COST: 477 $MM
VOLUMES: 13 MBOE/d
ACRES: 77000 Acres
COST: 1.4 $B
VOLUMES: 23 MBOE/d
ACRES: 480000 Acres
CALGARY, AB, Jan. 18, 2021 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to announce its 2021 exploration and development ("E&D") capital budget and associated production guidance.
Highlights
2021 Budget and Production Guidance
Vermilion's Board of Directors has approved an E&D capital budget of $300 million for 2021, representing a 17% reduction from 2020. The Company's primary focus for 2021 is to preserve liquidity and reduce debt while positioning the Company for long-term sustainability. As a result, the capital budget was designed to maximize returns and free cash flow while retaining the flexibility to adjust investment levels depending on commodity prices. In addition, following a review of our global asset base, we have reorganized the business and reporting lines into two core regions, North America and International.
The allocation of capital in 2021 will be more level-loaded compared to recent years. While the transition to a more level-loaded capital program will result in lower annual average production for 2021, it is expected to deliver better overall capital efficiencies and lead to a more manageable production base going forward. Approximately 31% of the 2021 capital budget will be invested during the first quarter, compared to approximately 65% in 2020. This $300 million capital program is expected to deliver annual average production of 83,000 to 85,000 boe/d.
During the budgeting process, close attention was paid to the return and payback period of each individual project under various commodity price scenarios. Given the strong recovery in European and North American natural gas prices throughout the second half of 2020 and into 2021, Vermilion's condensate-rich natural gas projects in Alberta and conventional natural gas projects in the Netherlands provided the strongest return profiles. As a result, the majority of the first half 2021 drilling program will be allocated to these projects. Vermilion's light oil projects in southeast Saskatchewan, Wyoming and France also screened well under strip pricing at the time of evaluation, however the size of the program has been scaled back in 2021. With the recent strengthening of global oil prices, the economics of these oil projects has further improved and additional drilling will be considered during the second half of the year if market conditions remain supportive.
Based on the midpoint of our production guidance and using the January 13, 2021 commodity strip, Vermilion expects to generate in excess of $200 million of free cash flow with a payout ratio less than 65%, including the impact from existing hedges. Our $300 million capital program is fully funded at a WTI oil price of approximately $37/bbl on an unhedged basis, assuming all other commodity prices held at the January 13, 2021 commodity strip. Vermilion has approximately 32% of its total production hedged for 2021, including 46% of its 2021 natural gas production and approximately 19% of its 2021 crude oil production, using a combination of swaps and three-way contracts (https://www.vermilionenergy.com/invest-with-us/hedging.cfm), while retaining significant leverage to further improvements in commodity prices.
Excess free cash flow net of reclamation and abandonment expenditures will be allocated to debt reduction as the Company remains committed to reducing its net debt(2)-to-fund flows from operations ("FFO") ratio to less than 1.5x over time. As our leverage profile improves, we will continue to review our long-term shareholder return policy to determine the appropriate time to reinstate a dividend and/or share buyback program.
North America
In North America, we plan to invest approximately $165 million of capital, representing a reduction of 37% compared to 2020. This program includes the drilling of ten (9.6 net) Mannville condensate-rich natural gas wells in Alberta, 25 (22.1 net) light oil wells in southeast Saskatchewan and four (3.9 net) light oil wells in Wyoming. In addition to these wells, the Company will also bring on production five (5.0 net) Mannville condensate-rich natural gas wells drilled in Q4 2020. Additional light oil wells in southeast Saskatchewan and Wyoming have been identified for drilling during the second half of 2021 if market conditions are supportive.
International
We plan to invest approximately $135 million across our international assets, representing an increase of 35% compared to 2020. The 2021 drilling program includes two (1.5 net) natural gas wells in the Netherlands, one (1.0 net) natural gas well in Croatia and one (1.0 net) oil well in Hungary. Capital activity in France and Germany will be primarily focused on well workovers to preserve production. Several oil wells have been identified in France for drilling during the second half of 2021 if market conditions are supportive. In addition, the previously drilled Burgmoor Z5 well (46% working interest) in Germany is expected to be brought on production in 2021. Capital activity in our remaining international jurisdictions will be focused primarily on maintenance activities, including a 1-week planned turnaround in Ireland and 3 weeks of planned maintenance downtime in Australia. As part of the review of our global asset base, we have decided to explore certain farm out opportunities to reduce exposure to higher risk assets in Europe as part of managing corporate risk and to refocus the organization.
E&D Capital Investment by Region | ||||||||||
Country | 2021 Budget* | 2020 Budget** | 2021 vs. 2020 | 2021 | 2020 | |||||
North America | 165 | 260 | (37) | % | 35.6 | 83.0 | ||||
International | 135 | 100 | 35 | % | 3.5 | 1.0 | ||||
Total E&D Capital Expenditures | 300 | 360 | (17) | % | 39.1 | 84.0 |
E&D Capital Investment by Category | ||||||
Category | 2021 Budget* | 2020 Budget** | 2021 vs. 2020 | |||
Drilling, completion, new well equipment and tie-in, workovers and recompletions | 185 | 280 | (34) | % | ||
Production equipment and facilities | 90 | 65 | 38 | % | ||
Seismic, land and other | 25 | 15 | 67 | % | ||
Total E&D Capital Expenditures | 300 | 360 | (17) | % |
*2021 Budget reflects foreign exchange assumptions of CAD/USD 1.27, CAD/EUR 1.56, and CAD/AUD 0.99. ** 2020 Budget figures based on midpoint of current guidance.
Conference Call and Webcast Details
Vermilion will discuss its 2021 capital budget and production guidance in a conference call and webcast presentation on Tuesday, January 19, 2021 at 7:00 AM MT (9:00 AM ET). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using conference ID 3783416 from January 19, 2021 at 10:00 AM MT to February 2, 2021 at 9:59 PM MT.
You may also access the webcast at https://produceredition.webcasts.com/starthere.jsp?ei=1420715&tp_key=6141ab16fe. The webcast link, along with conference call slides, will be available on Vermilion's website at https://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the conference call.
(1) | This document references free cash flow which is not specified, defined, or determined under International Financial Reporting Standards ("IFRS") and is therefore considered non-GAAP financial measures and may not be comparable to similar measures presented by other issuers. Free cash flow represents fund flows from operations in excess of capital expenditures and is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures. |
(2) | This document references net debt which does not have a standardized meaning and may not be comparable to similar measures presented by other issuers. Net debt is a measure of capital in accordance with IAS 1 "Presentation of Financial Statements". See Capital Disclosures in the notes to Vermilion's financial statements for further information. |
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing assets in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with returning capital to investors when economically warranted. Vermilion's operations are focused on the exploitation of light oil and liquids-rich natural gas conventional resource plays in North America and the exploration and development of conventional natural gas and oil opportunities in Europe and Australia.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares and are committed to delivering long-term value for all stakeholders. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures; Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2021 guidance; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; wells expected to be drilled in 2021; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt; statements regarding Vermilion's hedging program and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; acquisition and disposition plans and the timing thereof; operating and other expenses; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, AB, Jan. 18, 2021 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to announce its 2021 exploration and development ("E&D") capital budget and associated production guidance.
Highlights
2021 Budget and Production Guidance
Vermilion's Board of Directors has approved an E&D capital budget of $300 million for 2021, representing a 17% reduction from 2020. The Company's primary focus for 2021 is to preserve liquidity and reduce debt while positioning the Company for long-term sustainability. As a result, the capital budget was designed to maximize returns and free cash flow while retaining the flexibility to adjust investment levels depending on commodity prices. In addition, following a review of our global asset base, we have reorganized the business and reporting lines into two core regions, North America and International.
The allocation of capital in 2021 will be more level-loaded compared to recent years. While the transition to a more level-loaded capital program will result in lower annual average production for 2021, it is expected to deliver better overall capital efficiencies and lead to a more manageable production base going forward. Approximately 31% of the 2021 capital budget will be invested during the first quarter, compared to approximately 65% in 2020. This $300 million capital program is expected to deliver annual average production of 83,000 to 85,000 boe/d.
During the budgeting process, close attention was paid to the return and payback period of each individual project under various commodity price scenarios. Given the strong recovery in European and North American natural gas prices throughout the second half of 2020 and into 2021, Vermilion's condensate-rich natural gas projects in Alberta and conventional natural gas projects in the Netherlands provided the strongest return profiles. As a result, the majority of the first half 2021 drilling program will be allocated to these projects. Vermilion's light oil projects in southeast Saskatchewan, Wyoming and France also screened well under strip pricing at the time of evaluation, however the size of the program has been scaled back in 2021. With the recent strengthening of global oil prices, the economics of these oil projects has further improved and additional drilling will be considered during the second half of the year if market conditions remain supportive.
Based on the midpoint of our production guidance and using the January 13, 2021 commodity strip, Vermilion expects to generate in excess of $200 million of free cash flow with a payout ratio less than 65%, including the impact from existing hedges. Our $300 million capital program is fully funded at a WTI oil price of approximately $37/bbl on an unhedged basis, assuming all other commodity prices held at the January 13, 2021 commodity strip. Vermilion has approximately 32% of its total production hedged for 2021, including 46% of its 2021 natural gas production and approximately 19% of its 2021 crude oil production, using a combination of swaps and three-way contracts (https://www.vermilionenergy.com/invest-with-us/hedging.cfm), while retaining significant leverage to further improvements in commodity prices.
Excess free cash flow net of reclamation and abandonment expenditures will be allocated to debt reduction as the Company remains committed to reducing its net debt(2)-to-fund flows from operations ("FFO") ratio to less than 1.5x over time. As our leverage profile improves, we will continue to review our long-term shareholder return policy to determine the appropriate time to reinstate a dividend and/or share buyback program.
North America
In North America, we plan to invest approximately $165 million of capital, representing a reduction of 37% compared to 2020. This program includes the drilling of ten (9.6 net) Mannville condensate-rich natural gas wells in Alberta, 25 (22.1 net) light oil wells in southeast Saskatchewan and four (3.9 net) light oil wells in Wyoming. In addition to these wells, the Company will also bring on production five (5.0 net) Mannville condensate-rich natural gas wells drilled in Q4 2020. Additional light oil wells in southeast Saskatchewan and Wyoming have been identified for drilling during the second half of 2021 if market conditions are supportive.
International
We plan to invest approximately $135 million across our international assets, representing an increase of 35% compared to 2020. The 2021 drilling program includes two (1.5 net) natural gas wells in the Netherlands, one (1.0 net) natural gas well in Croatia and one (1.0 net) oil well in Hungary. Capital activity in France and Germany will be primarily focused on well workovers to preserve production. Several oil wells have been identified in France for drilling during the second half of 2021 if market conditions are supportive. In addition, the previously drilled Burgmoor Z5 well (46% working interest) in Germany is expected to be brought on production in 2021. Capital activity in our remaining international jurisdictions will be focused primarily on maintenance activities, including a 1-week planned turnaround in Ireland and 3 weeks of planned maintenance downtime in Australia. As part of the review of our global asset base, we have decided to explore certain farm out opportunities to reduce exposure to higher risk assets in Europe as part of managing corporate risk and to refocus the organization.
E&D Capital Investment by Region | ||||||||||
Country | 2021 Budget* | 2020 Budget** | 2021 vs. 2020 | 2021 | 2020 | |||||
North America | 165 | 260 | (37) | % | 35.6 | 83.0 | ||||
International | 135 | 100 | 35 | % | 3.5 | 1.0 | ||||
Total E&D Capital Expenditures | 300 | 360 | (17) | % | 39.1 | 84.0 |
E&D Capital Investment by Category | ||||||
Category | 2021 Budget* | 2020 Budget** | 2021 vs. 2020 | |||
Drilling, completion, new well equipment and tie-in, workovers and recompletions | 185 | 280 | (34) | % | ||
Production equipment and facilities | 90 | 65 | 38 | % | ||
Seismic, land and other | 25 | 15 | 67 | % | ||
Total E&D Capital Expenditures | 300 | 360 | (17) | % |
*2021 Budget reflects foreign exchange assumptions of CAD/USD 1.27, CAD/EUR 1.56, and CAD/AUD 0.99. ** 2020 Budget figures based on midpoint of current guidance.
Conference Call and Webcast Details
Vermilion will discuss its 2021 capital budget and production guidance in a conference call and webcast presentation on Tuesday, January 19, 2021 at 7:00 AM MT (9:00 AM ET). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using conference ID 3783416 from January 19, 2021 at 10:00 AM MT to February 2, 2021 at 9:59 PM MT.
You may also access the webcast at https://produceredition.webcasts.com/starthere.jsp?ei=1420715&tp_key=6141ab16fe. The webcast link, along with conference call slides, will be available on Vermilion's website at https://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the conference call.
(1) | This document references free cash flow which is not specified, defined, or determined under International Financial Reporting Standards ("IFRS") and is therefore considered non-GAAP financial measures and may not be comparable to similar measures presented by other issuers. Free cash flow represents fund flows from operations in excess of capital expenditures and is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures. |
(2) | This document references net debt which does not have a standardized meaning and may not be comparable to similar measures presented by other issuers. Net debt is a measure of capital in accordance with IAS 1 "Presentation of Financial Statements". See Capital Disclosures in the notes to Vermilion's financial statements for further information. |
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing assets in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with returning capital to investors when economically warranted. Vermilion's operations are focused on the exploitation of light oil and liquids-rich natural gas conventional resource plays in North America and the exploration and development of conventional natural gas and oil opportunities in Europe and Australia.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares and are committed to delivering long-term value for all stakeholders. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures; Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2021 guidance; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; wells expected to be drilled in 2021; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt; statements regarding Vermilion's hedging program and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; acquisition and disposition plans and the timing thereof; operating and other expenses; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, AB, Nov. 17, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX: VET) (NYSE: VET) announces changes to its senior leadership team. Mr. Michael Kaluza has stepped down as Executive Vice President and Chief Operating Officer ("COO"), effective immediately. We would like to thank Mr. Kaluza for his many contributions to Vermilion over the past seven years.
Mr. Dion Hatcher has been appointed to the newly created position of Vice President, North America. Mr. Hatcher has been with Vermilion since 2006 and most recently held the position of Vice President of the Canadian Business Unit, a position he has held since 2016. In his new role, Mr. Hatcher will be responsible for all of Vermilion's operations in Canada and the United States.
Mr. Darcy Kerwin has been appointed to the newly created position of Vice President, International & HSE where he will oversee Vermilion's Health, Safety and Environment efforts and be responsible for all of Vermilion's international operations. Mr. Kerwin has been with Vermilion since 2005 and has worked in our Canada, France, Australia and Ireland business units and most recently in the Calgary Head Office as Vice President, Strategic Planning.
We would like to congratulate Mr. Hatcher and Mr. Kerwin on their new roles and look forward to their ongoing contributions to Vermilion. These promotions are in alignment with Vermilion's objectives of promoting from within to develop internal succession candidates and maintaining continuity in our business while retaining our focus on efficient, effective operations.
In lieu of filling the role of COO we will rely on Mr. Hatcher and Mr. Kerwin to jointly fulfill the duties and continue to emphasize our focus on cost-control and safe, efficient, profitable operations.
As previously announced, Mr. Hatcher and Mr. Kerwin are also members of Vermilion's Executive Committee. The Executive Committee is proving to be very successful in managing the company by utilizing the collective knowledge of the eight Committee members to collaborate on strategic decisions for the Company.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with returning capital to investors when economically warranted. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares and are committed to delivering long-term value for all stakeholders. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content to download multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-senior-leadership-changes-301174077.html
SOURCE Vermilion Energy Inc.
CALGARY, AB, Nov. 9, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX: VET) (NYSE: VET) is pleased to report operating and condensed financial results for the three and nine months ended September 30, 2020 and the release of its 2020 Corporate Sustainability Report.
The unaudited interim financial statements and management discussion and analysis for the three and nine months ended September 30, 2020 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
($M except as indicated) | Q3 2020 | Q2 2020 | Q3 2019 | YTD 2020 | YTD 2019 | |
Financial | ||||||
Petroleum and natural gas sales | 282,020 | 193,013 | 391,935 | 803,347 | 1,301,061 | |
Fund flows from operations | 114,776 | 81,852 | 216,153 | 366,853 | 692,463 | |
Fund flows from operations ($/basic share) (1) | 0.73 | 0.52 | 1.39 | 2.33 | 4.49 | |
Fund flows from operations ($/diluted share) (1) | 0.73 | 0.52 | 1.39 | 2.33 | 4.45 | |
Net (loss) earnings | (69,926) | (71,290) | (10,229) | (1,459,720) | 31,322 | |
Net (loss) earnings ($/basic share) | (0.44) | (0.45) | (0.07) | (9.26) | 0.20 | |
Capital expenditures | 31,330 | 42,274 | 127,879 | 307,308 | 422,539 | |
Acquisitions | 6,720 | 2,932 | 4,657 | 20,989 | 29,307 | |
Asset retirement obligations settled | 2,305 | 970 | 3,586 | 7,007 | 12,090 | |
Cash dividends ($/share) | — | — | 0.690 | 0.575 | 2.070 | |
Dividends declared | — | — | 107,176 | 90,067 | 319,609 | |
% of fund flows from operations | —% | —% | 50% | 25% | 46% | |
Net dividends (1) | — | — | 98,316 | 81,790 | 294,872 | |
% of fund flows from operations | —% | —% | 45% | 22% | 43% | |
Payout (1) | 33,635 | 42,612 | 229,781 | 396,105 | 729,501 | |
% of fund flows from operations | 29% | 52% | 106% | 108% | 105% | |
Net debt | 2,136,219 | 2,161,442 | 2,001,870 | 2,136,219 | 2,001,870 | |
Net debt to four quarter trailing fund flows from operations | 3.67 | 3.16 | 2.19 | 3.67 | 2.19 | |
Operational | ||||||
Production | ||||||
Crude oil and condensate (bbls/d) | 43,240 | 45,041 | 47,242 | 44,383 | 48,455 | |
NGLs (bbls/d) | 9,509 | 9,588 | 7,772 | 9,041 | 7,925 | |
Natural gas (mmcf/d) | 256.34 | 274.42 | 253.36 | 265.39 | 268.88 | |
Total (boe/d) | 95,471 | 100,366 | 97,239 | 97,656 | 101,193 | |
Average realized prices | ||||||
Crude oil and condensate ($/bbl) | 52.77 | 34.90 | 73.45 | 49.03 | 75.38 | |
NGLs ($/bbl) | 15.04 | 8.94 | 6.14 | 11.09 | 13.25 | |
Natural gas ($/mcf) | 2.34 | 1.85 | 2.43 | 2.37 | 3.56 | |
Production mix (% of production) | ||||||
% priced with reference to WTI | 40% | 41% | 39% | 40% | 38% | |
% priced with reference to Dated Brent | 17% | 14% | 19% | 16% | 18% | |
% priced with reference to AECO | 28% | 29% | 26% | 28% | 26% | |
% priced with reference to TTF and NBP | 15% | 16% | 16% | 16% | 18% | |
Netbacks ($/boe) | ||||||
Operating netback (1) | 16.29 | 12.49 | 28.22 | 16.94 | 29.80 | |
Fund flows from operations netback | 12.95 | 9.08 | 23.73 | 13.63 | 24.89 | |
Operating expenses | 10.21 | 11.00 | 11.55 | 11.55 | 11.85 | |
General and administration expenses | 1.35 | 1.88 | 1.50 | 1.57 | 1.53 | |
Average reference prices | ||||||
WTI (US $/bbl) | 40.93 | 27.85 | 56.45 | 38.32 | 57.06 | |
Edmonton Sweet index (US $/bbl) | 37.42 | 21.71 | 51.79 | 32.57 | 52.34 | |
Saskatchewan LSB index (US $/bbl) | 37.57 | 21.60 | 52.01 | 32.53 | 52.81 | |
Dated Brent (US $/bbl) | 43.00 | 29.20 | 61.94 | 40.82 | 64.65 | |
AECO ($/mcf) | 2.24 | 1.99 | 1.06 | 2.09 | 1.64 | |
NBP ($/mcf) | 3.67 | 2.26 | 4.50 | 3.43 | 6.08 | |
TTF ($/mcf) | 3.51 | 2.39 | 4.40 | 3.38 | 6.08 | |
Average foreign currency exchange rates | ||||||
CDN $/US $ | 1.33 | 1.39 | 1.32 | 1.35 | 1.33 | |
CDN $/Euro | 1.56 | 1.53 | 1.47 | 1.52 | 1.49 | |
Share information ('000s) | ||||||
Shares outstanding - basic | 158,308 | 158,307 | 155,505 | 158,308 | 155,505 | |
Shares outstanding - diluted (1) | 163,800 | 164,090 | 159,260 | 163,800 | 159,260 | |
Weighted average shares outstanding - basic | 158,307 | 158,189 | 155,254 | 157,688 | 154,326 | |
Weighted average shares outstanding - diluted (1) | 158,307 | 158,189 | 155,421 | 157,688 | 155,673 |
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Message to Shareholders
Commodity prices during the third quarter partially recovered from the lows experienced in the prior quarter. In particular, global oil benchmarks and European natural gas benchmarks, our two most dominant products from a revenue generating perspective, increased approximately 50% relative to average prices in the second quarter. While the operating environment remains challenging even at these higher price levels, the improvement in commodity prices helped drive a 40% sequential increase in our Q3 2020 FFO to $115 million ($0.73/basic share(1)). As a result of the increase in FFO and limited capital investment, we generated $83 million of free cash flow during the third quarter and paid down $55 million on our credit facility.
During the third quarter, we resumed all operational activity that was stopped or deferred during the COVID-19 confinement period, and have slowly started returning staff to the office while keeping a close eye on further COVID-19 developments. Capital expenditures in Q3 2020 decreased 26% from the prior quarter to $31 million, and was focused primarily on maintenance related activities with no new wells drilled or tied-in during the quarter. This reduced level of activity was partly due to the design of our front-end weighted capital program and the budget cuts announced earlier this year in response to the commodity price collapse, and was also influenced by our focus on debt reduction.
Production in Q3 2020 declined 5% from the prior quarter to an average of 95,471 boe/d primarily due to natural decline, plant turnarounds and limited capital investment during the quarter, partially offset by increased production in France following the restart of the Grandpuits refinery. As a result of the front-end weighted capital program we executed this year, all of our new production was added during the first half of the year resulting in a declining production base for most business units through the second half of the year. We also made the economic decision to defer the startup of the Weststellingwerf (0.5 net) well until 2021 to take advantage of higher European gas prices. Although this will have a modestly negative impact on production for the second half of 2020, the decision will ultimately enhance the overall profitability and cash flow for the company. Incorporating this production deferral and taking into account our current production estimates, we have tightened our 2020 annual production guidance to a range of 94,000 to 96,000 boe/d.
We continue to work through various scenarios for our 2021 capital budget and expect to release more information in the new year. We are taking a very careful and thoughtful approach in preparing our capital budget for 2021, paying close attention to forward commodity prices and the profitability of each individual project, while also seeking the appropriate balance between production preservation, debt reduction and capital flexibility. As we have previously stated, our number one financial priority at this time is debt reduction and positioning the company for future success, and we are willing to sacrifice top-line production growth in the near-term to achieve this objective. We continue to focus on opportunities to improve our cost structure and capital efficiencies, and to that end we will be targeting a more level-loaded capital program in 2021 which should result in a more efficient allocation of capital while smoothing the production profile throughout the year.
The third quarter of 2020 was the first full quarter with the formal Executive Committee in place, and this structure is proving to be very successful in managing the company. By utilizing the collective knowledge and skillset of the Committee members, recently increased from six to nine members, we have been making steady progress in evaluating the business and navigating the company through these challenging times. While we anticipate continued volatility through the balance of 2020 and into 2021 as uncertainty persists around the duration of the COVID-19 pandemic, we have taken the necessary steps to position Vermilion for this environment. Earlier this year we reduced annual cash outflows by over $550 million and negotiated an extension to our $2.1 billion revolving credit facility to May 2024. We are also constructing our 2021 budget in a way that will ensure we retain the maximum amount of flexibility while only investing in the highest return projects. We remain optimistic about the longer-term prospects for Vermilion and our ability to generate free cash flow with the aim of returning capital to investors and maximizing value creation for all of our stakeholders over the long-term.
Q3 2020 Operations Review
North America
Production from our North American business units averaged 64,986 boe/d in Q3 2020, a decrease of 7% from the prior quarter primarily due to natural decline and limited capital investment during the quarter. As a result of the front-end-weighted capital program we executed this year and the reduced capital program announced in March in response to the COVID-19 pandemic and resulting commodity price collapse, capital activity during the third quarter was focused on maintenance activities with no wells drilled or tied-in during the quarter. During the fourth quarter we reinitiated moderate investment into new well activity with two rigs in Alberta targeting liquids rich gas.
Europe
Production from our European business units averaged 25,935 in Q3 2020, an increase of 3% from the prior quarter primarily due to increased production from the Paris basin in France following the restart of the Grandpuits refinery in mid-June. Production in France was also supported by the restart of workover activities in June following the COVID-19 confinement period in France. At the end of September, Total SE ("Total") announced plans to convert its Grandpuits refinery into a zero-crude platform for biofuels and bioplastics and its intention to discontinue crude oil refining at the platform in the first quarter of 2021. The Grandpuits refinery has been in operation for over 50 years and currently processes all of our Paris Basin oil production, approximately 5,000 bbl/d. Our recently negotiated long-term agreement with Total has provisions to deal with the closure of the Grandpuits refinery, whereby Total will take receipt of our crude at one of their other refineries in France. We are currently working on securing other transportation and delivery options to ensure a smooth transition. We estimate this will increase our transportation costs by approximately $20 million on an annualized basis, however we will continue to evaluate longer-term marketing options for this crude.
Elsewhere in Europe, our employees and contractors slowly started returning to the office following the COVID-19 confinements, however capital activity was limited due to the capital reductions announced earlier in the year. In the Netherlands, we deferred the startup of the Weststellingwerf (0.5 net) well until 2021 to take advantage of higher European gas prices during the winter months. In Ireland, a 3-week turnaround scheduled for September was scaled back to approximately 1-week due to the unavailability of a key contractor, however we managed to complete 50% of the scope work and plan to reschedule the remaining work next year. A third-party facility turnaround in Germany and well maintenance in Hungary further offset some of the production gains in France. We continue to advance future drilling projects in the Netherlands and Central and Eastern Europe in preparation for our 2021 drilling campaign.
Australia
In Australia, production averaged 4,549 bbl/d in Q3 2020, a 14% decrease from the prior quarter primarily due to natural decline and an unplanned 4-day shutdown to clean out one of the separator vessels. We sold 445,000 barrels of Wandoo crude during the third quarter and realized an average price premium of C$11 above Dated Brent. This premium remains well above the premium realized in prior years but is less than the premium realized earlier in the year due to weaker refinery margins as a result of the global economic slowdown related to COVID-19. We have a two-week maintenance turnaround scheduled for the Wandoo platform in Q4 2020 which will result in lower production volumes during the fourth quarter.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows. In aggregate, as of October 27, 2020, we have 47% of our expected net-of-royalty production hedged for the fourth quarter of 2020. With respect to individual commodity products, we have hedged 90% of our European natural gas production, 17% of our oil production, and 57% of our North American natural gas volumes for the fourth quarter of 2020, respectively. Please refer to the Hedging section of our website under Invest With Us for further details.
Sustainability
In early November, Vermilion released its 2020 Corporate Sustainability Report, marking our 7th year of ESG reporting. The 2020 report highlights our ongoing focus on reducing emissions within our operations, along with a content index that includes recommendations from the Task Force on Climate-related Financial Disclosures and the Sustainability Accounting Standards Board. We are committed to providing safe, affordable and reliable energy for our stakeholders and we believe that integrating sustainability principles into our business will increase shareholder returns, enhance our business development opportunities and reduce long-term risks to our business. The report can be found on our website using the following link.
http://sustainability.vermilionenergy.com/
Organizational Update
During the third quarter, we expanded our Executive Committee from six to nine members with the additions of Gerard Schut, Vice President European Operations, Darcy Kerwin, Vice President Strategic Planning and Dion Hatcher, Vice President Canada Business Unit. This expansion provides deeper coverage of the operations of the company, while continuing to utilize expertise from the corporate functional teams. Each member of the Executive Committee brings a unique skill set and knowledge base which contributes to the collective decision making process of the Committee.
(Signed "Lorenzo Donadeo") | (Signed "Curtis Hicks") | |
Lorenzo Donadeo | Curtis Hicks | |
Executive Chairman | President | |
November 6, 2020 | November 6, 2020 |
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Management's Discussion and Analysis and Consolidated Financial Statements
To view Vermilion's Management's Discussion and Analysis and Interim Condensed Consolidated Financial Statements for the periods ended September 30, 2020 and 2019, please refer to SEDAR (www.sedar.com) or Vermilion's website at https://www.vermilionenergy.com/invest-with-us/reports-filings.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with returning capital to investors when economically warranted. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares and are committed to delivering long-term value for all stakeholders. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures; Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2020 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion's future project inventory, and the wells expected to be drilled in 2020; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt, including its ability to redeem senior unsecured notes prior to maturity; statements regarding Vermilion's hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, AB, Sept. 24, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX: VET) (NYSE: VET) has prepared the following response to the recent news from Total SA ("Total") regarding their plans to convert the Grandpuits refinery in France to biofuels and bioplastics.
Earlier today, Total announced plans to convert its Grandpuits refinery into a zero-crude platform for biofuels and bioplastics and will discontinue crude oil refining at the platform in the first quarter of 2021. The Grandpuits refinery has been in operation for over 50 years and currently processes all of our Paris Basin oil production, currently estimated at approximately 5,000 bbl/d. We were aware that Total had been evaluating the long-term viability of its Grandpuits refinery for the past several years, and as such we have written provisions in our existing contract to deal with the potential closure of the Grandpuits refinery. As defined in our recently negotiated long-term agreement, Total will take receipt of our crude at one of their other refineries in France following the closure of the Grandpuits refinery.
In anticipation of the potential closure of the Grandpuits refinery, our France business unit has been working on securing other transportation and delivery options to ensure a smooth transition. We estimate this will increase our transportation costs by approximately $20 million on an annualized basis, however we will continue to evaluate longer-term marketing options for this crude.
Vermilion has been operating in France for over 20 years and we remain committed to our France business unit which we believe offers significant long-term value potential.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with returning capital to investors when economically warranted. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares and are committed to delivering long-term value for all stakeholders. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: future transportation and delivery options for Vermilion's crude oil production in France, expectations for future transportation costs for our Paris Basin production, and future longer-term marketing options for our French crude oil production.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in France; the ability of Vermilion to market crude oil successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, AB, July 27, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three and six months ended June 30, 2020.
The unaudited interim financial statements and management discussion and analysis for the three and six months ended June 30, 2020 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
(2) | The use by Vermilion Energy Inc of any MSCI ESG Research LLC or its affiliates ("MSCI") data, and the use of MSCI logos, trademarks, service marks or index names herein, do not constitute a sponsorship, endorsement, recommendation, or promotion of Vermilion by MSCI. MSCI services and data are the property of MSCI or its information providers, and are provided 'as-is' and without warranty. MSCI names and logos are trademarks or service marks of MSCI. |
($M except as indicated) | Q2 2020 | Q1 2020 | Q2 2019 | YTD 2020 | YTD 2019 | |||||
Financial | ||||||||||
Petroleum and natural gas sales | 193,013 | 328,314 | 428,043 | 521,327 | 909,126 | |||||
Fund flows from operations | 81,852 | 170,225 | 222,738 | 252,077 | 476,310 | |||||
Fund flows from operations ($/basic share) (1) | 0.52 | 1.09 | 1.44 | 1.60 | 3.10 | |||||
Fund flows from operations ($/diluted share) (1) | 0.52 | 1.09 | 1.42 | 1.60 | 3.07 | |||||
Net earnings (loss) | (71,290) | (1,318,504) | 2,004 | (1,389,794) | 41,551 | |||||
Net earnings (loss) ($/basic share) | (0.45) | (8.42) | 0.01 | (8.83) | 0.27 | |||||
Capital expenditures | 42,274 | 233,704 | 92,607 | 275,978 | 294,660 | |||||
Acquisitions | 2,932 | 11,337 | 8,623 | 14,269 | 24,650 | |||||
Asset retirement obligations settled | 970 | 3,732 | 4,907 | 4,702 | 8,504 | |||||
Cash dividends ($/share) | — | 0.575 | 0.690 | 0.575 | 1.380 | |||||
Dividends declared | — | 90,067 | 106,884 | 90,067 | 212,433 | |||||
% of fund flows from operations | —% | 53% | 48% | 36% | 45% | |||||
Net dividends (1) | — | 82,422 | 98,111 | 81,790 | 196,556 | |||||
% of fund flows from operations | —% | 48% | 44% | 32% | 41% | |||||
Payout (1) | 42,612 | 319,858 | 195,625 | 362,470 | 499,720 | |||||
% of fund flows from operations | 52% | 188% | 88% | 144% | 105% | |||||
Net debt | 2,161,442 | 2,155,623 | 1,950,509 | 2,161,442 | 1,950,509 | |||||
Net debt to four quarter trailing fund flows from operations | 3.16 | 2.61 | 1.91 | 3.16 | 1.91 | |||||
Operational | ||||||||||
Production | ||||||||||
Crude oil and condensate (bbls/d) | 45,041 | 44,881 | 48,964 | 44,961 | 49,072 | |||||
NGLs (bbls/d) | 9,588 | 8,022 | 8,107 | 8,805 | 8,002 | |||||
Natural gas (mmcf/d) | 274.42 | 265.51 | 275.60 | 269.96 | 276.77 | |||||
Total (boe/d) | 100,366 | 97,154 | 103,003 | 98,760 | 103,203 | |||||
Average realized prices | ||||||||||
Crude oil and condensate ($/bbl) | 34.90 | 58.66 | 79.46 | 47.20 | 76.36 | |||||
NGLs ($/bbl) | 8.94 | 8.92 | 11.25 | 8.94 | 16.76 | |||||
Natural gas ($/mcf) | 1.85 | 2.94 | 3.09 | 2.39 | 4.09 | |||||
Production mix (% of production) | ||||||||||
% priced with reference to WTI | 41% | 39% | 38% | 40% | 37% | |||||
% priced with reference to Dated Brent | 14% | 17% | 18% | 16% | 19% | |||||
% priced with reference to AECO | 29% | 27% | 26% | 28% | 26% | |||||
% priced with reference to TTF and NBP | 16% | 17% | 18% | 16% | 18% | |||||
Netbacks ($/boe) | ||||||||||
Operating netback (1) | 12.49 | 22.02 | 29.62 | 17.25 | 30.57 | |||||
Fund flows from operations netback | 9.08 | 18.85 | 24.15 | 13.96 | 25.46 | |||||
Operating expenses | 11.00 | 13.41 | 11.04 | 12.21 | 11.99 | |||||
General and administration expenses | 1.88 | 1.47 | 1.70 | 1.67 | 1.54 | |||||
Average reference prices | ||||||||||
WTI (US $/bbl) | 27.85 | 46.17 | 59.81 | 37.01 | 57.36 | |||||
Edmonton Sweet index (US $/bbl) | 21.71 | 38.59 | 55.19 | 30.15 | 52.62 | |||||
Saskatchewan LSB index (US $/bbl) | 21.60 | 38.41 | 55.54 | 30.01 | 53.19 | |||||
Dated Brent (US $/bbl) | 29.20 | 50.26 | 68.82 | 39.73 | 66.01 | |||||
AECO ($/mcf) | 1.99 | 2.03 | 1.03 | 2.01 | 1.83 | |||||
NBP ($/mcf) | 2.26 | 4.32 | 5.44 | 3.31 | 6.89 | |||||
TTF ($/mcf) | 2.39 | 4.23 | 5.75 | 3.32 | 6.94 | |||||
Average foreign currency exchange rates | ||||||||||
CDN $/US $ | 1.39 | 1.34 | 1.34 | 1.37 | 1.33 | |||||
CDN $/Euro | 1.53 | 1.48 | 1.50 | 1.50 | 1.51 | |||||
Share information ('000s) | ||||||||||
Shares outstanding - basic | 158,307 | 157,020 | 155,032 | 158,307 | 155,032 | |||||
Shares outstanding - diluted (1) | 164,090 | 160,425 | 158,633 | 164,090 | 158,633 | |||||
Weighted average shares outstanding - basic | 158,189 | 156,562 | 154,795 | 157,375 | 153,855 | |||||
Weighted average shares outstanding - diluted (1) | 158,189 | 156,562 | 156,844 | 157,375 | 155,335 |
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Message to Shareholders
The second quarter of 2020 was an extremely challenging period for the oil and gas sector. Demand destruction caused by the COVID-19 pandemic resulted in unprecedented negative oil prices for the WTI benchmark as global inventories swelled. Despite these challenges, we were able to manage our business effectively through this cycle, with relatively little operational impact from COVID-19. We successfully adapted our work procedures to ensure operational safety and business continuity in all of our operating regions, and to-date we have not had any confirmed cases of COVID-19 amongst our staff, with only minor production impacts related to the pandemic. We believe this is a reflection of the commitment to Vermilion of our skilled and dedicated staff.
We delivered strong operational results in Q2 2020. Production averaged 100,366 boe/d representing a 3% increase from the prior quarter. Most of this increase came from our North American business units where we benefited from new production coming online following an active and successful Q1 2020 drilling program. Both our Canadian and United States business units achieved record quarterly production during Q2 2020. This growth in North American production volumes more than offset approximately 3,000 bbl/d of curtailed oil production in France that was temporarily shut-in due to a local refinery being offline during the COVID-19 confinement period. The refinery has recently restarted and we are in the process of restoring our production in France.
As a result of the lower commodity prices during Q2 2020, FFO decreased 52% quarter-over-quarter to $82 million ($0.52/basic share(1)). However, with minimal capital investment of $42 million, we generated approximately $40 million of free cash flow and achieved a total payout ratio of 52%, including reclamation and abandonment spending. We ended the second quarter with net debt of $2.2 billion and approximately $350 million of liquidity on our covenant-based credit facility. Our facility is termed out until May 2024 and we remain in compliance on all debt covenants. Capital activity for the balance of the year will be minimal and focused predominantly on maintenance activity.
During the quarter, we also made several leadership changes in an effort to realign the Company with Vermilion's long-standing core business principles, which are based on a conservative, long-term focus on balance sheet strength and capital discipline to generate strong returns. The five core principles include: maintaining a strong balance sheet with low leverage; managing a total payout ratio of less than 100%; consistently delivering results that meet or exceed expectations, protecting equity to minimize dilution; and maintaining a strong corporate culture. These principles were implemented when Vermilion started paying a distribution as an energy trust in 2003 and have served the Company well over its history.
Along with the change in leadership we have also re-established an Executive Committee, which is a management structure that was successfully utilized by Vermilion in the past. This management structure has proved to be a highly collaborative decision-making model that draws upon the collective knowledge, experience, business acumen and skills of the senior management team.
As we move forward, our first priority will be to ensure the continued health and safety of our employees and business continuity as we navigate through COVID-19. With the cost reductions we have made to-date, our business is free cash flow positive in the current commodity price environment. Our top financial priority at this time is debt reduction with an ultimate target of achieving a debt-to-cash flow ratio of less than 1.5x. Achieving this target will not happen overnight, and we will take a long-term, patient approach to managing the business and improving the balance sheet.
We recently kicked-off our 2021 capital budget process with this long-term view in the fore. Our plans for the rest of this year and next will be guided by our core business principles, focusing on free cash flow generation and debt reduction rather than top-line production growth. In due course, we will review our shareholder return policy to determine the appropriate time to reinstate a dividend and/or buyback shares. We are proud to have delivered over $40 per share in dividends to our shareholders over the past 17 years and we believe returning capital to shareholders is a key component in generating long-term shareholder returns. Although we do not expect the road ahead to be without challenges, we believe our renewed focus on these core business principles will help guide Vermilion through these difficult times and position the Company for long-term value creation.
Q2 2020 Operations Review
Europe
Production from our European business units averaged 25,173 boe/d in Q2 2020, a decrease of 13% or approximately 3,700 boe/d from the prior quarter. The decrease was primarily due to the curtailment of approximately 3,000 bbl/d of oil production in France due to the temporary shutdown of the Total-operated Grandpuits refinery during the COVID-19 confinement period. Natural decline and minor unplanned downtime in Ireland accounted for the balance of the decrease.
The Grandpuits refinery resumed operations in mid-June and we are in the process of restoring our curtailed production in France, along with resuming our 2020 workover program which was put on hold during the COVID-19 confinement period. In the Netherlands, we recently received the final production permit for the Weststellingwerf (0.5 net) well and expect to bring this well on production during the second half of 2020. During the second quarter we deferred a planned turnaround in Ireland due to the COVID-19 restrictions and now plan to complete this turnaround in Q3 2020, which will result in the Corrib project being offline for approximately three weeks.
North America
Production from our North American business units averaged 69,895 boe/d in Q2 2020, an increase of 9% or approximately 5,700 boe/d from the prior quarter. The increase was due to new well contributions from our active Q1 2020 drilling programs in Canada and the United States. In Canada, we brought five (5.0 net) wells on production in Alberta and eleven (5.5 net) wells on production in Saskatchewan during the second quarter. In the United States, we completed and brought on production the remaining six (6.0 net) wells of our nine (8.9 net) well program. Despite highly volatile North American oil pricing in Q2 2020, we did not experience any material shut-ins of uneconomic production.
During the quarter, we focused on various cost-saving initiatives across the Canadian and United States business units and have identified many capital, operating and general and administrative efficiencies to-date. In the United States, we were able to reduce completion costs of the final six wells by approximately 15% from the first three (2.9 net) wells due to increased operational efficiencies, as well as the utilization of multi-well pads. We have completed our North American drilling program for 2020 and will focus on maintenance activities for the balance of the year. As a result, we expect production from both business units to decline over the second half of the year as no new well drilling activity is planned.
Australia
In Australia, production averaged 5,299 bbl/d in Q2 2020, an increase of 31% quarter-over-quarter as production was fully restored on two wells that were temporarily offline in the prior quarter to install electric submersible pumps. Production also benefited from the absence of cyclone activity in the quarter, which caused several days of unplanned downtime in Q1 2020. We continued to realize strong pricing for our Wandoo crude due to its low sulphur content, averaging a premium of C$21 per barrel above Dated Brent during Q2 2020. The demand for this blend of crude has increased under the new IMO 2020 regulations, which require marine vessels to either install sulphur scrubbers or run low sulphur fuel oil.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows. In aggregate, as of July 24, 2020, we have 50% of our expected net-of-royalty production hedged for the second half of 2020. With respect to individual commodity products, we have hedged 87% of our European natural gas production, 27% of our oil production, and 69% of our North American natural gas volumes for the second half of 2020, respectively. Please refer to the Hedging section of our website under Invest With Us for further details.
Sustainability
In June 2020, Vermilion received a rating of "AA" on a scale of AAA (leader) to CCC (laggard) in the MSCI ESG Ratings(2) assessment, which reflects exposure to industry-specific ESG risks and the ability to manage those risks. MSCI ESG Research provides in-depth research, ratings and analysis of the ESG-related business practices of thousands of companies worldwide. This consistent rating from 2019 continues to reflect Vermilion's commitment to improving company ESG performance and enhanced disclosure on topics relevant to MSCI's detailed assessment process.
Organizational Update
On May 25, 2020, Vermilion announced that Anthony Marino stepped down as President and Chief Executive Officer and as a director of the Company, effective immediately. In conjunction with Mr. Marino's departure, the Board also announced the appointments of Lorenzo Donadeo as Executive Chairman and the Curtis Hicks as President.
Mr. Donadeo has 39 years of experience in the oil and gas industry. He was a co-founder of Vermilion in 1994 and has served as Chairman of the Board since March 1, 2016. From 2014 to 2016, Mr. Donadeo served as the Chief Executive Officer. From 2003 to 2014, he served as President and Chief Executive Officer and from 1996 to 2003 he served as Vermilion's Executive Vice President and Chief Operating Officer. Mr. Donadeo has a Bachelor of Science degree in Mechanical Engineering (with distinction) from the University of Alberta.
Mr. Hicks has 37 years of experience in the oil and gas industry. Most recently, he was Executive Vice-President and Chief Financial Officer of Vermilion from 2003 to 2018 and was a key contributor to Vermilion's success and culture during his tenure. Mr. Hicks is a Chartered Professional Accountant and has a Bachelor of Commerce degree (with distinction) from the University of Saskatchewan.
Vermilion has a philosophy of staff development and internal promotion. In line with this approach, we are pleased to announce that Darcy Kerwin, currently Managing Director for our Ireland Business Unit (IBU), will be returning to Canada to take the role of Vice President, Strategic Planning, effective September 1, 2020. Mr. Kerwin has over 23 years of industry experience, with a focus on engineering and production operations in North America, West Africa, Australia, and Europe. Prior to joining Vermilion, Mr. Kerwin held a variety of engineering and project management roles with Chevron in Canada, Houston and Nigeria. In 2005, Mr. Kerwin joined Vermilion as the Interim General Manager of our Australia Business Unit (ABU). After his assignment in Australia, he spent five years in the France Business Unit (FBU), leading facilities engineering and asset integrity functions before returning to Canada in 2011 as the Facilities Engineering Manager. Mr. Kerwin returned to France in March 2014 as the Managing Director, FBU and for the last two and a half years, he has been successfully leading the IBU as Managing Director.
Ryan Carty, currently Operations Manager, Australia Business Unit, has been promoted to the position of Managing Director, IBU, also effective September 1, 2020. Mr. Carty has over 18 years of engineering and operations experience, working in positions with increasing leadership responsibility at BHP, ENI, Chevron and Origin Energy, prior to joining Vermilion in 2014. As Operations Manager in Australia, Mr. Carty has been responsible for the management of the Wandoo operation, including production, health, safety and environment, and overseeing all aspects of capital and operating activity. We look forward to Mr. Carty's leadership in further advancing Vermilion's track record as a community partner and responsible operator of essential domestic natural gas production in Ireland.
(Signed "Lorenzo Donadeo")
Lorenzo Donadeo
Executive Chairman
July 24, 2020
(Signed "Curtis Hicks")
Curtis Hicks
President
July 24, 2020
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
(2) | The use by Vermilion Energy Inc of any MSCI ESG Research LLC or its affiliates ("MSCI") data, and the use of MSCI logos, trademarks, service marks or index names herein, do not constitute a sponsorship, endorsement, recommendation, or promotion of Vermilion by MSCI. MSCI services and data are the property of MSCI or its information providers, and are provided 'as-is' and without warranty. MSCI names and logos are trademarks or service marks of MSCI. |
Management's Discussion and Analysis and Consolidated Financial Statements
To view Vermilion's Management's Discussion and Analysis and Interim Condensed Consolidated Financial Statements for the periods ended June 30, 2020 and 2019, please refer to SEDAR (www.sedar.com) or Vermilion's website at https://www.vermilionenergy.com/invest-with-us/reports-filings.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with returning capital to investors when economically warranted. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares and are committed to delivering long-term value for all stakeholders. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures; Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2020 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion's future project inventory, and the wells expected to be drilled in 2020; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt, including its ability to redeem senior unsecured notes prior to maturity; statements regarding Vermilion's hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, May 25, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) announces that Anthony Marino has stepped down as President and Chief Executive Officer and as a director of the Company, effective immediately. Mr. Marino made many contributions to Vermilion during his eight-year tenure with the Company, including various improvements to the cost structure and associated capital efficiencies. These core competencies will continue to serve the Company well moving into the future. Vermilion's Board of Directors (the "Board") would like to thank Mr. Marino for his contributions to the Company.
The Board is pleased to announce that Lorenzo Donadeo has been appointed Executive Chairman. Mr. Donadeo has 39 years of experience in the oil and gas industry. He was a co-founder of Vermilion in 1994 and has served as Chairman of the Board since March 1, 2016. From 2014 to 2016, Mr. Donadeo served as the Chief Executive Officer. From 2003 to 2014, he served as President and Chief Executive Officer and from 1996 to 2003 he served as Vermilion's Executive Vice President and Chief Operating Officer. Mr. Donadeo has a Bachelor of Science degree in Mechanical Engineering (with distinction) from the University of Alberta.
The Board is also pleased to announce that Curtis Hicks is rejoining the Company and has been appointed President. Mr. Hicks has 40 years of experience in the oil and gas industry. Most recently, he was Executive Vice-President and Chief Financial Officer of Vermilion from 2003 to 2018. During his time at Vermilion, the Company was recognized as one of the premier Canadian oil and gas companies with a strong financial structure backstopping disciplined capital allocation. He was a key contributor to Vermilion's success and culture during his tenure. Mr. Hicks is a Chartered Professional Accountant and has a Bachelor of Commerce degree (with distinction) from the University of Saskatchewan.
In lieu of filling the role of Chief Executive Officer, Vermilion has created an Executive Committee consisting of a minimum of five senior executives from within the Company. It will include the Executive Chairman, President, Chief Financial Officer, Chief Operating Officer, Executive Vice-President People and Culture and Vice-President of Business Development. The Executive Committee structure was successfully utilized by Vermilion in the past and has been formally re-established. It will be used by the organization to review and approve key organizational, financial, operational and strategic decisions for the Company. This leadership structure has proven to be a highly collaborative decision-making model that draws upon the collective knowledge, experience, business acumen and skills of the senior management team.
Larry MacDonald will continue as lead director.
Mr. Donadeo and Mr. Hicks know the Company well. They know the assets, the people and the corporate culture and have a positive track record of long-term value creation at Vermilion.
Stated Lorenzo Donadeo, "In these challenging times, Vermilion will redouble its focus on its core business principles that have served it well over its successful 26-year history. These principles are based on a conservative, long-term focus on balance sheet strength and capital discipline to generate strong returns. This has resulted in Vermilion providing shareholders with over $3.8 billion, or $40.20 per share, of dividends over the last 17 years. This approach has also helped build an organization underpinned by a high quality, high netback diversified asset base with strong free cash flow generation. Through Vermilion's history we have experienced, and more importantly learned from, several previous severe downturns. To that end, while our long-term strategic plan is unchanged, we have acted quickly to ensure the Company can emerge from the current downturn in a strong financial position. This, together with our talented and dedicated organizational team gives me confidence that we can successfully navigate the Company through this very difficult time and position Vermilion for continued long-term value creation."
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with returning capital to investors when economically warranted. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares and are committed to delivering long-term value for all stakeholders. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, April 29, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to announce that at its annual meeting of shareholders held on April 28, 2020 each of the ten nominees were elected as directors of the Company.
The detailed results of the vote by ballot are as follows:
Name of Nominee | Votes For | Votes Withheld | ||
Number | Percent (%) | Number | Percent (%) | |
Lorenzo Donadeo | 40,800,761 | 96.67% | 1,405,270 | 3.33% |
Larry J. Macdonald | 39,447,319 | 93.44% | 2,770,515 | 6.56% |
Carin A. Knickel | 40,361,411 | 95.60% | 1,856,423 | 4.40% |
Stephen P. Larke | 40,005,735 | 94.76% | 2,212,099 | 5.24% |
Loren M. Leiker | 40,942,072 | 96.98% | 1,275,762 | 3.02% |
Dr. Timothy R. Marchant | 41,002,675 | 97.12% | 1,215,159 | 2.88% |
Anthony Marino | 40,764,572 | 96.56% | 1,453,262 | 3.44% |
Robert Michaleski | 40,258,838 | 95.36% | 1,958,996 | 4.64% |
William B. Roby | 40,964,247 | 97.03% | 1,253,587 | 2.97% |
Catherine L. Williams | 40,365,461 | 95.61% | 1,852,373 | 4.39% |
For complete voting results, please see our Report of Voting Results available through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.
An archive webcast of the annual meeting of shareholders and presentation by Anthony Marino, President & CEO, that provides a business overview and an update on recent developments, is available on Vermilion's website at www.vermilionenergy.com.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes free cash flow generation and returning capital to investors when economically warranted, augmented by moderate organic production growth and value-adding acquisitions. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas semi-conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, April 28, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three months ended March 31, 2020.
The unaudited interim financial statements and management discussion and analysis for the three months ended March 31, 2020 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
(2) | The Weststellingwerf flow rate was 14.7 mmcf/d gross over a 24-hour period at a wellhead pressure of 1,625 psi. Initial flow rates are not necessarily indicative of long-term performance or ultimate recovery. |
($M except as indicated) | Q1 2020 | Q4 2019 | Q1 2019 | |||
Financial | ||||||
Petroleum and natural gas sales | 328,314 | 388,802 | 481,083 | |||
Fund flows from operations | 170,225 | 215,592 | 253,572 | |||
Fund flows from operations ($/basic share) (1) | 1.09 | 1.38 | 1.66 | |||
Fund flows from operations ($/diluted share) (1) | 1.09 | 1.38 | 1.64 | |||
Net earnings (loss) | (1,318,504) | 1,477 | 39,547 | |||
Net earnings (loss) ($/basic share) | (8.42) | 0.01 | 0.26 | |||
Capital expenditures | 233,704 | 100,625 | 202,053 | |||
Acquisitions | 11,337 | 9,165 | 16,027 | |||
Asset retirement obligations settled | 3,732 | 7,352 | 3,597 | |||
Cash dividends ($/share) | 0.575 | 0.690 | 0.690 | |||
Dividends declared | 90,067 | 107,702 | 105,549 | |||
% of fund flows from operations | 53 | % | 50 | % | 42 | % |
Net dividends (1) | 82,422 | 97,502 | 98,445 | |||
% of fund flows from operations | 48 | % | 45 | % | 39 | % |
Payout (1) | 319,858 | 205,479 | 304,095 | |||
% of fund flows from operations | 188 | % | 95 | % | 120 | % |
Net debt | 2,155,623 | 1,993,194 | 2,000,144 | |||
Net debt to four quarter trailing fund flows from operations | 2.61 | 2.20 | 1.45 | |||
Operational | ||||||
Production | ||||||
Crude oil and condensate (bbls/d) | 44,881 | 46,261 | 49,181 | |||
NGLs (bbls/d) | 8,022 | 8,160 | 7,897 | |||
Natural gas (mmcf/d) | 265.51 | 260.72 | 277.96 | |||
Total (boe/d) | 97,154 | 97,875 | 103,404 | |||
Average realized prices | ||||||
Crude oil and condensate ($/bbl) | 58.66 | 71.25 | 73.45 | |||
NGLs ($/bbl) | 8.92 | 14.63 | 22.49 | |||
Natural gas ($/mcf) | 2.94 | 3.61 | 5.10 | |||
Production mix (% of production) | ||||||
% priced with reference to WTI | 39 | % | 40 | % | 37 | % |
% priced with reference to Dated Brent | 17 | % | 17 | % | 18 | % |
% priced with reference to AECO | 27 | % | 26 | % | 26 | % |
% priced with reference to TTF and NBP | 17 | % | 17 | % | 19 | % |
Netbacks ($/boe) | ||||||
Operating netback (1) | 22.02 | 27.53 | 31.50 | |||
Fund flows from operations netback | 18.85 | 24.40 | 26.76 | |||
Operating expenses | 13.41 | 12.52 | 12.92 | |||
General and administration expenses | 1.47 | 1.88 | 1.38 | |||
Average reference prices | ||||||
WTI (US $/bbl) | 46.17 | 56.96 | 54.90 | |||
Edmonton Sweet index (US $/bbl) | 38.59 | 51.59 | 50.05 | |||
Saskatchewan LSB index (US $/bbl) | 38.41 | 51.58 | 50.84 | |||
Dated Brent (US $/bbl) | 50.26 | 63.25 | 63.20 | |||
AECO ($/mcf) | 2.03 | 2.48 | 2.62 | |||
NBP ($/mcf) | 4.32 | 5.38 | 8.33 | |||
TTF ($/mcf) | 4.23 | 5.36 | 8.14 | |||
Average foreign currency exchange rates | ||||||
CDN $/US $ | 1.34 | 1.32 | 1.33 | |||
CDN $/Euro | 1.48 | 1.46 | 1.51 | |||
Share information ('000s) | ||||||
Shares outstanding - basic | 157,020 | 156,290 | 153,213 | |||
Shares outstanding - diluted (1) | 160,425 | 159,912 | 156,650 | |||
Weighted average shares outstanding - basic | 156,562 | 155,950 | 152,904 | |||
Weighted average shares outstanding - diluted (1) | 156,562 | 156,180 | 154,550 |
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Message to Shareholders
The past two months have been an extremely challenging time for people the world over as we make changes in our daily lives to arrest the COVID-19 pandemic. Health and safety is our top priority at Vermilion, and we have taken the necessary physical distancing measures and operating adjustments to manage through this crisis while still delivering essential energy products for our society. I would like to extend my deepest gratitude to all of our employees and contractors who have adapted their daily working practices and schedules to ensure both safety and business continuity at Vermilion. At present, we have only moderate impacts on our operations due to COVID-19, with those effects stemming solely from reduced availability of third party services in France. We are particularly proud of our field staff, which has maintained production operations in all of our business units, including jurisdictions that have been particularly hard hit with COVID-19.
During the first quarter of 2020, we executed a front-loaded capital program, in part to mitigate the risk of another season of post break-up weather delays. Given the events that have transpired over the past several weeks with respect to the COVID-19 pandemic, we believe this program will prove to be beneficial to Vermilion in several ways. The timing of this program allowed us to complete most of our drilling and completion activity before physical distancing measures were necessary, minimizing health risks to our employees and contractors. Furthermore, our capital program has established a significant amount of production capacity, which will benefit us throughout the year as we minimize capital expenditures for the remainder of 2020.
Production during the quarter averaged 97,154 boe/d, down slightly from the prior quarter, primarily due to natural decline, unplanned downtime in Australia, minor COVID-19 impacts, and the timing of new well completions. We drilled several wells in Canada that were more prolific than we anticipated, and brought these wells on production after the end of the first quarter. We continued to advance permitting in the Netherlands including the recently completed Weststellingwerf well (0.5 net) well, for which we are currently awaiting the final production permit. In Australia, although somewhat delayed by cyclone activity, we successfully completed the electric submersible pump (ESP) installation on two wells, which has enhanced our production capacity at Wandoo. Pricing for our Wandoo crude has significantly improved with the implementation of the new IMO 2020 regulation at the start of the year, resulting in an average realized premium of C$29/bbl over dated Brent for Q1 2020.
We generated $170 million of FFO during the quarter, which was down 21% from the prior quarter primarily due to weaker commodity prices. Crude oil prices started the year on solid footing with WTI and Brent benchmarks reaching over US$63 and US$70 per barrel respectively in early January. As the rapid spread of COVID-19 took hold during the quarter, global oil prices declined due to associated demand destruction, and the price decline was exacerbated by the OPEC+ price war in early March. This rapid decline in oil prices had a significant negative impact on our cash flows during the first quarter and our projections for the balance of the year.
In response, we reduced our monthly dividend by 50% and announced an $80 to $100 million reduction to our capital budget in early March. We now expect to reach the upper end of this capital reduction range. In addition, we have identified $35 million in expense savings to be executed in 2020, and are continuing to identify greater reductions. Commodity market conditions continued to deteriorate throughout March and early April, at which point we decided to suspend our monthly dividend until further notice. The basis for suspending the dividend is to preserve liquidity and protect Vermilion's financial position during this period of global economic turmoil. Maintaining balance sheet strength has always been our top financial priority and we believe the suspension of our monthly dividend supports that objective. We also believe that this will better position us for the economic and commodity recovery that we expect will ensue when the world economy emerges from the COVID-19 crisis.
Since the beginning of March 2020, our projected annualized cash outlays for dividends, capex and expenses have been reduced by over $550 million. Under the current commodity strip, we expect to generate positive free cash flow for the last three quarters of 2020. Looking forward, Vermilion fully intends to exit this period of economic turmoil in a position of enhanced strength to resume a capital markets model that includes returning cash to our shareholders.
In Q1 2020, we negotiated and closed an extension to our $2.1 billion revolving credit facility to extend the maturity to May 31, 2024. All other terms within the facility remained the same. As at March 31, 2020, we had over $500 million of undrawn capacity on this facility.
To date, the vast majority of our operations have not been interrupted by the pandemic, aside from minor timing delays in capital projects in several business units as we put COVID-19 protocols in place. As mentioned previously, we have made the necessary adjustments to our daily working practices to maximize business continuity. The only meaningful impact has been in France where government-mandated confinement resulting in work restrictions has limited our ability to complete well workovers beginning in March. In addition, we have been forced to curtail some of our production in the Paris Basin due to a temporary shutdown of the Grandpuits refinery because of reduced product demand. At present, these COVID-19 impacts are estimated to total approximately 2,000 boe/d on an annualized basis.
Q1 2020 Operations Review
Europe
In France, Q1 2020 production averaged 9,957 boe/d, a decrease of 3% from the prior quarter primarily due to higher than normal well downtime. The COVID-19 confinement measures put in place by the France government in mid-March restricted our ability to complete well workovers and facility maintenance. In addition, the Total-operated Grandpuits refinery temporarily shut down operations in late March due to low product demand caused by COVID-19. As a result of the Grandpuits refinery closure and reduced well servicing activity, we will temporarily reduce our French production by about one-third during the second quarter of 2020.
In the Netherlands, Q1 2020 production averaged 8,143 boe/d, a slight increase from the prior quarter. The increase was primarily due to higher uptime across our asset base, partially offset by natural decline. We continue to advance the permitting for future planned wells while awaiting the final production permit for our Weststellingwerf well (0.5 net).
In Ireland, production averaged 41 mmcf/d (6,896 boe/d) in Q1 2020, a decrease of 2% from the prior quarter. The decrease was primarily due to natural decline, partially offset by higher uptime at the Corrib natural gas processing facility compared to the prior quarter.
In Germany, Q1 2020 production averaged 3,349 boe/d, a slight decrease from the prior quarter. The decrease was primarily due to planned downtime to perform various workovers and facility maintenance, but was partially offset by improved uptime at one of our operated oil fields following the completion of pipeline maintenance.
In Central and Eastern Europe ("CEE"), production averaged 546 boe/d in Q1 2020, nearly double the level from the prior quarter reflecting a full quarter contribution from the two (1.3 net) Hungarian wells tied-in midway through the fourth quarter of 2019.
North America
In Canada, production averaged 59,537 boe/d in Q1 2020, an increase of 2% from the prior quarter. The increase was primarily due to production contributions from new well start-ups partially offset by natural decline. We drilled or participated in 77 (67.4 net) wells in the first quarter of 2020, 15 (15.0 net) of which were drilled in Alberta and 62 (52.4 net) drilled in Saskatchewan. In both Alberta and Saskatchewan, we observed strong performance from wells drilled in the quarter, with several wells performing ahead of expectations. We brought 13 (13.0 net) wells on production in Alberta and 55 (48.0 net) wells on production in Saskatchewan during the quarter. We have completed all of our planned drilling activity in Canada for the year, with the majority of these wells completed and tied-in prior to spring break-up in mid-April.
In the United States, Q1 2020 production averaged 4,685 boe/d, a decrease of 18% from the prior quarter. The decrease was primarily due to natural decline and increased downtime. During Q1, we drilled nine (8.9 net) wells and completed and tied-in three (2.9 net) of these wells at the end of the quarter. The remaining six (6.0 net) wells were completed in April and are undergoing tie-in activities. This constitutes the completion of our planned drilling and completion activities for 2020 in the United States.
Australia
In Australia, production averaged 4,041 bbl/d in Q1 2020, a decrease of 11% from the previous quarter, primarily due to planned and unplanned downtime, which stemmed from the installation of electric submersible pumps on two of our wells and cyclone activity during the quarter. The cyclone forced us to temporarily halt Wandoo production and delayed completion of the ESP installations and well startup. Installation of the ESPs was successfully completed during the quarter and the wells are on production. Our crude sales during the quarter realized an average price that was approximately C$29 per barrel above Dated Bent, reflecting an increased premium for our Wandoo Crude following the implementation of IMO 2020 regulations.
Dividend and Capital Reductions
In March, we reduced our monthly dividend by 50% to $0.115 per share and announced an $80 to $100 million reduction to our annual capital budget in response to the COVID-19 pandemic and the resulting negative impact on near-term oil demand and prices. We now expect to achieve the high end of this capital reduction range. In addition, subsequent to the first quarter, our board of directors suspended the monthly dividend as a further measure to strengthen the financial position of the company during this period of weak commodity prices.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows. In aggregate, as of April 21, 2020, we currently have 66% of our expected net-of-royalty production hedged for Q2 2020. For 2020 as a whole, approximately 49% of our production is hedged, with 82% of our hedge position in two-way and three-way collar structures.
With respect to individual products within our product mix, we have hedged 79% of anticipated European natural gas volumes for Q2 2020. We have also hedged 75% of our anticipated full-year 2020 European natural gas volumes at prices which are expected to provide for strong project economics and free cash flows. At present, 61% of our expected Q2 2020 oil production is hedged. For Q2 2020, 67% of our North American natural gas production is priced away from AECO, with a variety of contracts to sell gas at the SoCal Border, Henry Hub, Saskatchewan and Wyoming.
In addition to the percentages that are shown above for swaps and collars, we have transacted WTI calendar spreads to protect an additional 16% of our Q2 2020 and Q3 2020 oil production. Please refer to the Hedging section of our website under Invest With Us for further details.
Sustainability
Vermilion was named to the CDP Climate Leadership Level (A-) for the third consecutive year in 2019. We were one of only two Canadian oil and gas companies and one of only four North American oil and gas companies to receive this designation, ranking Vermilion in the top 6% of oil and gas companies globally. We are proud of this achievement and believe this ranking is a reflection of our focus on sustainable oil and gas production, responsible operating practices and positive track record of reducing emissions from our assets. We will continue to seek new and innovative ways to improve our overall operating performance while reducing the emission intensity of our assets. We fully intend to maintain our focus on ESG despite the economic upheaval wrought by COVID-19.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
April 28, 2020
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Annual General Meeting Webcast
Vermilion will hold its Annual General and Special Meeting on April 28, 2020 at 3:00 pm MT. With the emergence of COVID-19, and in light of limits on larger gatherings and our concern for the health and safety of our employees and shareholders, our meeting will be held virtually. Shareholders can participate electronically at https://web.lumiagm.com/131477895. Please see our Virtual Meeting Guide at https://www.vermilionenergy.com/files/2020_Virtual_Meeting_Guide.pdf for detailed instructions on how to access the meeting, vote on resolutions and submit questions. Following the formal portion of the meeting, a presentation will be given by Anthony Marino, President & Chief Executive Officer. Guests may also view the event at https://web.lumiagm.com/131477895 by registering as a guest. The live webcast link, webcast slides, and archive webcast link will be available on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes free cash flow generation and returning capital to investors when economically warranted, augmented by moderate organic production growth and value-adding acquisitions. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas semi-conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands, and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures; Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2020 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion's future project inventory, and the wells expected to be drilled in 2020; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt, including its ability to redeem senior unsecured notes prior to maturity; statements regarding Vermilion's hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, April 21, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) will release its 2020 first quarter operating and condensed financial results on Tuesday, April 28, 2020 after the close of North American markets. The unaudited financial statements and management discussion and analysis for the first quarter ended March 31, 2020 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Annual General Meeting and Webcast Details
Vermilion will hold its Annual General and Special Meeting on April 28, 2020 at 3:00 pm MT. With the emergence of COVID-19, and in light of limits on larger gatherings and our concern for the health and safety of our employees and shareholders, our meeting will be held virtually. Shareholders can participate electronically at https://web.lumiagm.com/131477895. Please see our Virtual Meeting Guide at https://www.vermilionenergy.com/files/2020_Virtual_Meeting_Guide.pdf for detailed instructions on how to access the meeting, vote on resolutions and submit questions. Following the formal portion of the meeting, a presentation will be given by Anthony Marino, President & Chief Executive Officer. Guests may also view the event at https://web.lumiagm.com/131477895 by registering as a guest. The live webcast link, webcast slides, and archive webcast link will be available on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes free cash flow generation and returning capital to investors when economically warranted, augmented by moderate organic production growth and value-adding acquisitions. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas semi-conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, April 15, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) announces that its Board of Directors has suspended our monthly dividend until further notice.
Following the release of our revised 2020 capital budget and announced dividend reduction, we have witnessed further deterioration in near-term commodity prices as a result of the COVID-19 pandemic and resulting oil demand destruction. In particular, growing oil inventory has decreased prompt prices for global benchmark indices and expanded regional discounts in North America. As we have previously stated, we are attuned to evolving business conditions and are prepared to make further adjustments to all forms of cash outlays to protect Vermilion's financial position. In view of our determination to reduce debt within the current commodity environment, we are suspending our monthly dividend until further notice following the payment of the March dividend of $0.115 previously declared for payment today.
Since the beginning of March 2020, our annualized cash outlays for capex and dividends have now been reduced by approximately $520 million. Furthermore, we have identified approximately $30 million of additional opportunities to reduce cash expenses and will seek to identify and secure other savings.
Vermilion has a long history of paying dividends and we remain strong proponents of returning capital to shareholders. For Vermilion, returning cash to our owners has enforced capital discipline and led us to put in place a conventional and semi-conventional asset base with low base declines and differential capability to produce free cash. Nonetheless, financial strength remains our overriding goal, and suspension of our dividend enhances that objective. Acting today better positions us for the economic and commodity recovery that we believe will ensue when the world economy emerges from the COVID-19 crisis. Looking forward, Vermilion fully intends to exit this period of economic turmoil in a posture of enhanced strength to resume a capital markets model that includes returning cash to our shareholders.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes free cash flow generation and returning capital to investors when economically warranted, augmented by moderate organic production growth and value-adding acquisitions. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas semi-conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included in this news release may constitute forward-looking statements or information under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this news release may include, but are not limited to: adjustments to forms of cash outlays to protect Vermilion's financial position; opportunities for savings; economic and commodity recovery that Vermilion believes will ensue when the world economy emerges from the COVID-19 crisis; Vermilion's exit from the period of economic turmoil in a posture of enhanced strength and Vermilion's resumption of a capital markets model that includes returning cash to shareholders.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements or information because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: economic and business conditions as a result of the COVID-19 pandemic and the resulting oil demand destruction; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally; risks inherent in Vermilion's marketing operations, including credit risk; potential delays or changes in plans with respect to exploration or development projects; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
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SOURCE Vermilion Energy Inc.
CALGARY, March 16, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) announces that its Board of Directors has approved a reduction to our 2020 capital budget of $80 to $100 million and a reduction in our monthly dividend from $0.115 CDN per share to $0.02 CDN per share in response to the pronounced decline in global commodity prices. The new dividend amount will be implemented in the April dividend payable in May 2020.
Following the release of our Q4 2019 results on March 6, 2020, we have witnessed a further decrease in oil prices as a result of the growing COVID-19 outbreak and the ensuing oil price war between OPEC+ members. While we continue to believe the long-term fundamentals for the oil and gas industry are sound and will lead to higher prices in the future, we cannot predict how long the impact from COVID-19 and the OPEC+ price war will continue. As we stated in our Q4 2019 release, in the event that we experienced an even more pronounced and protracted commodity downturn due to COVID-19 or any other cause, we would be attentive to all forms of cash outlays to protect Vermilion's financial position. As we assessed the status of the global emergency, we determined that it was now appropriate to take these additional actions regarding capital investment and dividends.
The new capital investment and dividend reductions reduce our annualized cash outlays by an additional $260 to $280 million, providing greater flexibility to manage our business through this period of depressed and uncertain commodity prices. In combination with the dividend reduction we announced on March 6, our annualized cash outlays will have been reduced by $465 to $485 million. These reductions will substantially contribute to Vermilion's financial strength, and we will remain vigilant to make further adjustments based on our assessment of evolving business conditions. Vermilion fully intends to exit this period of economic turmoil in a position of enhanced financial strength.
Our revised capital budget of $350 to $370 million is expected to deliver 2020 annual production of 94,000 boe/d to 98,000 boe/d, reflecting both a reduced capital slate and allowance for potential disruptions to our operations due to COVID-19. Thus far, we have had no operational or supply chain impacts from COVID-19.
March 2020 Dividend Declaration
As discussed in our Q4 2019 release, Vermilion is reaffirming a cash dividend of $0.115 CDN per share payable on April 15, 2020 to all shareholders of record on March 31, 2020. The ex-dividend date for this payment is March 30, 2020. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada). As previously announced, we are phasing out the Dividend Reinvestment Plan ("DRIP") over the course of 2020. We will be prorating the available DRIP shares by 25% each quarter starting in Q1 2020, until completely eliminated by Q4 2020. The net market proration factor may differ slightly each month from the stated factor to ensure the total quarterly proration of 25% remains in-tact. For those investors that would like to continue reinvesting the cash portion of their dividends in Vermilion shares, we encourage you to contact your brokerage firm about setting up an automated reinvestment plan to purchase shares on the open market.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing a meaningful dividend stream to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, March 6, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and financial results for the year ended December 31, 2019 along with our 2019 reserves and resources information.
The audited financial statements, management discussion and analysis, and annual information form for the year ended December 31, 2019 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
(2) | The Weststellingwerf flow rate was 14.7 mmcf/d gross over a 24 hour period at a wellhead pressure of 1,625 psi. Initial flow rates are not necessarily indicative of long-term performance or ultimate recovery. |
(3) | Estimated company interest proved, developed and producing, total proved, and total proved plus probable reserves as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 10, 2020 with an effective date of December 31, 2019 (the "2019 GLJ Reserves Report"). |
(4) | F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted FDC (future development capital), by the change in the reserves, incorporating revisions and production, for the same period. |
(5) | Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
($M except as indicated) | Q4 2019 | Q3 2019 | Q4 2018 | 2019 | 2018 | ||
Financial | |||||||
Petroleum and natural gas sales | 388,802 | 391,935 | 456,939 | 1,689,863 | 1,678,117 | ||
Fund flows from operations | 215,592 | 216,153 | 222,342 | 908,055 | 838,652 | ||
Fund flows from operations ($/basic share) (1) | 1.38 | 1.39 | 1.46 | 5.87 | 5.96 | ||
Fund flows from operations ($/diluted share) (1) | 1.38 | 1.39 | 1.44 | 5.82 | 5.89 | ||
Net earnings (loss) | 1,477 | (10,229) | 323,373 | 32,799 | 271,650 | ||
Net earnings (loss) ($/basic share) | 0.01 | (0.07) | 2.12 | 0.21 | 1.93 | ||
Capital expenditures | 100,625 | 127,879 | 163,580 | 523,164 | 518,214 | ||
Acquisitions | 9,165 | 4,657 | 2,689 | 38,472 | 1,759,425 | ||
Asset retirement obligations settled | 7,352 | 3,586 | 6,562 | 19,442 | 15,765 | ||
Cash dividends ($/share) | 0.690 | 0.690 | 0.690 | 2.760 | 2.715 | ||
Dividends declared | 107,702 | 107,176 | 105,310 | 427,311 | 388,111 | ||
% of fund flows from operations | 50% | 50% | 47% | 47% | 46% | ||
Net dividends (1) | 97,502 | 98,316 | 100,195 | 392,374 | 339,060 | ||
% of fund flows from operations | 45% | 45% | 45% | 43% | 40% | ||
Payout (1) | 205,479 | 229,781 | 270,337 | 934,980 | 873,039 | ||
% of fund flows from operations | 95% | 106% | 122% | 103% | 104% | ||
Net debt | 1,993,194 | 2,001,870 | 1,929,529 | 1,993,194 | 1,929,529 | ||
Net debt to four quarter trailing fund flows from operations | 2.20 | 2.19 | 2.30 | 2.20 | 2.30 | ||
Operational | |||||||
Production | |||||||
Crude oil and condensate (bbls/d) | 46,261 | 47,242 | 47,678 | 47,902 | 39,182 | ||
NGLs (bbls/d) | 8,160 | 7,772 | 7,815 | 7,984 | 6,366 | ||
Natural gas (mmcf/d) | 260.72 | 253.36 | 276.77 | 266.82 | 250.33 | ||
Total (boe/d) | 97,875 | 97,239 | 101,621 | 100,357 | 87,270 | ||
Average realized prices | |||||||
Crude oil and condensate ($/bbl) | 71.25 | 73.45 | 66.19 | 74.42 | 79.16 | ||
NGLs ($/bbl) | 14.63 | 6.14 | 25.69 | 13.61 | 26.33 | ||
Natural gas ($/mcf) | 3.61 | 2.43 | 5.83 | 3.58 | 5.45 | ||
Production mix (% of production) | |||||||
% priced with reference to WTI | 40% | 39% | 37% | 39% | 32% | ||
% priced with reference to Dated Brent | 17% | 19% | 18% | 18% | 20% | ||
% priced with reference to AECO | 26% | 26% | 26% | 25% | 26% | ||
% priced with reference to TTF and NBP | 17% | 16% | 19% | 18% | 22% | ||
Netbacks ($/boe) | |||||||
Operating netback (1) | 27.53 | 28.22 | 27.58 | 29.25 | 31.59 | ||
Fund flows from operations netback | 24.40 | 23.73 | 23.79 | 24.77 | 26.47 | ||
Operating expenses | 12.52 | 11.55 | 12.04 | 12.01 | 11.26 | ||
General and administration expenses | 1.88 | 1.50 | 1.37 | 1.61 | 1.64 | ||
Average reference prices | |||||||
WTI (US $/bbl) | 56.96 | 56.45 | 58.81 | 57.03 | 64.77 | ||
Edmonton Sweet index (US $/bbl) | 51.59 | 51.79 | 32.51 | 52.15 | 53.65 | ||
Saskatchewan LSB index (US $/bbl) | 51.58 | 52.01 | 44.03 | 52.50 | 56.46 | ||
Dated Brent (US $/bbl) | 63.25 | 61.94 | 67.76 | 64.30 | 71.04 | ||
AECO ($/mcf) | 2.48 | 1.06 | 1.56 | 1.76 | 1.50 | ||
NBP ($/mcf) | 5.38 | 4.50 | 11.03 | 5.90 | 10.35 | ||
TTF ($/mcf) | 5.36 | 4.40 | 10.91 | 5.90 | 10.23 | ||
Average foreign currency exchange rates | |||||||
CDN $/US $ | 1.32 | 1.32 | 1.32 | 1.33 | 1.30 | ||
CDN $/Euro | 1.46 | 1.47 | 1.51 | 1.49 | 1.53 | ||
Share information ('000s) | |||||||
Shares outstanding - basic | 156,290 | 155,505 | 152,704 | 156,290 | 152,704 | ||
Shares outstanding - diluted (1) | 159,912 | 159,260 | 156,173 | 159,912 | 156,173 | ||
Weighted average shares outstanding - basic | 155,950 | 155,254 | 152,588 | 154,736 | 140,619 | ||
Weighted average shares outstanding - diluted (1) | 156,180 | 155,421 | 153,880 | 156,094 | 142,335 |
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Message to Shareholders
We are now in the sixth year of a period of reduced energy prices that began in the second half of 2014, with the novel coronavirus (COVID-19) being the latest event to produce a retracement in commodity markets. Throughout this period, we have maintained focus on profitability by grinding costs out of all phases of our business ranging from field operations to financing expense, upgrading our capital project slate, and adapting our capital markets model to focus even more acutely on returning capital to shareholders. In this environment, we have been unique among our traditional competitor group in maintaining our dividend while still providing a moderate level of growth. We have paid a monthly dividend (or distribution in the trust era) for the past 205 consecutive months, returning over $40 per share to shareholders over this period. During the energy downturn, we have put more production, reserves and free cash flow behind each share despite dramatically lower capital budgets. While still modestly over 100%, we brought our total payout ratio down to 103% in 2019, representing our lowest total payout ratio since before the financial crisis in 2008. Moreover, we are phasing out the small level of remaining DRIP participation at the end of Q3 2020, resulting in 100% of dividends being paid in cash.
We are proud of this record of returning capital to shareholders while still providing per share growth. We think paying dividends is the right thing to do. This model has kept us disciplined in a capital-intensive industry and has put substantial cash back in the hands of investors. As we started 2020, our funding status continued to improve to a projected total payout ratio below 100%, driven by a significantly lower capital budget for 2020 as compared to 2019, and by a modestly positive trend for oil prices. In that environment, we were confident in our ability to continue our monthly dividend at $0.23 while deleveraging our balance sheet. We were clear in stating that we would reevaluate the dividend in the event of a structural change in commodity prices that could affect our ability to self-fund our combination of capital expenditures and dividends, and that we would prioritize balance sheet strength over other objectives, including either growth or dividends.
The emergence of COVID-19 was an unanticipated event, and we do not claim any special expertise in assessing what the appropriate type or degree of public health responses are to the outbreak. Nonetheless, we must make an assessment of its current and probable future market and economic impacts. We observe that COVID-19 has dramatically altered individual, business and government behavior, and that these impacts are decidedly negative for the outlook for global economic growth, commodity prices in general, and oil demand and prices in particular. We do not believe that the long-term prospects for the oil and gas industry are likely to be significantly altered, and ultimately we expect a resumption of a positive trend for commodity prices. However, we do think the recovery in oil prices that we began to experience at the outset of 2020 will be pushed back for an unknown period. In the short-to-medium term, we believe COVID-19 represents a hard-to-quantify set of macro risks, probably lower in economic severity than the financial crisis of 2008, but of a type that is also likely unprecedented in our lifetimes.
We have maintained our dividend though a number of other periods of downside volatility since the commodity crash of 2014, making all of the necessary adjustments to costs and growth levels. During these periods, we continuously assessed our dividend policy in light of our top priority of balance sheet strength. As we consider today's economic and commodity outlook, we believe it is unlikely that we would achieve fully-funded status for our present dividend at a reasonable level of capital expenditures. Therefore, we have determined that a reduction to our dividend is the most prudent course of action at this time. Accordingly, our board of directors has approved a 50% reduction in our monthly dividend to $0.115 per share, or $1.38 on an annualized basis. The revised dividend will be effective for the March dividend payable on April 15, 2020. At the current forward commodity strip, we estimate a 2020 payout ratio of 99%, including previously declared dividends. Any excess cash generated beyond the dividend and capital requirements will be allocated towards debt reduction at this time, while retaining the option of buying back shares through our NCIB program in an improved macroeconomic environment.
We have had no operational impacts from COVID-19 to-date. We have business continuity plans for each of our business units and for our corporate center that can be invoked if the outbreak significantly worsens and threatens our supply chain or workforce capabilities.
During 2019, Vermilion generated record cash flow, production and reserves despite a continued environment of challenging commodity prices. We recorded FFO of $908 million in 2019 on a capital program of $523 million, which translated to free cash flow(1) generation of $385 million, also the highest in our history. The resulting 2019 total payout ratio, after accounting for dividends and asset retirement obligations, was 103%. In Q4 2019, we generated $216 million of FFO which was in line with the prior quarter despite a large inventory build in Australia due to the timing of crude liftings. Net debt in 2019 increased modestly to $2.0 billion, however the net debt to trailing FFO ratio improved to 2.2x, compared to 2.3x in 2018. In addition to an improving leverage profile, we also enhanced the quality of our balance sheet over the past year. We have recently received commitments to extend our $2.1 billion covenant-based credit facility, resulting in a new a maturity date of May 2024. The closing of the extension remains subject to customary closing conditions. In addition, in June 2019, we executed a cross currency interest rate swap on our 2025 US$300 million long-term senior notes, converting our 5.625% interest cost on these notes to 3.275% for the remainder of their term. As a result of these initiatives, our pre-tax cost of debt today is approximately 3.2% with a weighted-average remaining term of 4.4 years.
We delivered record production of 100,357 boe/d in 2019, representing year-over-year growth of 15%, or 5% on a per share basis. We achieved these results despite several unexpected operational challenges throughout the year, including a third-party refinery outage in France and uncharacteristic weather-driven delays in Canada. During the fourth quarter we tied-in two discoveries in Hungary and successfully drilled the Weststellingwerf well in the Netherlands, marking our first drilling activity in that country in two and a half years. In the US, new well completions from our Q3 2019 program drove increased production from our North American region. Two months into the new year, the execution of our 2020 capital program is progressing as planned. To mitigate the risk of another season of post-breakup weather delays, which affected our results in 2019, we are front-loading our 2020 capital program by scheduling most of our North American drilling activity into the first quarter.
Proved plus probable reserves increased by 3% year-over-year to 501.2 mmboe. The large majority of our new reserve additions were through organic activities as we continue to enhance the recovery factor on existing assets and advanced resources to reserves in a number of our operating areas. We added these reserves at an organic F&D cost of $9.93/boe, including FDC, resulting in an operating recycle ratio of 3.0x and funds flow recycle ratio of 2.5x. Our F&D costs have been below $10.00/boe for the past three years (3-year average F&D of $9.38, including FDC), while growing our liquids weighting. Driven by a capital-efficient project slate and a continued focus on cost improvements, our 3-year organic operating recycle ratio stands at 3.2x. Our contingent and prospective resource bases remain a source of reserve additions, with 31.8 mmboe of contingent and 5.0 mmboe of prospective resources converted to 2P reserves during 2019.
As we stated earlier, our top financial priority remains balance sheet strength. Both our debt-to-cash flow ratio and weighted-average interest rate decreased in 2019, and our debt exposures are fully termed-out via our covenant-based bank facility and long-term notes. Nonetheless, we will continue to be vigilant regarding commodity prices and resulting cash flows. It remains to be seen how long oil demand and economic growth will be suppressed by the global reaction to COVID-19. Should we experience an even more-pronounced and protracted commodity downturn due to COVID-19 or any other cause, we will be attentive to all forms of cash outlays, focusing first on capital investment levels, to protect the financial position of the company.
Q4 2019 Operations Review
Europe
In France, Q4 2019 production averaged 10,264 boe/d, representing a slight decrease from the prior quarter primarily due to weather-driven downtime in the Aquitaine Basin. Production in the Paris Basin was relatively consistent with the prior quarter.
In the Netherlands, Q4 2019 production averaged 8,088 boe/d, an increase of 9% from the prior quarter. The increase was primarily due to the restoration of production following planned and unplanned facility downtime in Q3 2019. During the quarter, we successfully drilled and completed the Weststellingwerf well (0.5 net), representing our first drilling activity in the Netherlands since 2017. We encountered three gas-bearing zones in the Vlieland, Zechstein and Rotliegend formations. The Weststellingwerf well flowed at an initial gross rate of 14.7 mmcf/d(2) and is expected to be brought on production during 2020.
In Ireland, production averaged 42 mmcf/d (7,049 boe/d) in Q4 2019, a decrease of 2% from the prior quarter. The decrease was primarily due to natural decline, partially offset by higher uptime at the Corrib natural gas processing facility compared to the prior quarter. As disclosed in our Q3 2019 release, we had 10 days of unplanned downtime in one of the plant auxiliary systems, which occurred at the end of Q3 2019 and continued into Q4 2019. Since assuming operatorship of Corrib at the end of 2018, we have reduced operating costs by approximately 20% and continue to evaluate other optimization opportunities.
In Germany, Q4 2019 production averaged 3,373 boe/d, an increase of 3% from the prior quarter. The increase was primarily due to improved uptime on our operated oil and natural gas assets, partially offset by unplanned downtime on our non-operated oil assets. Following the successful drilling of the Burgmoor Z5 (46% working interest) well in 2019, the partner group has agreed to a tie-in plan which should allow for production early next year.
In Central and Eastern Europe ("CEE"), production averaged 276 boe/d following the tie-in of two discoveries from our 2019 drilling program late in the year. In Hungary, we tied-in the Mh-21 (0.3 net) and Battonya E-09 (1.0 net) wells, drilled in the second and third quarters of 2019, respectively. The wells were brought on production midway through the fourth quarter of 2019 at a restricted rate of approximately 600 boe/d net for the two wells combined. In addition, we were provisionally awarded the Kadarkút exploration license in western Hungary during the quarter and we expect to receive final government approvals in the first quarter of 2020. The license covers approximately 298,500 net acres and consists of primarily oil prospects. Most of the license is covered by 3D seismic. The license term covers a four year period, with the option to extend the license for a further two years. In Croatia, we continued to prepare for our 2020-2021 drilling programs, in addition to evaluating natural gas plant processing facility construction options, which we expect to allow tie-in of our 2019 natural gas discoveries next year.
North America
In Canada, production averaged 58,593 boe/d in Q4 2019, up slightly from the prior quarter. Strong results from new well completions in the quarter more than offset natural decline. We drilled or participated in 26 (16.8 net) wells in the fourth quarter of 2019, eight (8.0 net) of which were drilled in Alberta and 18 (8.8 net) drilled in Saskatchewan. During the quarter, we drilled one of our best ever condensate-rich Lower Mannville wells in Drayton Valley, Alberta, achieving an IP30 rate of approximately 1,900 boe/d (60% liquids). In Ferrier, we drilled a liquids-rich Upper Mannville well which delivered an IP30 rate of approximately 1,800 boe/d (15% liquids). We brought 33 (23.5 net) wells on production in Saskatchewan and four (4.0 net) wells on production in Alberta during the quarter. We are currently in the midst of a very active Q1 2020 drilling campaign in Canada, with rig activity in the quarter peaking at six rigs in Saskatchewan and four rigs in Alberta. We plan to complete the majority of our 2020 Canadian drilling program in the first quarter of the year in order to avoid potential delays from an extended spring break-up season or unseasonably wet summer weather.
In the United States, Q4 2019 production averaged 5,683 boe/d, representing an increase of 15% from the prior quarter. The increase was primarily due to a full quarter of contribution from the four wells we brought on production during the third quarter of 2019. These wells continue to perform in line with our type curves, achieving an average IP90 rate of approximately 450 boe/d. We also began drilling two (1.98 net) wells in December 2019, for which drilling finished in January 2020, and are currently undergoing completion. We currently have two rigs operating in our Hilight field in the Powder River Basin. Similar to our Canadian business unit, we plan to execute a front-end weighted capital program in the United States, completing our twelve (11.9 net) well 2020 drilling program in the first half of the year.
Australia
In Australia, production averaged 4,548 bbl/d in Q4 2019, a decrease of 18% from the previous quarter, primarily due to the planned shutdown of the Wandoo platform for eight days to perform facility upgrades and regular maintenance. We recently began the installation of electric submersible pumps on two wells and will continue to advance process optimization projects throughout 2020.
Dividend Reinvestment Plan
As previously announced, we are phasing out the Dividend Reinvestment Plan ("DRIP") in 2020 by prorating the available DRIP shares by 25% each quarter starting in Q1 2020. It is our intention to increase this proration each quarter throughout the year, such that the DRIP will be eliminated at the end of the third quarter of 2020.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows, providing additional certainty with regard to the execution of our dividend and capital programs. In aggregate, as of February 24, 2020, we currently have 51% of our expected net-of-royalty production hedged for Q1 2020. More than half of our Q1 2020 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases up to contract ceilings. For 2020 as a whole, approximately 42% of our production is hedged, with 63% of our hedge position in participating structures.
With respect to individual products within our product mix, we have hedged 70% of anticipated European natural gas volumes for Q1 2020. We have also hedged 78% of our anticipated full-year 2020 European natural gas volumes at prices which are expected to provide for strong project economics and free cash flows. At present, 44% of our expected Q1 2020 oil production is hedged. For Q1 2020, 45% of our North American natural gas production is priced away from AECO, with a variety of contracts to sell gas at the SoCal Border, Henry Hub, Saskatchewan and Wyoming.
Sustainability
We delivered another year of industry-leading performance as indicated by a number of important ESG rankings. The Company received a top quartile ranking for our industry sector in SAM's 2019 Corporate Sustainability Assessment ("CSA"). The CSA analyzes sustainability performance across economic, environmental, governance, and social criteria, and is the basis of the Dow Jones Sustainability Indices. Vermilion was ranked second in our peer group in the Sustainalytics ESG (environment, social, governance) rankings. Vermilion's MSCI ESG rating increased to AA in 2019, and our Governance Metrics score ranked in the top decile globally. We received ISS QualityScore decile ratings of 1 for both Environmental and Social, which assess corporate disclosure and transparency practices in these areas, where 1 indicates the lowest risk. These rankings reflect our high degree of ESG focus, and we will strive to continue to this record of high performance as we move forward.
2019 Reserves and Resources
In 2019 we increased our reserves and resources predominantly through development activities. Based on the 2019 GLJ Reserves Report, our 2P reserves increased 3% from year-end 2018 to 501.2(3) mmboe, while our 1P reserves increased 4% from year-end 2018 to 310.2(3) mmboe in 2019. PDP reserves increased 4% from year-end 2018 to 200.0(3) mmboe. Our PDP reserves represent 65% of our 1P reserves.
The following table provides a summary of company interest reserves by reserve category and country on an oil equivalent basis. Please refer to Vermilion's 2019 Annual Information Form for the year ending December 31, 2019 ("2019 Annual Information Form") for detailed by product type information.
BOE (mboe) | Proved Developed | Proved Developed | Proved Undeveloped | Proved | Probable | Proved Plus |
Australia | 8,608 | — | — | 8,608 | 4,552 | 13,160 |
Canada | 111,738 | 7,125 | 72,764 | 191,627 | 109,262 | 300,889 |
CEE | 228 | 1,503 | — | 1,731 | 972 | 2,703 |
France | 35,109 | 934 | 4,920 | 40,963 | 18,729 | 59,692 |
Germany | 9,694 | 2,930 | 1,157 | 13,781 | 12,959 | 26,740 |
Ireland | 11,772 | — | — | 11,772 | 6,002 | 17,774 |
Netherlands | 8,620 | 2,035 | 450 | 11,105 | 9,875 | 20,980 |
United States | 14,222 | 515 | 15,886 | 30,623 | 28,673 | 59,296 |
Vermilion | 199,991 | 15,042 | 95,177 | 310,210 | 191,024 | 501,233 |
Through development activities, we replaced 120% of 2P reserves, 121% of 1P reserves and 113% of PDP reserves, respectively. Including acquisitions, we replaced 136% of 2P reserves, 133% of 1P reserves and 122% of PDP reserves, respectively. Reserve additions included 15.0 million boe of positive technical revisions at the 1P level.
Our Operating Recycle Ratio(5) (including FDC) at the 2P level was 3.0x in 2019. We have achieved F&D costs below $10.00/boe for the past three years (3-year average F&D of $9.38, including FDC) as a result of our highly capital-efficient project slate and continued focus on cost improvements.
The following table summarizes the finding and development costs and associated operating recycle ratios by reserve category for the year ending December 31, 2019:
2019 | 3-Year Average | |||||
PDP | 1P | 2P | PDP | 1P | 2P | |
Finding and Development Costs, including FDC (F&D)(4) ($/boe) | $12.71 | $11.90 | $9.93 | $13.66 | $12.71 | $9.38 |
Finding, Development and Acquisition Costs, including FDC (FD&A)(4) ($/boe) | $12.69 | $11.82 | $9.85 | $19.31 | $17.48 | $13.84 |
F&D Operating Recycle Ratio(5) * | 2.3 | 2.5 | 3.0 | 2.2 | 2.4 | 3.2 |
FD&A Operating Recycle Ratio(5) * | 2.3 | 2.5 | 3.0 | 1.6 | 1.7 | 2.2 |
In addition to our reserve base, we report contingent and prospective resources. According to the 2019 GLJ Resources Report, risked low, best, and high estimates for our contingent resources in the Development Pending category were 139.0(6) mmboe, 236.8(6) mmboe, and 330.2(6) mmboe, respectively. The 2019 GLJ Resources Report also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 10.8(6) mmboe, 37.6(6) mmboe, and 54.1(6) mmboe, respectively. Over 86% of our best estimate risked contingent resources reside in the Development Pending category. Prospective resources were assessed at risked low, best and high estimates of 51.9(6) mmboe, 179.2(6) mmboe, and 330.2(6) mmboe, respectively. Our contingent and prospective resource bases remain a source of reserve additions, with 31.8 mmboe of contingent and 5.0 mmboe of prospective resources converted to 2P reserves during 2019.
The following table provides a reconciliation of changes in company interest reserves by reserve category and country. Please refer to Vermilion's 2019 Annual Information Form for detailed by product type information.
1P (mboe) | Australia | Canada | CEE | France | Germany | Ireland | Netherlands | United States | Vermilion |
December 31, 2018 | 9,668 | 181,938 | 131 | 43,467 | 12,990 | 13,094 | 11,804 | 25,146 | 298,236 |
Discoveries | — | 491 | 1,725 | — | 844 | — | — | — | 3,060 |
Extensions & improved recovery | — | 20,981 | — | 551 | 470 | — | 720 | 4,254 | 26,976 |
Technical revisions | 1,007 | 7,019 | (100) | 806 | 743 | 1,511 | 1,601 | 2,368 | 14,955 |
Acquisitions | — | 3,847 | — | — | — | — | — | 561 | 4,408 |
Dispositions | — | (13) | — | — | — | — | — | — | (13) |
Economic factors | — | (744) | — | (40) | — | — | — | — | (784) |
Production | (2,067) | (21,892) | (25) | (3,821) | (1,266) | (2,833) | (3,020) | (1,706) | (36,630) |
December 31, 2019 | 8,608 | 191,627 | 1,731 | 40,963 | 13,781 | 11,772 | 11,105 | 30,623 | 310,210 |
2P (mboe) | Australia | Canada | CEE | France | Germany | Ireland | Netherlands | United States | Vermilion |
December 31, 2018 | 14,480 | 284,835 | 190 | 63,918 | 25,733 | 20,576 | 22,200 | 56,213 | 488,145 |
Discoveries | — | 1,044 | 2,686 | — | 1,250 | — | — | — | 4,980 |
Extensions & improved recovery | — | 31,200 | — | 810 | 920 | — | 1,131 | 2,693 | 36,754 |
Technical revisions | 747 | 1,190 | (148) | (549) | 103 | 31 | 669 | 1,143 | 3,186 |
Acquisitions | — | 5,350 | — | — | — | — | — | 953 | 6,303 |
Dispositions | — | (428) | — | — | — | — | — | — | (428) |
Economic factors | — | (410) | — | (666) | — | — | — | — | (1,076) |
Production | (2,067) | (21,892) | (25) | (3,821) | (1,266) | (2,833) | (3,020) | (1,706) | (36,630) |
December 31, 2019 | 13,160 | 300,889 | 2,703 | 59,692 | 26,740 | 17,774 | 20,980 | 59,296 | 501,233 |
Additional information about our 2019 GLJ Reserves Report and GLJ 2019 Resources Report can be found in our 2019 Annual Information Form on our website at www.vermilionenergy.com and on SEDAR at www.sedar.com.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
March 5, 2020
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
(2) | The Weststellingwerf flow rate was 14.7 mmcf/d gross over a 24 hour period at a wellhead pressure of 1,625 psi. Initial flow rates are not necessarily indicative of long-term performance or ultimate recovery. |
(3) | Estimated company interest proved, developed and producing, total proved, and total proved plus probable reserves as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 10, 2020 with an effective date of December 31, 2019 (the "2019 GLJ Reserves Report"). |
(4) | F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted FDC (future development capital), by the change in the reserves, incorporating revisions and production, for the same period. |
(5) | Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(6) | Vermilion retained GLJ to conduct an independent resource evaluation dated February 10, 2020 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2019 (the "GLJ 2019 Resources Report"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 81% and 81%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 24%, 24% and 24%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development). Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. Prospective resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. Please refer to Vermilion's 2019 Annual Information Form for further information on Vermilion's contingent resources and prospective resources. |
Guidance
On October 25, 2018, we released our 2019 capital budget and related guidance. On February 27, 2019, we deferred some activity to later in the year and reallocated capital between business units, although the 2019 total budget and production guidance remained unchanged. On October 31, 2019, we reduced our 2019 capital expenditure guidance to $520 million and our 2019 annual production guidance to 100,000 to 101,000 boe/d. Actual 2019 capital spending of $523 million was within 1% of our guidance and 2019 average production of 100,357 boe/d was approximately at the mid-point of our revised guidance range.
On October 31, 2019, we released our 2020 capital budget and associated production guidance.
The following table summarizes our guidance:
Date | Capital Expenditures ($MM) | Production (boe/d) | |
2019 Guidance | |||
2019 Guidance | October 25, 2018 | 530 | 101,000 to 106,000 |
2019 Guidance | October 31, 2019 | 520 | 100,000 to 101,000 |
2019 Actual Results | March 6, 2020 | 523 | 100,357 |
2020 Guidance | |||
2020 Guidance | October 31, 2019 | 450 | 100,000 to 103,000 |
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and webcast presentation on Friday, March 6, 2020 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using conference ID 8457996 from March 6, 2020 at 12:00 PM MST to March 20, 2020 at 9:59 PM MST.
You may also access the webcast at https://event.on24.com/wcc/r/2209057/77DA8099A827A0D8BC4A73C85AFABBDD. The webcast link, along with conference call slides, will be available on Vermilion's website at https://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the conference call.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.115 per share, which provides a current yield of approximately 11%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands, and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward-looking statements or financial outlooks under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures; Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2020 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion's future project inventory, and the wells expected to be drilled in 2020; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt, including its ability to redeem senior unsecured notes prior to maturity; statements regarding Vermilion's hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.
Such forward-looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, Feb. 18, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on March 16, 2020 to all shareholders of record on February 28, 2020. The ex-dividend date for this payment is February 27, 2020. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada). As previously announced, we are phasing out the Dividend Reinvestment Plan ("DRIP") over the course of 2020. We will be prorating the available DRIP shares by 25% each quarter starting in Q1 2020, until completely eliminated in Q4 2020. The net market proration factor may differ slightly each month from the stated factor to ensure the total quarterly proration of 25% remains in-tact. For those investors that would like to continue reinvesting the cash portion of their dividends in Vermilion shares, we encourage you to contact your brokerage firm about setting up an automated reinvestment plan to purchase shares on the open market.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 14.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content to download multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-0-23-cdn-cash-dividend-for-march-16--2020-payment-date-301006677.html
SOURCE Vermilion Energy Inc.
DENVER, Jan. 30, 2020 /PRNewswire/ -- Institutional investors, portfolio managers, financial analysts, CIOs and other capital market professionals who invest in the energy space should register now for the EnerCom Dallas energy investment conference, which is coming to The Tower Club February 11-12 in downtown Dallas.
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors and sellside researchers to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists. The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. Key panel discussions include Environmental, Social and Governance (ESG), Capital Markets, LNG Landscape and Midstream.
New this year, the EnerCom Dallas conference is offering a unique session for energy related technology, alternative energy and traditional oil and gas start-up ventures the opportunity to present their business to a captive audience of investors. The event will provide invited presenters the opportunity to give a fifteen-minute presentation and participate in a Q&A. Investors can also schedule private one-on-one meetings with session participants at the Tower Club, Dallas.
The EnerCom Dallas schedule is now live and will be updated continuously on the conference site.
Chris Wright, CEO of Liberty Oilfield Services Will Present "Energy Transitions and Humans"
Chris Wright serves as CEO and Chairman of Liberty Oilfield Services and has since its founding in 2011. Additionally, Chris co-founded and serves as Executive Chairman of Liberty Resources, a Bakken-focused E&P company and Liberty Midstream Solutions. He has had a lifelong passion for energy and its role in human life.
He has spoken on energy to the UK House of Lords, the States Attorneys General, Federal and State Judges, debated the merits of the shale revolution on TV and given over 100 talks.
Chris completed an undergraduate degree in Mechanical Engineering at MIT and graduate work in Electrical Engineering at both UC Berkeley and MIT. Chris founded Pinnacle Technologies and from 1992 to 2006 served as CEO and Chairman. Pinnacle created the hydraulic fracture mapping industry by developing and commercializing tiltmeter and microseismic fracture mapping. Pinnacle's innovations in fracturing practices helped launch commercial shale gas production in the late 1990's. Chris was Chairman of Stroud Energy, an early shale gas producer, prior to its sale to Range Resources in 2006. Chris is currently a director of Liberty Oilfield Services, Liberty Resources, and Urban Solutions Group.
One-on-One Meetings Open for 2020 Conference Session:
EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. Buy- and sell-side attendees can now request one-on-one meeting via the conference registration portal accessible on the conference site.
EnerCom Dallas Presenting Companies Include:
The EnerCom Dallas Presenting Company Line-Up will be updated continuously on the conference website.
Registration for EnerCom Dallas is now open
Buyside professionals and oil and gas company executives may register for the event through the conference website.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2020.
Conference Dates: February 11-12, 2020
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Public and Private Company Presenters: EnerCom Dallas will feature both public and private companies headquartered in Canada and the U.S. with operations across the most active and prolific oil and gas regions and the globe.
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2020 marks EnerCom's 25th annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 50 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is an internationally recognized management consultancy advising companies on Environmental, Social & Governance (ESG), investor relations, corporate strategy/board advisory, marketing, analysis and valuation, media, branding, and visual communications design. Headquartered in Denver, EnerCom and its team of experts are passionate about the energy industry and our work to provide clients with wide range of services to build brand recognition that drives valuation and returns.
EnerCom's upcoming oil and gas investment conferences include:
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
Event Sponsors Include:
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services.
For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit https://netherlandsewell.com/.
About Haynes and Boone
Haynes and Boone, LLP is an energy focused corporate law firm, providing a full spectrum of legal services and solutions to clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. Lawyers from our Denver office and 15 other offices work as a team to meet the legal needs of our domestic and international clients involved in oil and gas. We represent private and public oil and gas companies, financial institutions, investment funds and other investors. Our team of more than 100 energy lawyers and landmen understands the physical and financial energy markets, and the firm has been helping both operators and lenders complete some of the largest financings and M&A transactions in recent years. The BTI Industry Power Rankings, published by BTI Consulting Group, Inc., named Haynes and Boone a "Leading Recommended" firm for the energy industry in 2017, ranking our firm among the top three percent of all law firms. For more information, please visit www.haynesboone.com/.
About CAC Specialty
CAC Specialty is an employee-owned risk solutions company of seasoned and proactive industry leaders, operating as a nimble and collaborative partner who puts you and your business first. With a knowledge-driven approach informed by data and decades of honed instinct, CAC Specialty brings an innovative vision to insurance broking, private finance and structured solutions to solve your risk challenges – from the simple to the previously unsolvable.
We are an integrated specialty insurance brokerage and structured solutions business focused on providing subject matter expertise and placement capabilities across the spectrum of insurance and alternative capital markets. CAC Specialty designs and delivers bespoke private finance and insurance solutions to public and private companies and private equity sponsors. We deliver unique solutions that help our clients facilitate the execution of strategic priorities, increase capital efficiency and significantly reduce costs. We are not constrained by traditional risk transfer thinking. Backed by a large $40B AUM asset manager, our team can expand the range of risk transfer through access to private debt and alternative pools of risk capital. For information on CAC Specialty, please visit the www.cacspecialty.com/.
About SitePro
At SitePro we discovered the missing link between facilities and human power is digital technology. Developed in 2012 by our team of experts in computer science, oilfield operations and engineering, our real-time cloud-based automation and IoT platform transformed fluid management in the industry. Our technology combines field operations with back-office responsibilities in one platform, allowing our customers to remotely control their sites, digitally manage their tickets and receive real-time data for reporting. To ensure the continued growth of our customers' businesses we knew we had to provide more operational support, in the form of managed services. Today we offer around-the-clock facility management acting as our customer's eyes, protecting their operations and enabling optimal production. The SitePro team continues to work towards our goal by developing solutions that help our customers operate efficiently and safely.
For information on SitePro, please visit the www.sitepro.com/.
View original content:http://www.prnewswire.com/news-releases/day-one-keynote-speaker-chris-wright-announced-for-enercom-dallas-energy-investment-conference-february-11-12-2020-300996588.html
SOURCE EnerCom, Inc.
CALGARY, Jan. 15, 2020 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on February 18, 2020 to all shareholders of record on January 31, 2020. The ex-dividend date for this payment is January 30, 2020. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada). As previously announced, we are phasing out the Dividend Reinvestment Plan ("DRIP") over the course of 2020. We will be prorating the available DRIP shares by 25% each quarter starting in Q1 2020, until completely eliminated in Q4 2020. For those investors that would like to continue reinvesting the cash portion of their dividends in Vermilion shares, we encourage you to contact your brokerage firm about setting up an automated reinvestment plan to purchase shares on the open market.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 13%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content to download multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-0-23-cdn-cash-dividend-for-february-18--2020-payment-date-300987100.html
SOURCE Vermilion Energy Inc.
DENVER, Jan. 8, 2020 /PRNewswire/ -- Institutional investors, portfolio managers, financial analysts, CIOs and other capital market professionals who invest in the energy space should register now for the EnerCom Dallas energy investment conference, which is coming to The Tower Club February 11-12 in downtown Dallas.
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors and sellside researchers to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists. The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. Key panel discussions include Environmental, Social and Governance (ESG), Capital Markets, LNG Landscape and Midstream.
New this year, the EnerCom Dallas conference is offering a unique session for energy related technology, alternative energy and traditional oil and gas start-up ventures to have the opportunity to present their business to a captive audience of investors. The event will provide invited presenters the opportunity to give a fifteen-minute presentation and participate in a Q&A. Investors can also schedule private one-on-one meetings with session participants at the Tower Club, Dallas.
EnerCom Dallas Presenting Companies Include:
The EnerCom Dallas Presenting Company Line-Up will be updated continuously on the conference website.
Registration for EnerCom Dallas is now open
Buyside professionals and oil and gas company executives may register for the event through the conference website.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2020.
Conference Dates: February 11-12, 2020
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Public and Private Company Presenters: EnerCom Dallas will feature both public and private companies headquartered in Canada and the U.S. with operations across the most active and prolific oil and gas regions and the globe.
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2020 marks EnerCom's 25th annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 50 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is an internationally recognized management consultancy advising companies on Environmental, Social & Governance (ESG), investor relations, corporate strategy/board advisory, marketing, analysis and valuation, media, branding, and visual communications design. Headquartered in Denver, EnerCom and its team of experts are passionate about the energy industry and our work to provide clients with wide range of services to build brand recognition that drives valuation and returns.
EnerCom's upcoming oil and gas investment conferences include:
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
Event Sponsors Include:
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services.
For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit https://netherlandsewell.com/.
About Haynes and Boone
Haynes and Boone, LLP is an energy focused corporate law firm, providing a full spectrum of legal services and solutions to clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. Lawyers from our Denver office and 15 other offices work as a team to meet the legal needs of our domestic and international clients involved in oil and gas. We represent private and public oil and gas companies, financial institutions, investment funds and other investors. Our team of more than 100 energy lawyers and landmen understands the physical and financial energy markets, and the firm has been helping both operators and lenders complete some of the largest financings and M&A transactions in recent years. The BTI Industry Power Rankings, published by BTI Consulting Group, Inc., named Haynes and Boone a "Leading Recommended" firm for the energy industry in 2017, ranking our firm among the top three percent of all law firms. For more information, please visit www.haynesboone.com/.
About CAC Specialty
CAC Specialty is an employee-owned risk solutions company of seasoned and proactive industry leaders, operating as a nimble and collaborative partner who puts you and your business first. With a knowledge-driven approach informed by data and decades of honed instinct, CAC Specialty brings an innovative vision to insurance broking, private finance and structured solutions to solve your risk challenges – from the simple to the previously unsolvable.
We are an integrated specialty insurance brokerage and structured solutions business focused on providing subject matter expertise and placement capabilities across the spectrum of insurance and alternative capital markets. CAC Specialty designs and delivers bespoke private finance and insurance solutions to public and private companies and private equity sponsors. We deliver unique solutions that help our clients facilitate the execution of strategic priorities, increase capital efficiency and significantly reduce costs. We are not constrained by traditional risk transfer thinking. Backed by a large $40B AUM asset manager, our team can expand the range of risk transfer through access to private debt and alternative pools of risk capital. For information on CAC Specialty, please visit the www.cacspecialty.com/.
About SitePro
At SitePro we discovered the missing link between facilities and human power is digital technology. Developed in 2012 by our team of experts in computer science, oilfield operations and engineering, our real-time cloud-based automation and IoT platform transformed fluid management in the industry. Our technology combines field operations with back-office responsibilities in one platform, allowing our customers to remotely control their sites, digitally manage their tickets and receive real-time data for reporting. To ensure the continued growth of our customers' businesses we knew we had to provide more operational support, in the form of managed services. Today we offer around-the-clock facility management acting as our customer's eyes, protecting their operations and enabling optimal production. The SitePro team continues to work towards our goal by developing solutions that help our customers operate efficiently and safely.
For information on SitePro, please visit the www.sitepro.com/.
View original content:http://www.prnewswire.com/news-releases/presenting-company-line-up-announced-for-enercom-dallas-energy-investment-conference-february-11-12-2020-300983772.html
SOURCE EnerCom, Inc.
DENVER, Dec. 18, 2019 /PRNewswire/ -- Institutional investors, portfolio managers, financial analysts, CIOs and other investment community professionals who invest in the energy space should register now for the EnerCom Dallas energy investment conference, which is coming to The Tower Club February 11-12 in downtown Dallas.
EnerCom Dallas is a financial conference that allows institutional investors an early 2020 opportunity to hear and meet CEOs from leading independent E&Ps, including some of the industry's leading Permian, Eagle Ford, Marcellus, Utica and Canadian producers and the oilfield service companies supporting them, discuss plans to drive development, fund operations and return value to shareholders in 2020.
Registration for EnerCom Dallas is now open
Buyside professionals and oil and gas company executives may register for the event through the conference website.
2019 proved to be a year where the energy industry continued to adapt, have constructive dialogues with capital parties and find ways to generate returns for investors. Companies are focused on improving their operations and having a relentless drive to continually be better stewards of their assets and the capital.
"EnerCom Dallas will give the buyside community an early opportunity to hear the leading independent oil and gas producers and service companies present their plans for 2020," said Aaron Vandeford, President of EnerCom. "Growing public expectations around Corporate Social Responsibility (CSR) has increased the emphasis by investors on making investments in companies that are actively addressing Environmental, Social and Governance (ESG) concerns. EnerCom will look to help facilitate this dialogue at our Dallas conference ahead of the proxy season."
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists. The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. The conference offers healthy dialogue and informal networking opportunities for attendees and presenters.
EnerCom Dallas is in its fourth year. Last year's EnerCom Dallas conference featured hundreds of investment community and oil and gas industry attendees.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2020.
Conference Dates: February 11, 12, 2020
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Public and Private Company Presenters: EnerCom Dallas will feature both public and private companies headquartered in Canada and the U.S. with operations across the most active and prolific oil and gas regions and the globe.
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2020 marks EnerCom's 25th annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 50 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is an internationally recognized management consultancy advising companies on Environmental, Social & Governance (ESG), investor relations, corporate strategy/board advisory, marketing, analysis and valuation, media, branding, and visual communications design. Headquartered in Denver, EnerCom and its team of experts are passionate about the energy industry and our work to provide clients with wide range of services to build brand recognition that drives valuation and returns.
EnerCom's upcoming oil and gas investment conferences include:
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
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SOURCE EnerCom, Inc.
CALGARY, Dec. 16, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on January 15, 2020 to all shareholders of record on December 31, 2019. The ex-dividend date for this payment is December 30, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 14%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Nov. 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on December 16, 2019 to all shareholders of record on November 27, 2019. The ex-dividend date for this payment is November 26, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 14.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Oct. 31, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three and nine months ended September 30, 2019.
The unaudited financial statements and management discussion and analysis for the three and nine months ended September 30, 2019, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) | Berak-01 well (100% working interest) tested at a rate of 17.2 mmcf/d during a four-hour flow period with a stabilized flowing wellhead pressure of 908 psi on a 0.875 inch diameter choke. A final shut in wellhead pressure of 1,186 psi was recorded following the flow test. The flow test continued an additional 12 hours at reduced choke sizes to minimize flaring. No formation water was produced during the test. The well logged 21 feet of net gas pay with an average porosity of 32% from the Upper Miocene Pannonian sandstone occurring within a gross measured depth interval of 3,006-3,033 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
($M except as indicated) | Q3 2019 | Q2 2019 | Q3 2018 | YTD 2019 | YTD 2018 | ||||||||||
Financial | |||||||||||||||
Petroleum and natural gas sales | 391,935 | 428,043 | 508,411 | 1,301,061 | 1,221,178 | ||||||||||
Fund flows from operations | 216,153 | 222,738 | 260,705 | 692,463 | 616,310 | ||||||||||
Fund flows from operations ($/basic share) (1) | 1.39 | 1.44 | 1.71 | 4.49 | 4.51 | ||||||||||
Fund flows from operations ($/diluted share) (1) | 1.39 | 1.42 | 1.69 | 4.45 | 4.46 | ||||||||||
Net earnings (loss) | (10,229) | 2,004 | (15,099) | 31,322 | (51,723) | ||||||||||
Net earnings (loss) ($/basic share) | (0.07) | 0.01 | (0.10) | 0.2 | (0.38) | ||||||||||
Capital expenditures | 127,879 | 92,607 | 146,185 | 422,539 | 354,634 | ||||||||||
Acquisitions | 4,657 | 8,623 | 198,173 | 29,307 | 1,756,736 | ||||||||||
Asset retirement obligations settled | 3,586 | 4,907 | 2,986 | 12,090 | 9,203 | ||||||||||
Cash dividends ($/share) | 0.690 | 0.690 | 0.690 | 2.070 | 2.025 | ||||||||||
Dividends declared | 107,176 | 106,884 | 105,192 | 319,609 | 282,801 | ||||||||||
% of fund flows from operations | 50 | % | 48 | % | 40 | % | 46 | % | 46 | % | |||||
Net dividends (1) | 98,316 | 98,111 | 100,872 | 294,872 | 238,865 | ||||||||||
% of fund flows from operations | 45 | % | 44 | % | 39 | % | 43 | % | 39 | % | |||||
Payout (1) | 229,781 | 195,625 | 250,043 | 729,501 | 602,702 | ||||||||||
% of fund flows from operations | 106 | % | 88 | % | 96 | % | 105 | % | 98 | % | |||||
Net debt | 2,001,870 | 1,950,509 | 2,034,086 | 2,001,870 | 2,034,086 | ||||||||||
Net debt to trailing twelve months fund flows from operations | 2.19 | 2.03 | 2.55 | 2.19 | 2.55 | ||||||||||
Operational | |||||||||||||||
Production | |||||||||||||||
Crude oil and condensate (bbls/d) | 47,242 | 48,964 | 47,152 | 48,455 | 36,318 | ||||||||||
NGLs (bbls/d) | 7,772 | 8,107 | 6,839 | 7,925 | 5,878 | ||||||||||
Natural gas (mmcf/d) | 253.36 | 275.60 | 253.38 | 268.88 | 241.42 | ||||||||||
Total (boe/d) | 97,239 | 103,003 | 96,222 | 101,193 | 82,433 | ||||||||||
Average realized prices | |||||||||||||||
Crude oil and condensate ($/bbl) | 73.45 | 79.46 | 85.84 | 75.38 | 84.98 | ||||||||||
NGLs ($/bbl) | 6.14 | 11.25 | 27.97 | 13.25 | 26.61 | ||||||||||
Natural gas ($/mcf) | 2.43 | 3.09 | 5.35 | 3.56 | 5.30 | ||||||||||
Production mix (% of production) | |||||||||||||||
% priced with reference to WTI | 39 | % | 38 | % | 37 | % | 38 | % | 30 | % | |||||
% priced with reference to Dated Brent | 19 | % | 18 | % | 18 | % | 18 | % | 21 | % | |||||
% priced with reference to AECO | 26 | % | 26 | % | 26 | % | 26 | % | 26 | % | |||||
% priced with reference to TTF and NBP | 16 | % | 18 | % | 19 | % | 18 | % | 23 | % | |||||
Netbacks ($/boe) | |||||||||||||||
Operating netback (1) | 28.22 | 29.62 | 34.85 | 29.80 | 33.26 | ||||||||||
Fund flows from operations netback | 23.73 | 24.15 | 29.69 | 24.89 | 27.59 | ||||||||||
Operating expenses | 11.55 | 11.04 | 11.13 | 11.85 | 10.94 | ||||||||||
General and administration expenses | 1.50 | 1.70 | 1.51 | 1.53 | 1.75 | ||||||||||
Average reference prices | |||||||||||||||
WTI (US $/bbl) | 56.45 | 59.81 | 69.50 | 57.06 | 66.75 | ||||||||||
Edmonton Sweet index (US $/bbl) | 51.79 | 55.19 | 62.68 | 52.34 | 60.69 | ||||||||||
Saskatchewan LSB index (US $/bbl) | 52.01 | 55.54 | 63.35 | 52.81 | 60.61 | ||||||||||
Dated Brent (US $/bbl) | 61.94 | 68.82 | 75.27 | 64.65 | 72.13 | ||||||||||
AECO ($/mcf) | 1.06 | 1.03 | 1.19 | 1.64 | 1.48 | ||||||||||
NBP ($/mcf) | 4.50 | 5.44 | 10.95 | 6.08 | 10.12 | ||||||||||
TTF ($/mcf) | 4.40 | 5.75 | 10.92 | 6.08 | 10.00 | ||||||||||
Average foreign currency exchange rates | |||||||||||||||
CDN $/US $ | 1.32 | 1.34 | 1.31 | 1.33 | 1.29 | ||||||||||
CDN $/Euro | 1.47 | 1.50 | 1.52 | 1.49 | 1.54 | ||||||||||
Share information ('000s) | |||||||||||||||
Shares outstanding - basic | 155,505 | 155,032 | 152,497 | 155,505 | 152,497 | ||||||||||
Shares outstanding - diluted (1) | 159,260 | 158,633 | 155,747 | 159,260 | 155,747 | ||||||||||
Weighted average shares outstanding - basic | 155,254 | 154,795 | 152,432 | 154,326 | 136,585 | ||||||||||
Weighted average shares outstanding - diluted (1) | 155,421 | 156,844 | 153,839 | 155,673 | 138,258 |
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Message to Shareholders
The third quarter of 2019 continued to be an exceptionally difficult period for energy investors, as the upstream oil and gas sector traded down to multi-year lows and significantly underperformed the broader equity market. Vermilion was not spared. Our stock price declined over 30% during the quarter, bringing our current dividend yield to approximately 14%. While we are certainly disappointed with our share price performance, we would like to stress that Vermilion's dividend policy is not based on the market price of our shares. Our dividend policy is based on the fundamental economic sustainability and free cash flow generation of our business, which remains strong.
The capital markets environment for oil and gas companies has changed dramatically over recent years due to a multitude of factors, including poor investment returns from energy issuers, increased focus on ESG and SRI mandates, and a growing concern about the future of fossil fuels amongst both investors and the general public. This has led to valuation multiple compression across the entire sector with many companies, including Vermilion, trading significantly below their historical valuation metrics. Despite these changing capital market dynamics, the oil and gas sector is a vital contributor to the global economy and will be around for many decades to support the long-term energy transition. During this transition, we believe there is significant value to be realized from responsible energy investment, and that Vermilion is optimally positioned to prosper in this industry and market environment. Our belief in Vermilion is founded in the economic sustainability of our business model and our leadership in environmental sustainability in the upstream oil and gas sector.
Throughout our 25-year history, we have repeatedly made the necessary adjustments to adapt to the changing landscape around us. Our business model has focused on sustainable growth and income, which we have successfully delivered to our shareholders over the years. Vermilion has paid over $39 per share in distributions and dividends since 2003 and generated compounded growth in production per share of over 8% annually since 2012. Our investment cycle time is short with minimal fixed commitments. Consequently, we have flexibility to adjust our investment and growth levels to provide the combination of return of capital and growth which we think will maximize shareholder value in a changing capital market environment. Based on the current market and commodity environment, we believe a strategy that is even more focused on free cash flow generation will create the most value for our shareholders. As such, for 2020, while maintaining our dividend at current levels, we have elected to reduce our production growth rate and to introduce additional flexibility in how we return capital to investors.
This lower growth strategy was embedded in the preparation of our 2020 budget as well as our capital plans for the remainder of 2019. For 2019, we have reduced capital investment by $10 million, and now expect to invest $520 million. As a result of this reduced level of investment and after accounting for higher-than-expected downtime and weather delays, we have correspondingly reduced our 2019 annual production guidance to 100,000 to 101,000 boe/d. We expect to deliver annual production at the mid-point of this revised guidance range, reflecting strong year-over-year production per share growth of 5%. Our Board of Directors has approved a 2020 capital budget of $450 million with associated production guidance of 100,000 to 103,000 boe/d. This budget is designed to deliver modest production growth of about 1%. The 2020 budget includes approximately $20 million of strategic capital associated with early-stage exploration and development activities. These activities will lay the groundwork for future development and production growth from a highly economic asset base.
During the third quarter we received approval from the TSX for a normal course issuer bid ("NCIB"), which will allow us to buy back up to 7.75 million shares. With this approval, we intend to use the NCIB in combination with debt reduction when we have excess free cash flow available (beyond dividends) to enhance per share growth. We will also be phasing out our DRIP over the course of the next year, prorating the available DRIP shares by 25% each quarter starting in Q1 2020 until the DRIP is completely eliminated in Q4 2020. The DRIP has been a shareholder service that we have provided since our first income distribution in 2003, with discounted share purchases offered until 2018. We recognize that the elimination of the DRIP may be a disappointment to some shareholders. Nonetheless, we feel that in an environment of lower trading commissions, the establishment of our NCIB, and lower energy issuer valuation multiples, the elimination of the DRIP is in the best interests of our broad shareholder group.
We remain committed to maximizing value for our shareholders over the long-term through a combination of a sustainable dividend, low financial leverage, share buybacks, and production growth as appropriate. In addition, we will remain disciplined in our acquisition strategy as we continue to evaluate strategic opportunities that fit within our business model and add value for existing shareholders. Our highest financial priority is our balance sheet, and under no circumstance will we do anything that jeopardizes Vermilion's long-term financial stability. We have a robust balance sheet with termed-out borrowing, strong liquidity, and a very low cost of debt. Coupled with low operating leverage due to high margins, a diversified product mix, and a strong hedge position, our balance sheet provides us with the flexibility to weather volatility in commodity prices.
Q3 2019 Operations Review
Our Q3 2019 operational results were impacted by several planned turnarounds, a high level of unplanned downtime, weather related delays and a moderate carry-over impact from the refinery outage in France. As a result, our Q3 2019 production decreased 6% from the prior quarter to 97,239 boe/d, with variances discussed by business unit below. We generated FFO of $216 million in the third quarter, down by 3% from the prior quarter, with positive contributions from hedging gains, lower G&A expense, and lower taxes partially offsetting lower production and commodity prices.
Europe
In France, Q3 2019 production averaged 10,347 boe/d, an increase of 6% from the prior quarter. Production volumes in the Paris Basin returned to near full capacity in mid-August following the restart of the Grandpuits refinery which had been offline due to a failure on its main feedstock pipeline. Most of our wells in the Paris Basin have returned to pre-shutdown production levels, although some wells continue to clean up and workover activity is continuing to restore full productivity. The net impact from the refinery outage reduced our Q3 2019 production volumes by approximately 400 boe/d. In the Aquitaine Basin, production was consistent with the prior quarter as we successfully completed our 2019 workover campaign, which continues to yield results above our expectations.
In the Netherlands, Q3 2019 production averaged 7,429 boe/d, a decrease of 17% from the prior quarter. The decrease was primarily due to a planned turnaround and unexpected downtime to repair a gas compressor, which extended the length of the turnaround. The combined impact was a reduction in Netherlands production of approximately 1,200 boe/d in Q3 2019. Our facilities have returned to service and production has been restored. We are currently in the process of drilling the Weststellingwerf well (0.5 net), representing our first drilling activity in the Netherlands since 2017, and we expect drilling to be completed before the end of the year.
In Ireland, production averaged 43 mmcf/d (7,202 boe/d) in Q3 2019, a decrease of 12% from the prior quarter. The decrease was primarily due to planned and unplanned downtime at the Corrib natural gas processing facility and natural decline. Our planned turnaround was successfully completed as scheduled in mid-September. Later in the month, we identified the need for repairs in one of the plant auxiliary systems which necessitated shutting the plant down for approximately 10 days spanning the end of Q3 and early Q4 2019. The combined impact of the planned and unplanned downtime was approximately 800 boe/d in Q3.
In Germany, production in Q3 2019 averaged 3,269 boe/d, a decrease of 6% from the prior quarter. The decrease was primarily due to unplanned downtime on several operated and non-operated assets, partially offset by contributions from successful workovers performed earlier this year. Following the successful drilling of the Burgmoor Z5 (46% working interest) well, completed early in the third quarter of 2019, we continue to evaluate tie-in alternatives and expect to bring the well on production in late 2020.
In Central and Eastern Europe ("CEE"), we drilled one (1.0 net) natural gas exploration well in Croatia during Q3 2019, which resulted in a second consecutive gas discovery, testing at a rate of 17.2 mmcf/d(2). During the third quarter, we were also provisionally awarded the SA-07 license in Croatia, which is contiguous with our existing land position and will add approximately 500,000 net acres to our portfolio in the country. Vermilion continues to be the largest onshore landholder in Croatia, with total licensed acreage of approximately 2.4 million net acres, including the new SA-07 block. In Hungary, we began tie-in activities for the Mh-21 (0.3 net) and Battonya E-09 (1.0 net) wells, drilled in the second and third quarters of 2019, respectively, and expect to bring them on production during the fourth quarter of 2019.
North America
In Canada, production averaged 58,504 boe/d in Q3 2019, a decrease of 5% from the prior quarter. The decrease was primarily due to planned turnarounds (700 boe/d impact) and project delays caused by abnormally wet weather (2,100 boe/d impact). We drilled or participated in 40 (38.3 net) wells in the third quarter of 2019, all of which were drilled in Saskatchewan, as no drilling in Alberta was possible due to wet conditions throughout the summer. Well activity in Alberta, including tie-in and completions, was delayed until late September due to extremely wet ground, three months later than when we typically resume post-break-up activity. We brought 41 (36.2 net) wells on production in Saskatchewan and three (2.5 net) wells on production in Alberta during the quarter. We have continued to realize capital and operating efficiencies in our southeast Saskatchewan assets, achieving a 10% improvement in drilling, completion, equipping and tie-in ("DCET") costs on our Q3 2019 open-hole drilling program compared to our Q1 2019 program.
In the United States, Q3 2019 production averaged 4,925 boe/d, representing an increase of 12% from the prior quarter. The increase was primarily driven by production contributions from our 2019 Hilight drilling campaign, as we successfully completed and brought on production four (4.0 net) wells during the third quarter. The increased production was partially offset by planned and unplanned third-party gas plant maintenance, which reduced production by approximately 200 boe/d. The first two wells drilled in the quarter were brought on production in late August and achieved an average peak IP30 rate of approximately 600 boe/d per well (86% oil and NGLs). The other two wells were brought on production at the end of September and are currently producing at an average rate of approximately 500 boe/d per well (92% oil and NGLs). We continue to progress along the learning curve in reducing costs since our Hilight acquisition one year ago, with a 20% DCET cost reduction in our H2 2019 program to-date compared to our H1 2019 program. As a result of these cost savings, we have added two (1.5 net) wells to our 2019 program and plan to drill these wells in Q4 2019.
Australia
In Australia, production averaged 5,564 bbl/d in Q3 2019, a decrease of 17% from the previous quarter, primarily due to well management and unplanned vessel maintenance on the Wandoo platform. We plan to conduct facility upgrades in Q4 2019 to increase fluid handling capacity, which will necessitate a shutdown of the Wandoo platform for an estimated eight days in the fourth quarter of 2019.
2020 Budget
Our Board of Directors has approved an exploration and development capital expenditure budget of $450 million, with associated production guidance of 100,000 to 103,000 boe/d. As previously communicated, we are placing less emphasis on production growth as we navigate the current commodity price and capital markets environment.
We plan to drill 13 (8.7 net) wells in Europe. In addition, we plan to continue significant workover programs in France, Netherlands and Germany, and facility optimization in Ireland. The capital budget includes approximately $20 million of strategic, non-production-adding capital invested to facilitate our long-term future growth plans in Europe.
In North America, our activity will focus on our three core areas of southeast Saskatchewan (light oil), west-central Alberta (condensate-rich natural gas), and the Powder River Basin in Wyoming (light oil). We have made significant progress on improving the capital and operating efficiencies on the North American assets we acquired in 2018, and we plan to continue that trend in 2020.
Assuming WTI oil prices remain at approximately US$55/bbl in 2020, and holding all other commodities at the October 11, 2019 commodity strip, we would more than cover our dividend and capital investment. Excess cash generated beyond our capital program and dividend commitment will be allocated to a combination of debt reduction and share buybacks. Our top financial priorities in 2020 will be balance sheet and dividend protection, and we maintain the capital investment flexibility to reduce capital outlays if required by lower commodity prices.
Europe
In France, our 2020 E&D capital budget of $57 million represents a 23% reduction from our 2019 spending. While we do not intend to invest in any new wells in 2020, we plan to continue with our workover and asset optimization programs in both the Paris and Aquitaine Basins. These workover programs are expected to maintain production at roughly the same level in 2020 as we have averaged in 2019.
Our 2020 E&D budget in the Netherlands of $18 million represents a 22% decrease from 2019. While significant progress has been made on our permitting efforts, we will plan for modest growth in the Netherlands in 2020 as we reschedule our slate of capital projects in the context of a lower corporate growth rate target. We plan to drill or participate in three (0.6 net) wells. Assuming success on the Weststellingwerf well (0.5 net) currently being drilled, we plan to bring this well on production during the first half of 2020. We will continue to advance our well permitting throughout the year in order to compile a backlog of projects for implementation beginning in 2021.
In Ireland, we plan to invest approximately $3 million of E&D capital in 2020 as we continue to focus on facility maintenance and compression optimization.
In Germany, our 2020 E&D capital budget of $18 million represents a decrease of 18% year-over-year. In addition to our planned workover and facility program, we plan to drill sidetracks in three (3.0 net) of our operated oil wells and begin drilling activities on one (0.6 net) exploratory gas prospect.
In Central and Eastern Europe, our 2020 E&D budget will be approximately the same as in 2019, building on the success we had in 2019 and laying the groundwork for future growth. We plan to invest $20 million in E&D capital expenditures in 2020. While the majority of this capital program will be focused on following-up our successful 2019 drilling program, a portion of the budget will be directed to strategic infrastructure investments in Croatia and Slovakia, notably the commencement of construction of natural gas compression facilities in each country. In 2020, we plan to drill six (4.5 net) wells in CEE comprised of two (2.0 net) wells in Croatia, one (1.0 net) well in Hungary and three (1.5 net) wells in Slovakia.
North America
In Canada, we plan to invest $250 million of E&D capital in 2020, a decrease of 14% from our 2019 capital program. We plan to drill 107 (95.5 net) wells in Canada in 2020, comprised of 87 (76.3 net) light oil wells in southeast Saskatchewan and 20 (19.2 net) wells in Alberta. In addition to the drilling program, we will also continue to focus on our waterflood program in southeast Saskatchewan, as well as production and facility optimization opportunities, as we have in previous years.
In the United States, our 2020 E&D capital budget of $59 million represents a 4% increase from our 2019 capital program. We plan to drill 10 (9.6 net) wells on our Hilight asset in Wyoming. This expanded drilling program will allow us to capitalize on the efficiencies we have achieved since the Hilight acquisition and to continue to increase production in the Powder River Basin.
Australia
In Australia, our 2020 E&D budget of $25 million will focus primarily on workovers and facility modifications to increase artificial lift capacity and facility throughput.
E&D Capital Investment by Country
Country | 2020 Budget* | 2019 Budget | 2020 vs. 2019 | 2020 | 2020 | |
Canada | 250 | 292 | (14) | % | 107 | 95.5 |
France | 57 | 74 | (23) | % | — | — |
Netherlands | 18 | 23 | (22) | % | 3 | 0.6 |
Germany | 18 | 22 | (18) | % | 4 | 3.6 |
Ireland | 3 | 1 | 200 | % | — | — |
Australia | 25 | 31 | (19) | % | — | — |
USA | 59 | 57 | 4 | % | 10 | 9.6 |
Central and Eastern Europe | 20 | 20 | — | % | 6 | 4.5 |
Total E&D Capital Expenditures | 450 | 520 | (13) | % | 130 | 113.8 |
E&D Capital Investment by Category
Category | 2020 Budget* | 2019 Budget | 2020 vs. 2019 | |||
Drilling, completion, new well equipment and tie-in, workovers and recompletions | 350 | 380 | (8) | % | ||
Production equipment and facilities | 70 | 100 | (30) | % | ||
Seismic, land and other | 30 | 40 | (25) | % | ||
Total E&D Capital Expenditures | 450 | 520 | (13) | % |
*2020 Budget reflects foreign exchange assumptions of CAD/USD 1.32, CAD/EUR 1.48, and CAD/AUD 0.90.
Dividend Reinvestment Plan
We have elected to phase out the Dividend Reinvestment Plan ("DRIP"), prorating the available DRIP shares by 25% each quarter starting in Q1 2020. It is our intention to increase this proration each quarter throughout next year, such that the DRIP will be eliminated by the fourth quarter of 2020.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows, providing additional certainty with regard to the execution of our dividend and capital programs. In aggregate, as of October 29, 2019, we currently have 51% of our expected net-of-royalty production hedged for Q4 2019. More than half of our Q4 2019 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases up to contract ceilings. For 2020, approximately one-third of our production is hedged, with 54% of our hedge position in participating structures.
With respect to individual products within our product mix, we have currently hedged 74% of anticipated European natural gas volumes for Q4 2019. We have also hedged 75% of our anticipated full-year 2020 European natural gas volumes at prices which are expected to provide for strong project economics and free cash flows. At present, 47% of our expected Q4 oil production is hedged. For Q4 2019, 51% of our North American natural gas production is priced away from AECO, due to diversification hedges to financially sell at the SoCal Border and at Henry Hub for a portion of our Alberta natural gas production, and because 16% of our North American gas production is located in Saskatchewan and Wyoming.
Sustainability
Vermilion received top quartile rankings for 2019 for our industry sector in both the Sustainalytics ESG Rating and SAM (formerly known as RobecoSAM) annual Corporate Sustainability Assessment ("CSA"). These agencies analyze sustainability performance across economic, environmental, governance and social criteria, and the CSA is also the basis of the Dow Jones Sustainability Indices. We believe the integration of sustainability principles into our business is the right thing to do, increases shareholder return, and reduces long-term risks to our business model. These ratings demonstrate our commitment to maintaining leadership in sustainability and ESG performance. Our 2019 Sustainability Report is available on our corporate website at: http://sustainability.vermilionenergy.com.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
October 30, 2019
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) | Berak-01 well (100% working interest) tested at a rate of 17.2 mmcf/d during a four-hour flow period with a stabilized flowing wellhead pressure of 908 psi on a 0.875 inch diameter choke. A final shut in wellhead pressure of 1,186 psi was recorded following the flow test. The flow test continued an additional 12 hours at reduced choke sizes to minimize flaring. No formation water was produced during the test. The well logged 21 feet of net gas pay with an average porosity of 32% from the Upper Miocene Pannonian sandstone occurring within a gross measured depth interval of 3,006-3,033 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call on Thursday, October 31, 2019 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using the conference ID 2090807 from October 31, 2019 at 12:00 MST to November 14, 2019 at 21:59 MST.
You may also access the webcast at https://event.on24.com/wcc/r/2114194/1C4F8D98D22708487A065827392F4760. The webcast link can be found on Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm under upcoming events.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 14.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
This document contains metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, Oct. 17, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) announced today it will release its 2019 third quarter operating and condensed financial results on Thursday, October 31, 2019 before the open of North American markets. The unaudited financial statements and management discussion and analysis for the three and nine months ended September 30, 2019 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and webcast presentation on Thursday, October 31, 2019 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using the conference ID 2090807 from October 31, 2019 at 12:00 MST to November 14, 2019 at 21:59 MST.
You may also access the webcast at https://event.on24.com/wcc/r/2114194/1C4F8D98D22708487A065827392F4760. The webcast link, along with conference call slides, will be available on Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm under Upcoming Events prior to the conference call.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 13.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Oct. 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on November 15, 2019 to all shareholders of record on October 31, 2019. The ex-dividend date for this payment is October 30, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 14%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Sept. 16, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on October 15, 2019 to all shareholders of record on September 30, 2019. The ex-dividend date for this payment is September 27, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 12.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Aug. 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on September 16, 2019 to all shareholders of record on August 30, 2019. The ex-dividend date for this payment is August 29, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 14%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Aug. 7, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce that the Toronto Stock Exchange ("TSX") has approved the notice of Vermilion's intention to commence a normal course issuer bid ("NCIB").
The NCIB allows Vermilion to purchase up to 7,750,000 common shares (representing approximately 5% of its 155,161,464 outstanding common shares as of July 31, 2019) over a twelve month period commencing on August 9, 2019. The NCIB will expire no later than August 8, 2020. Under the NCIB, common shares may be repurchased in open market transactions on the TSX and other alternative trading platforms in Canada and in accordance with the rules of the TSX governing NCIB's. The total number of common shares Vermilion is permitted to purchase is subject to a daily purchase limit of 267,558 common shares, representing 25% of the average daily trading volume of 1,070,233 common shares on the TSX calculated for the six-month period ended July 31, 2019; however, Vermilion may make one block purchase per calendar week which exceeds the daily repurchase restrictions. Any common shares that are purchased under the NCIB will be cancelled upon their purchase by Vermilion.
Since 2003, Vermilion has had a track record of returning capital to shareholders through our monthly dividend (previously a cash distribution during the trust era). We also recognize that other forms of returning capital to shareholders, such as share buybacks, may be appropriate to complement our dividend in certain market conditions. We intend to utilize the NCIB under conditions in which we have excess free cash flow available after dividends, with that excess cash allocated both to debt reduction and buybacks.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 13.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: number of shares to be purchased under the NCIB; intended use of the NCIB; and future plans regarding the uses of excess free cash flow.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
This document contains metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, July 29, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three and six months ended June 30, 2019.
The unaudited financial statements and management discussion and analysis for the three and six months ended June 30, 2019, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. | |
(2) | Burgmoor Z5 well (46% working interest) tested at a final flow rate of 8.8 mmcf/d at a flowing wellhead pressure of 431 psi, with the rate limited by weather conditions during a 30 hour clean-up flow. The well produced at a final rate of 480 bbls/d of drilling and completion load fluid during clean-up operations, but is not expected to produce meaningful amounts of formation water under long-term producing conditions. The flowing wellhead pressure continued to increase during the clean-up period and was 431 psi immediately prior to being shut-in. The well encountered 125 feet of net pay in the Permian Zechstein Carbonate from 11,014-11,276 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. | |
(3) | Hajdubagos-01 well (100% working interest) tested at a flow rate of 1.4 mmcf/d of natural gas with 55 barrels per day of 60° API condensate with no formation water during a 12 hour flow test on a 0.374 inch choke with a stabilized flowing wellhead pressure of 590 psi. The well encountered 15 feet of net pay in an Upper Miocene Pannonian sandstone at depths from 6,517-6,550 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. | |
(4) | Mh-21 well (30% working interest) tested at a flow rate of 2.0 mmcf/d with no formation water during a six hour flow test with a stabilized flowing wellhead pressure of 543 psi on a 0.43 inch choke. The well encountered 26 feet of net pay in an Upper Miocene Pannonian sandstone at depths from 2,901-2,930 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. | |
(5) | Battonya E-09 well (100% working interest) tested at a flow rate of 3.4 mmcf/d with no formation water during an eight hour flow test with a stabilized flowing wellhead pressure of 739 psi on a 0.47 inch choke. The well encountered 17 feet of net pay in an Upper Miocene Pannonian sandstone from 2,448-2,476 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. | |
(6) | Ceric-01 well (100% working interest) tested at a final flow rate of 15.0 mmcf/d at a stabilized flowing wellhead pressure of 851 psi on a 0.86 inch diameter choke during a one hour flow period following perforating. An additional 18 hour flow test was later conducted at reduced rates to limit flaring. During this test, the well flowed at a rate of 6.2 mmcf/d at a stabilized flowing pressure of 1,376 psi on a 0.37 inch choke. No formation water was produced during the tests. The well encountered 32 feet of net pay in two Upper Miocene Pannonian sandstones from 3,346-3,353 and 3,828-3,861 feet. Only the lower zone was tested. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
($M except as indicated) | Q2 2019 | Q1 2019 | Q2 2018 | YTD 2019 | YTD 2018 | ||||||||||
Financial | |||||||||||||||
Petroleum and natural gas sales | 428,043 | 481,083 | 394,498 | 909,126 | 712,767 | ||||||||||
Fund flows from operations | 222,738 | 253,572 | 195,190 | 476,310 | 355,605 | ||||||||||
Fund flows from operations ($/basic share) (1) | 1.44 | 1.66 | 1.45 | 3.10 | 2.77 | ||||||||||
Fund flows from operations ($/diluted share) (1) | 1.42 | 1.64 | 1.43 | 3.07 | 2.73 | ||||||||||
Net earnings (loss) | 2,004 | 39,547 | (61,364) | 41,551 | (36,624) | ||||||||||
Net earnings (loss) ($/basic share) | 0.01 | 0.26 | (0.46) | 0.27 | (0.28) | ||||||||||
Capital expenditures | 92,607 | 202,053 | 79,984 | 294,660 | 208,449 | ||||||||||
Acquisitions | 8,623 | 16,027 | 1,465,485 | 24,650 | 1,558,563 | ||||||||||
Asset retirement obligations settled | 4,907 | 3,597 | 2,626 | 8,504 | 6,217 | ||||||||||
Cash dividends ($/share) | 0.690 | 0.690 | 0.690 | 1.380 | 1.335 | ||||||||||
Dividends declared | 106,884 | 105,549 | 98,604 | 212,433 | 177,609 | ||||||||||
% of fund flows from operations | 48% | 42% | 51% | 45% | 50% | ||||||||||
Net dividends (1) | 98,111 | 98,445 | 78,629 | 196,556 | 137,993 | ||||||||||
% of fund flows from operations | 44% | 39% | 40% | 41% | 39% | ||||||||||
Payout (1) | 195,625 | 304,095 | 161,239 | 499,720 | 352,659 | ||||||||||
% of fund flows from operations | 88% | 120% | 83% | 105% | 99% | ||||||||||
Net debt | 1,950,509 | 2,000,144 | 1,796,807 | 1,950,509 | 1,796,807 | ||||||||||
Ratio of net debt to annualized fund flows from operations | 2.19 | 1.97 | 2.30 | 2.05 | 2.53 | ||||||||||
Operational | |||||||||||||||
Production | |||||||||||||||
Crude oil and condensate (bbls/d) | 48,964 | 49,181 | 34,574 | 49,072 | 30,812 | ||||||||||
NGLs (bbls/d) | 8,107 | 7,897 | 5,651 | 8,002 | 5,390 | ||||||||||
Natural gas (mmcf/d) | 275.60 | 277.96 | 242.40 | 276.77 | 235.34 | ||||||||||
Total (boe/d) | 103,003 | 103,404 | 80,625 | 103,203 | 75,425 | ||||||||||
Average realized prices | |||||||||||||||
Crude oil and condensate ($/bbl) | 79.46 | 73.45 | 87.50 | 76.36 | 84.32 | ||||||||||
NGLs ($/bbl) | 11.25 | 22.49 | 26.06 | 16.76 | 25.73 | ||||||||||
Natural gas ($/mcf) | 3.09 | 5.10 | 4.77 | 4.09 | 5.27 | ||||||||||
Production mix (% of production) | |||||||||||||||
% priced with reference to WTI | 38% | 37% | 29% | 37% | 25% | ||||||||||
% priced with reference to Dated Brent | 18% | 18% | 21% | 19% | 23% | ||||||||||
% priced with reference to AECO | 26% | 26% | 26% | 26% | 26% | ||||||||||
% priced with reference to TTF and NBP | 18% | 19% | 24% | 18% | 26% | ||||||||||
Netbacks ($/boe) | |||||||||||||||
Operating netback (1) | 29.62 | 31.50 | 33.03 | 30.57 | 32.22 | ||||||||||
Fund flows from operations netback | 24.15 | 26.76 | 26.58 | 25.46 | 26.20 | ||||||||||
Operating expenses | 11.04 | 12.92 | 10.75 | 11.99 | 10.82 | ||||||||||
General and administration expenses | 1.70 | 1.38 | 1.93 | 1.54 | 1.91 | ||||||||||
Average reference prices | |||||||||||||||
WTI (US $/bbl) | 59.81 | 54.90 | 67.88 | 57.36 | 65.37 | ||||||||||
Edmonton Sweet index (US $/bbl) | 55.19 | 50.05 | 62.43 | 52.62 | 59.70 | ||||||||||
Saskatchewan LSB index (US $/bbl) | 55.54 | 50.84 | 61.84 | 53.19 | 59.23 | ||||||||||
Dated Brent (US $/bbl) | 68.82 | 63.20 | 74.35 | 66.01 | 70.55 | ||||||||||
AECO ($/mcf) | 1.03 | 2.62 | 1.18 | 1.83 | 1.63 | ||||||||||
NBP ($/mcf) | 5.44 | 8.33 | 9.42 | 6.89 | 9.69 | ||||||||||
TTF ($/mcf) | 5.75 | 8.14 | 9.50 | 6.94 | 9.54 | ||||||||||
Average foreign currency exchange rates | |||||||||||||||
CDN $/US $ | 1.34 | 1.33 | 1.29 | 1.33 | 1.28 | ||||||||||
CDN $/Euro | 1.50 | 1.51 | 1.54 | 1.51 | 1.55 | ||||||||||
Share information ('000s) | |||||||||||||||
Shares outstanding - basic | 155,032 | 153,213 | 152,363 | 155,032 | 152,363 | ||||||||||
Shares outstanding - diluted (1) | 158,633 | 156,650 | 155,355 | 158,633 | 155,355 | ||||||||||
Weighted average shares outstanding - basic | 154,795 | 152,904 | 134,603 | 153,855 | 128,531 | ||||||||||
Weighted average shares outstanding - diluted (1) | 156,844 | 154,550 | 136,559 | 155,335 | 130,224 |
(1) The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
Message to Shareholders
During the second quarter, we conducted our most active exploration drilling program in Europe in the history of the company. Over the past four months, we have drilled one exploration well in Germany and five exploration wells in our Central and Eastern European ("CEE") business unit, with successes on all but one well in Hungary. This drilling campaign was preceded by several years of careful implementation of our new country entry strategy. We entered Germany in 2014 and initially focused on expanding our land position through various acquisitions, farm-ins and government concessions, and we now have approximately 1.2 million net acres of land, comprising about one-quarter of the prolific North German Basin. The first few years were focused on building our team and executing on low risk development opportunities on the existing producing assets while evaluating future exploration and development prospects. Following the successful completion of our first operated drilling in Germany this summer, we now plan to drill at least one exploration well in Germany each year over the next several years, targeting other sizable gas prospects in the basin.
We followed a similar approach when we entered Central and Eastern Europe later in 2014. We acquired land in the Pannonian Basin in Hungary, Croatia and Slovakia through various government concessions and deals with industry partners. Our initial focus was on building our knowledge of the basin and operating environment, while acquiring and evaluating seismic to identify future drilling prospects. This summer's drilling program has yielded four conventional discoveries in Hungary and Croatia in five exploratory attempts. We look forward to executing the remainder of our Croatian program and to initiating our Slovakian program later this year.
Subsequent to the second quarter, we further expanded our CEE presence as we were awarded two exploration licenses in Ukraine in partnership with Ukrgazvydobuvannya ("UGV", a Ukrainian state owned gas producer) in the prolific Dnieper-Donets Basin. These two licenses are in close proximity to several multi-TCF gas fields with most of the basin (and awarded license areas) still not covered by 3D seismic. Entering Ukraine aligns with our strategy to capitalize on opportunities in under-exploited basins by using modern technologies to improve success rates and recovery.
In addition to our Germany and CEE exploration drilling programs, we are also currently preparing to drill the first well (0.5 net) of our two (1.0 net) well 2019 program in the Netherlands after having received permits for these wells in the second quarter. Netherlands continues to be a strong free cash flow generating business and we look forward to resuming drilling there after a two-year hiatus.
Our second quarter results were negatively impacted by a third-party refinery outage in France which reduced production and forced us to find alternate transportation methods and delivery points for our oil in the Paris Basin, which is the larger of our two producing regions in the country. Our French team did an exceptional job of contracting for alternate delivery points for most of our production, and conducting the required long-haul trucking and barging in a safe manner. Despite the refinery outage, which impacted quarterly production volumes by approximately 1,300 boe/d and FFO by approximately $11 million, we recorded corporate production of approximately 103,000 boe/d, little changed from the previous quarter.
We recorded FFO of $223 million in Q2 2019, down 12% from the prior quarter. In addition to the France refinery impact, the primary drivers for this lower FFO were the timing of crude lifting in Australia, which resulted in an inventory build and lower sales volumes ($8 million impact), and weaker natural gas prices in Europe and North America ($33 million impact).
We were able to mitigate a portion of this pricing variance through our hedging program, particularly in European gas, realizing a $14 million pre-tax gain during the quarter. European gas prices weakened this summer due to increased LNG deliveries. However, we have locked in pricing on approximately 70% of our summer European gas at significantly higher prices than the spot price. The forward price for European gas remains in strong contango compared to the front month price, with the calendar 2020 strip for NBP at approximately $8.50/mmbtu, and calendar year strips for the next three years are currently trading within approximately 1% of where they were one year ago. While our fundamental view on European gas is that the forward market realistically reflects supply and demand drivers, we are willing to lock in this curve and attendant strong levels of free cash flow and expected project economics. Accordingly, we have already hedged 65% of our expected 2020 European gas production, with hedges continuing at lower percentages on into 2022.
Since 2003, Vermilion has had a track record of returning capital to shareholders through our monthly dividend (previously a cash distribution during the trust era). This distribution and dividend stream has been increased four times and has never been reduced. We also recognize that other forms of returning capital to shareholders, such as share buybacks, may be appropriate to complement our dividend in certain market conditions. With this in mind, our Board of Directors has authorized an application to the TSX to implement a normal course issuer bid ("NCIB") for a maximum amount of 5% of the issued and outstanding shares of Vermilion. We intend to use the NCIB to return capital to our shareholders, augmenting our current return of cash through dividends. We will also continue to allocate a portion of excess free cash flow to debt reduction.
Q2 2019 Operations Review
Europe
In France, Q2 2019 production averaged 9,800 boe/d, a decrease of 15% from the prior quarter. Our production in the Paris Basin was temporarily curtailed as a result of a third party refinery outage due to a failure on the refinery's main feedstock line. The Grandpuits refinery, where all of our Paris Basin production is processed, returned to service in late July, and has resumed processing Vermilion deliveries. During the refinery outage, we made arrangements to ship most of our oil to alternate delivery points in France and Germany utilizing trucks and barges. The net impact from the refinery outage reduced our Q2 2019 production volumes by approximately 1,300 boe/d and after-tax FFO by approximately $11 million ($0.07/share) from reduced sales and higher transportation expense. In addition, approximately $2 million in capital investment was required to put truck and barge loading equipment in place.
In the Netherlands, Q2 2019 production averaged 8,917 boe/d, an increase of 3% from the prior quarter. The increase is primarily due to the successful completion of our first half 2019 workover and facility maintenance program, which was partially offset by minor downtime. During the second quarter we received the draft drilling permit for the Waalwijk South well (0.5 net), the second well in our planned 2019 drilling program. We recently began site construction for the first well of our 2019 program, the Weststellingwerf well (0.5 net), which is expected to commence drilling in August 2019. Drilling of the Waalwijk South well is expected to begin in Q4 2019.
In Ireland, production averaged 49 mmcf/d (8,201 boe/d) in Q2 2019, a decrease of 4.8% from the prior quarter. The decrease was due to natural decline and minor unplanned downtime at the Corrib natural gas processing facility. Since we took over as operator of the Corrib Project late in 2018, operating costs have decreased 14% over the comparative six-month period. At present, our efforts are focused on evaluating future facility and drilling projects, and optimizing our maintenance activities, including a scheduled plant turnaround in Q3 2019.
In Germany, production in Q2 2019 averaged 3,474 boe/d, a decrease of 8% from the prior quarter. The decrease is primarily due to unplanned downtime on several operated and non-operated assets, which was partially offset by a full quarter contribution from various well workovers performed on our operated oil assets earlier this year. During the quarter, we completed drilling our first exploratory well in Germany, the Burgmoor Z5 well (46% working interest). The well reached a measured depth of 11,480 feet and encountered 125 feet of net pay in the Zechstein carbonate. The well was tested at the end of July at a final flow rate of 8.8 mmcf/d(2) limited by weather conditions. The Burgmoor Z5 well has been turned over to ExxonMobil as operator during the testing and production phases. We also completed and brought on production a non-operated coil tubing sidetrack (0.25 net) during the quarter.
In Central and Eastern Europe, we drilled four (3.3 net) exploration wells during Q2 2019, and one (1.0 net) subsequent to the end of the quarter. Four of these wells resulted in new gas discoveries. In Hungary, we drilled four (3.3 net) exploration wells, the first (1.0 net) of which was dry. The second well (1.0 net) of our 2019 Hungary drilling program encountered 15 feet of net gas pay and tested at a rate of 1.4 mmcf/d and 55 bbls/d(3) of condensate. The third well (0.3 net) encountered 26 feet of net gas pay, and tested at a rate of 2.0 mmcf/d(4) in July. The fourth Hungarian well (1.0 net) was drilled and tested in July, encountering 17 feet of net gas pay and testing at 3.4 mmcf/d(5). In Croatia, we drilled our first natural gas exploration well (1.0 net) in the country which encountered 32 feet of net gas pay in two zones. Subsequent to the end of the quarter, it tested 15.0 mmcf/d(6) from the lower zone.
Subsequent to the end of the second quarter, we were awarded two exploration licenses in Ukraine, subject to a final production sharing agreement, in a 50/50 partnership with Ukrgazvydobuvannya ("UGV", a Ukrainian state owned gas producer). The licenses cover approximately 585,000 gross acres situated in one of Europe's most prolific natural gas regions (Dnieper-Donets Basin). The new licenses are in close proximity to several multi-TCF gas fields with most of the basin (and awarded license areas) still uncovered by 3D seismic. The terms of the licenses include a modest capital commitment, back-loaded over a five-year time frame.
North America
In Canada, production averaged 61,507 boe/d in Q2 2019, up slightly from the prior quarter. The increase was primarily due to the contribution from our first quarter drilling program in Saskatchewan and Alberta, partially offset by unplanned facility downtime and less drilling activity in the second quarter due to spring breakup. We drilled or participated in 28 (22.9 net) wells in the second quarter of 2019, including 27 (22.4 net) wells in Saskatchewan and one (0.5 net) Mannville well in Alberta. We brought six (6.0 net) wells on production in Saskatchewan and one (1.0 net) well in Alberta during the quarter. During the second half of the year, we plan to drill 73 (62.7 net) wells in Saskatchewan and six (4.2 net) wells in Alberta, in addition to completing several plant turnarounds in Alberta in Q3 2019. We are currently operating four drilling rigs in Saskatchewan, but have been delayed in resuming Alberta activity due to wet weather conditions.
In the United States, Q2 2019 production averaged 4,414 boe/d, representing an increase of 21% from the prior quarter. The increase was primarily driven by production contributions from our first half 2019 Hilight drilling campaign, in which four (4.0 net) wells were completed and brought on production during the quarter. The first two wells were equipped with rod pumps and brought on production in mid-April. These wells have performed ahead of our expectations, producing in excess of our rod-pump type curve through the end of the quarter, and achieving an average peak IP30 rate of approximately 325 boe/d to date, with production still on a modest incline in one of the wells. The two subsequent wells were equipped with electric submersible pumps ("ESP") and were brought on production in mid-May. These two wells have also performed ahead of our expectations by approximately 150 bbls/d on average, while achieving an average peak IP30 rate of approximately 635 boe/d per well. We recently mobilized a rig that we had been using on our Canadian operations to Wyoming for our remaining (4.0 net) Hilight wells planned for this year. The fifth well of the program was spud toward the end of Q2 2019 and was drilled in less than 12 days, representing a 28% improvement over the fastest H1 2019 well. Since taking over operatorship last year, we have achieved a 15% reduction in DCET costs, and expect another 10% improvement in the remaining wells this year.
Australia
In Australia, production averaged 6,689 bbl/d in Q2 2019, an increase of 14% from the previous quarter primarily due to contributions from the two (2.0 net) well drilling program completed at the end of January 2019. We continue to manage our Australian production to our annual production target of 6,000 bbl/d.
Cross Currency Interest Rate Swaps
On June 12, 2019, Vermilion entered into a series of cross currency interest rate swaps with a syndicate of banks, financially swapping the remaining term of our 5.625% US$300 million senior unsecured notes due March 2025 into a €265 million obligation bearing interest at 3.275%. At current foreign exchange rates, this swap is expected to reduce our annual cash interest costs by approximately $9 million.
Credit Rating
On July 26, 2019, Fitch Ratings initiated a credit rating for Vermilion. The corporate first-time Long-Term Issuer Default Rating was initiated at a BB- with a stable outlook and the BB- rating was assigned to the issued and outstanding senior unsecured notes due March 2025.
Normal Course Issuer Bid
Our Board of Directors has authorized an application to the TSX to implement a normal course issuer bid ("NCIB") for a maximum amount of 5% of the issued and outstanding shares of Vermilion, which we plan to use as an additional means of returning capital to shareholders under appropriate market conditions. The NCIB is intended to augment our ongoing return of capital via dividends. We plan to allocate excess free cash flow beyond our dividend stream to both debt reduction and buybacks.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows, providing additional certainty with regard to the execution of our dividend and capital programs. In aggregate, as of July 25, 2019, we currently have 40% of our expected net-of-royalty production hedged for Q3 2019. More than half of our Q3 2019 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases up to contract ceilings. For 2020, approximately 70% of our hedge position is in participating structures.
We have currently hedged 71% of anticipated European natural gas volumes for Q3 2019. We have also hedged 69% and 65% of our anticipated full-year 2019 and 2020 European natural gas volumes, respectively, at prices which are expected to provide for strong project economics and free cash flows. At present, 33% of both our expected Q3 2019 and Q4 2019 oil production is hedged. For Q3 2019, 45% of our North American natural gas production is priced away from AECO, due to diversification hedges to financially sell at the SoCal Border and at Henry Hub for a portion of our Alberta natural gas production, and because 15% of our North American gas production is located in Saskatchewan and Wyoming.
Sustainability
Vermilion was recently rated "AA" in MSCI's annual ESG rankings for 2019, placing us in the top 19% of oil and gas companies worldwide. This rating is an improvement from "A" in the previous two years. MSCI ESG Research LLC is the world's largest provider of ESG ratings and research, rating over 13,000 equity and income issuers. Its research is used globally to help investors understand how ESG factors can impact the long-term risk and return profile of their investments. Our increased rating is the result of improving company ESG performance and enhanced disclosure on topics relevant to MSCI's detailed assessment process.
Organizational Update
Mr. Kyle Preston, previously our Director of Investor Relations, has been promoted to the position of Vice President of Investor Relations. He joined Vermilion in 2016 and has over 20 years of experience in oil and gas finance, including 13 years as an equity research analyst. Mr. Preston has played a key role in developing and executing our differentiated capital markets strategy. He holds the Chartered Financial Analyst® and Certified Management Accountant designations and earned a Bachelor of Commerce degree from the University of Manitoba.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
July 25, 2019
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
(2) | Burgmoor Z5 well (46% working interest) tested at a final flow rate of 8.8 mmcf/d at a flowing wellhead pressure of 431 psi, with the rate limited by weather conditions during a 30 hour clean-up flow. The well produced at a final rate of 480 bbls/d of drilling and completion load fluid during clean-up operations, but is not expected to produce meaningful amounts of formation water under long-term producing conditions. The flowing wellhead pressure continued to increase during the clean-up period and was 431 psi immediately prior to being shut-in. The well encountered 125 feet of net pay in the Permian Zechstein Carbonate from 11,014-11,276 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
(3) | Hajdubagos-01 well (100% working interest) tested at a flow rate of 1.4 mmcf/d of natural gas with 55 barrels per day of 60° API condensate with no formation water during a 12 hour flow test on a 0.374 inch choke with a stabilized flowing wellhead pressure of 590 psi. The well encountered 15 feet of net pay in an Upper Miocene Pannonian sandstone at depths from 6,517-6,550 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
(4) | Mh-21 well (30% working interest) tested at a flow rate of 2.0 mmcf/d with no formation water during a six hour flow test with a stabilized flowing wellhead pressure of 543 psi on a 0.43 inch choke. The well encountered 26 feet of net pay in an Upper Miocene Pannonian sandstone at depths from 2,901-2,930 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
(5) | Battonya E-09 well (100% working interest) tested at a flow rate of 3.4 mmcf/d with no formation water during an eight hour flow test with a stabilized flowing wellhead pressure of 739 psi on a 0.47 inch choke. The well encountered 17 feet of net pay in an Upper Miocene Pannonian sandstone from 2,448-2,476 feet. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
(6) | Ceric-01 well (100% working interest) tested at a final flow rate of 15.0 mmcf/d at a stabilized flowing wellhead pressure of 851 psi on a 0.86 inch diameter choke during a one hour flow period following perforating. An additional 18 hour flow test was later conducted at reduced rates to limit flaring. During this test, the well flowed at a rate of 6.2 mmcf/d at a stabilized flowing pressure of 1,376 psi on a 0.37 inch choke. No formation water was produced during the tests. The well encountered 32 feet of net pay in two Upper Miocene Pannonian sandstones from 3,346-3,353 and 3,828-3,861 feet. Only the lower zone was tested. Test results are not necessarily indicative of long-term performance or ultimate recovery. |
Guidance
On October 25, 2018, we released our 2019 capital budget and related guidance. On February 27, 2019, we deferred some activity to later in the year and reallocated capital between business units, although the 2019 total budget and production guidance remained unchanged.
The following table summarizes our guidance:
Date | Capital Expenditures ($MM) | Production (boe/d) | ||||
2019 Guidance | ||||||
2019 Guidance | October 25, 2018 | 530 | 101,000 to 106,000 |
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and webcast presentation on Monday, July 29, 2019 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using the conference ID 4454959 from July 29, 2019 at 12:00 MST to August 12, 2019 at 21:59 MST.
You may also access the webcast at https://event.on24.com/wcc/r/2034202/D763FFCE3D2CBFC02220C1DD1B0A63FB. The webcast link, along with conference call slides, can be found on Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm under Upcoming Events prior to the conference call.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 11.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
This document contains metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, July 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on August 15, 2019 to all shareholders of record on July 31, 2019. The ex-dividend date for this payment is July 30, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 9.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, July 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) announced today it will release its 2019 second quarter operating and condensed financial results on Monday, July 29, 2019 before the open of North American markets. The unaudited financial statements and management discussion and analysis for the three and six months ended June 30, 2019 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and webcast presentation on Monday, July 29, 2019 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using the conference ID 4454959 from July 29, 2019 at 12:00 PM MST to August 12, 2019 at 9:59 PM MST.
You may also access the webcast at https://event.on24.com/wcc/r/2034202/D763FFCE3D2CBFC02220C1DD1B0A63FB. The webcast link, along with conference call slides, will be available on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the conference call.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 9.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content to download multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-confirms-second-quarter-2019-release-date-and-conference-call-and-webcast-details-300884589.html
SOURCE Vermilion Energy Inc.
CALGARY, June 17, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on July 15, 2019 to all shareholders of record on June 28, 2019. The ex-dividend date for this payment is June 27, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 10.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content to download multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-0-23-cdn-cash-dividend-for-july-15--2019-payment-date-300869332.html
SOURCE Vermilion Energy Inc.
DENVER, June 12, 2019 /PRNewswire/ -- EnerCom has released the presentation schedule for the oil and gas companies presenting at its 24th annual The Oil & Gas Conference® on Aug. 11-14, 2019, in Denver, Colorado.
Day One Presenting Companies at the 2019 EnerCom Conference
Aug. 12, 2019, the first day of the EnerCom conference presentation schedule, features a large, established group of operators working across North America's shale basins and internationally, including:
The conference investor presentations begin at 7:30 a.m. and run through 4:30 p.m. on Monday, Aug. 12.
Expert Speakers: Global energy industry leaders, economists, market strategists, government officials, energy finance professionals and other energy experts will provide their insights on global commodities markets, energy exports, frac sand supply and logistics, and capital sources for energy development.
EnerCom is pleased to include Credit Agricole CIB's Chief Economist for the United States Michael Carey as a guest expert speaker at 11:30 a.m. on Monday, Aug. 12. Carey will provide his insight on energy markets, capital markets and market conditions going forward.
Monday's luncheon keynote address on Aug. 12, 2019 will be provided by Cedric Burgher, Occidental Petroleum (NYSE: OXY) CFO.
Online Registration is Open for EnerCom's 24TH Annual The Oil & Gas Conference®: Buyside investors and oil and gas company professionals may register for the event through the conference website registration page.
Conference Details: The Oil & Gas Conference® 24 offers investment professionals the opportunity to listen to senior management teams in the oil and gas industry present operational and financial strategies and to gain exposure to important energy topics affecting the global oil and gas industry.
The EnerCom conference forum fosters healthy dialogue and informal networking opportunities for attendees at several sponsored events the week of the conference.
Public and Private Company Presenters: The 2019 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations around the world including the U.S. shale basins, the Gulf of Mexico and Canada. A work-in-progress list of the 2019 presenting companies will be updated on the conference website. The daily schedule of presenters is also posted on the website (presenters, days, times are subject to change).
How to Hear the Luncheon Speakers: Completing online registration well in advance of The Oil & Gas Conference® will provide your best chance to gain insight from Occidental Petroleum SVP and chief financial officer Cedric Burgher, Continental Resources Chairman and CEO Harold Hamm, and global supermajor Eni, SpA VP of North America Investor Relations Andrew Lees.
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, family offices, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2018, EnerCom arranged and managed more than 2,000 one-on-one meeting requests.
How to Register: Investment professionals and oil and gas companies may register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; and Drillinginfo. Sponsors of The Oil & Gas Conference® 24 include CIBC; Credit Agricole CIB; McGriff, Seibels & Williams; Haynes and Boone; Moss Adams; PNC; Preng & Associates; Bank of America Merrill Lynch; DNB Bank ASA; Holland & Hart; MUFG; Petrie Partners; SMBC; and Wells Fargo.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized management consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor relations, media relations, external communications and visual communications design.
EnerCom produces and publishes numerous data products and external communications tools for public energy companies and oil and gas investors including:
Headquartered in Denver, with senior consultants in Dallas, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries. EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 11-14, 2019
EnerCom Dallas – Q1 - 2020
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About Drillinginfo
Drillinginfo delivers business-critical insights to the energy, power, and commodities markets. Its state-of-the-art SaaS platform offers sophisticated technology, powerful analytics, and industry-leading data. Drillinginfo's solutions deliver value across upstream, midstream and downstream markets, empowering exploration and production (E&P), oilfield services, midstream, utilities, trading and risk, and capital markets companies to be more collaborative, efficient, and competitive. Drillinginfo delivers actionable intelligence over mobile, web, and desktop to analyze and reduce risk, conduct competitive benchmarking, and uncover market insights. Drillinginfo serves over 5,000 companies globally from its Austin, Texas headquarters and has more than 1,000 employees.
For more information visit drillinginfo.com
About CIBC
CIBC is a leading Canadian-based global financial institution with a reputation as a strong, reliable banking partner focused on delivering customized products and services built on innovative thinking and leading technology.
Through our major business units – Canadian Personal & Business Banking, Canadian Commercial Banking & Wealth Management, U.S. Commercial Banking & Wealth Management and Capital Markets – our more than 45,000 employees provide a full range of financial products and services to 10 million clients around the world.
With offices throughout North America and other major financial centers, we are widely recognized as a strong global financial institution with more than $634 billion in assets and a market capitalization of $50 billion. We are rated A+ by Standard & Poor's, Aa2 by Moody's Investor Service and AA- by Fitch Ratings.
Our dedicated industry specialists based in Houston, New York, Calgary, London, Hong Kong, Beijing, Tokyo, Singapore and Sydney draw on the breadth of our capabilities to support firms across the entire energy value chain. From credit commitments, A&D advisory, M&A, and capital markets, we help our clients achieve their objectives and unlock value across a range of market conditions.
Visit www.cibccm.com/energy to learn more about CIBC Capital Markets and our energy capabilities.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
McGriff, Seibels & Williams
As one of the most progressive insurance brokerage firms in the United States, McGriff, Seibels & Williams leads the way with innovative programs to protect our clients' financial interests. Our experienced professionals work with some of the world's largest corporations to design state-of-the-art solutions for a full range of needs "…from property and casualty exposures…to employee benefits, life and pension plans…to financial services and surety products…to specialty insurance programs."
Our philosophy of personal service and attention to individual needs puts the client at the top of our organizational chart. We work to make each relationship a long-term partnership that continues to grow in value.
For more information please visit mcgriff.com.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group. With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Holland & Hart
Holland & Hart's oil and gas clients include the major, large independent producers and small to medium sized independents.
The Mountain West is one of the nation's leading oil and gas producing regions, and we are the only law firm with established oil and gas lawyers in every state in the region. We provide clients broad-based, in-depth industry knowledge and legal capabilities by local practitioners who have long-standing professional relationships with decision makers in each of the Mountain West states.
We assist clients at every stage of the oil and gas business, from upstream activities including exploration, production, secondary and tertiary recovery, to midstream gathering and processing activities; and to downstream elements including refining, pipelines, local distribution, marketing, and Federal and State utility regulation. Within each segment of the oil and gas business, Holland & Hart's regional team has experience providing representation every step of the way.
For details, please contact Lisa Adelberg in the Denver office: (303) 295-8148.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Petrie Partners
Petrie Partners, LLC is a boutique investment banking firm offering financial advisory services to the oil and gas industry. We provide specialized advice on mergers, divestitures and acquisitions and private placements.
For more information please refer to petrie.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
About Wells Fargo & Company
Wells Fargo & Company (NYSE: WFC) is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
View original content:http://www.prnewswire.com/news-releases/enercom-posts-schedule-of-presenters-for-the-oil--gas-conference-aug-11-14-2019-300866065.html
SOURCE EnerCom, Inc.
CALGARY, April 26, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to announce that at its annual meeting of shareholders held on April 25, 2019 each of the ten nominees were elected as directors of the Company.
The detailed results of the vote by ballot are as follows:
Name of Nominee | Votes For | Votes Withheld | ||
Number | Percent (%) | Number | Percent (%) | |
Lorenzo Donadeo | 86,392,453 | 96.67% | 2,971,409 | 3.33% |
Larry J. Macdonald | 83,500,415 | 93.44% | 5,863,447 | 6.56% |
Carin A. Knickel | 87,453,428 | 97.86% | 1,910,434 | 2.14% |
Stephen P. Larke | 86,706,021 | 97.03% | 2,657,841 | 2.97% |
Loren M. Leiker | 89,106,037 | 99.71% | 257,825 | 0.29% |
Dr. Timothy R. Marchant | 89,131,134 | 99.74% | 232,328 | 0.26% |
Anthony Marino | 89,115,223 | 99.72% | 248,639 | 0.28% |
Robert Michaleski | 86,138,346 | 96.39% | 3,225,516 | 3.61% |
William B. Roby | 88,875,205 | 99.45% | 488,657 | 0.55% |
Catherine L. Williams | 86,708,713 | 97.03% | 2,655,149 | 2.97% |
For complete voting results, please see our Report of Voting Results available through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.
An archive webcast of the annual meeting of shareholders presentation by Anthony Marino, President & CEO, that provides a business overview and an update on recent developments, is available on Vermilion's website at www.vermilionenergy.com.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada and Germany and a certified Great Place to Work in France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content to download multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-reports-voting-results-of-election-of-directors-300839328.html
SOURCE Vermilion Energy Inc.
CALGARY, April 25, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three months ended March 31, 2019.
The unaudited financial statements and management discussion and analysis for the three months ended March 31, 2019, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
($M except as indicated) | Q1 2019 | Q4 2018 | Q1 2018 | ||
Financial | |||||
Petroleum and natural gas sales | 481,083 | 456,939 | 318,269 | ||
Fund flows from operations | 253,572 | 222,342 | 160,415 | ||
Fund flows from operations ($/basic share) (1) | 1.66 | 1.45 | 1.31 | ||
Fund flows from operations ($/diluted share) (1) | 1.64 | 1.44 | 1.29 | ||
Net earnings (loss) | 39,547 | 323,373 | 24,740 | ||
Net earnings (loss) ($/basic share) | 0.26 | 2.12 | 0.20 | ||
Capital expenditures | 202,053 | 163,580 | 128,465 | ||
Acquisitions | 16,027 | 2,689 | 93,078 | ||
Asset retirement obligations settled | 3,597 | 6,562 | 3,591 | ||
Cash dividends ($/share) | 0.690 | 0.690 | 0.645 | ||
Dividends declared | 105,549 | 105,310 | 79,005 | ||
% of fund flows from operations | 42% | 47% | 49% | ||
Net dividends (1) | 98,445 | 100,195 | 59,364 | ||
% of fund flows from operations | 39% | 45% | 37% | ||
Payout (1) | 304,095 | 270,337 | 191,420 | ||
% of fund flows from operations | 120% | 122% | 119% | ||
Net debt | 2,000,144 | 1,929,529 | 1,525,562 | ||
Ratio of net debt to annualized fund flows from operations | 1.97 | 2.17 | 2.38 | ||
Operational | |||||
Production | |||||
Crude oil and condensate (bbls/d) | 49,181 | 47,678 | 27,008 | ||
NGLs (bbls/d) | 7,897 | 7,815 | 5,126 | ||
Natural gas (mmcf/d) | 277.96 | 276.77 | 228.20 | ||
Total (boe/d) | 103,404 | 101,621 | 70,167 | ||
Average realized prices | |||||
Crude oil and condensate ($/bbl) | 73.45 | 66.19 | 80.03 | ||
NGLs ($/bbl) | 22.49 | 25.69 | 25.37 | ||
Natural gas ($/mcf) | 5.10 | 5.83 | 5.81 | ||
Production mix (% of production) | |||||
% priced with reference to WTI | 37% | 37% | 21% | ||
% priced with reference to Dated Brent | 18% | 18% | 24% | ||
% priced with reference to AECO | 26% | 26% | 26% | ||
% priced with reference to TTF and NBP | 19% | 19% | 29% | ||
Netbacks ($/boe) | |||||
Operating netback (1) | 31.50 | 27.58 | 31.27 | ||
Fund flows from operations netback | 26.76 | 23.79 | 25.77 | ||
Operating expenses | 12.92 | 12.04 | 10.90 | ||
General and administration expenses | 1.38 | 1.37 | 1.88 | ||
Average reference prices | |||||
WTI (US $/bbl) | 54.90 | 58.81 | 62.87 | ||
Edmonton Sweet index (US $/bbl) | 50.05 | 32.51 | 56.98 | ||
Saskatchewan LSB index (US $/bbl) | 50.84 | 44.03 | 56.63 | ||
Dated Brent (US $/bbl) | 63.20 | 67.76 | 66.76 | ||
AECO ($/mcf) | 2.62 | 1.56 | 2.08 | ||
NBP ($/mcf) | 8.33 | 11.03 | 9.96 | ||
TTF ($/mcf) | 8.14 | 10.91 | 9.59 | ||
Average foreign currency exchange rates | |||||
CDN $/US $ | 1.33 | 1.32 | 1.26 | ||
CDN $/Euro | 1.51 | 1.51 | 1.55 | ||
Share information ('000s) | |||||
Shares outstanding - basic | 153,213 | 152,704 | 122,769 | ||
Shares outstanding - diluted (1) | 156,650 | 156,173 | 125,794 | ||
Weighted average shares outstanding - basic | 152,904 | 152,588 | 122,390 | ||
Weighted average shares outstanding - diluted (1) | 154,550 | 153,880 | 124,304 | ||
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
Message to Shareholders
We delivered strong operational and financial results in Q1 2019. Production increased 2% quarter-over-quarter to 103,404 boe/d and FFO increased 14% from the prior quarter to $254 million. While global benchmark commodity prices were weaker in Q1 2019 compared to the prior quarter, we benefited from a significant improvement in Canadian benchmark prices and continued positive operational momentum across our asset base. On a per share basis we generated $1.66(1) of FFO in Q1 2019 compared to $1.31 in Q1 2018, representing a year-over-year increase of 27% despite most commodity benchmark prices being lower over this comparative period, reflecting accretion from the acquisitions we completed in 2018 and our ongoing organic development activities. Our Australian and Canadian business units were responsible for most of the growth in Q1 2019 as we brought two new offshore wells on production in Australia and executed one of our most active drilling programs to date in Canada. We achieved increased production despite an unusually active cyclone season in Australia, which resulted in 11 days of downtime at Wandoo and extremely cold weather conditions in our producing areas in Canada and the US.
We are committed to our capital markets strategy of sustainable growth and income. With all business units contributing strong development results to-date and most completion and tie-in activities in North America completed at break-up, we expect to deliver robust year-over-year production per share growth in 2019 of 8% or more, while paying a sustainable dividend which is currently yielding approximately 8%. We typically have a front-loaded capital program which seeks to finish as much Canadian drilling and tie-in activity ahead of break-up as possible, and this year was no exception, with nearly 40% of our annual capital investment for Exploration and Development ("E&D") activities executed in Q1 2019. As a result, our total payout ratio exceeded 100% for the quarter. However, based on the current commodity strip, our annual capital program and dividend are more than fully funded with a forecasted total payout ratio of approximately 90%. As we have previously indicated, our intent is to allocate any excess cash generated beyond the capital program and dividend towards debt reduction, targeting a debt-to-FFO leverage ratio of 1.5 times or lower. In Q2 2019, we negotiated an extension to our $2.1 billion revolving credit facility to extend the maturity to May 31, 2023. The closing of the amendment is expected to take place before the end of April, 2019.
Q1 2019 Operations Review
Europe
In France, Q1 2019 production averaged 11,470 boe/d, which was up slightly from the prior quarter. Initial results from our 2019 workover program have exceeded our expectations, with one recompletion in the Aquitaine Basin yielding an initial 30-day rate of 600 bbls/d. Production contributions from the 2018 drilling program in the Champotran field continue to outperform internal estimates. Our 2019 Champotran drilling program commenced during the first quarter, as we drilled and completed three (3.0 net) wells. These wells are expected to be brought on production in late April, while drilling of the final (1.0 net) well of the program is ongoing.
In the Netherlands, Q1 2019 production averaged 8,677 boe/d, representing a 1% decrease from the prior quarter. We continue to make progress on the permitting for our two (1.0 net) 2019 planned wells. We received the drilling permit for the Weststellingwerf well during the first quarter, and are currently awaiting regulatory decisions on two additional wells, which should enable us to execute our planned two-well program for this year.
In Ireland, production averaged approximately 52 mmcf/d (8,619 boe/d) in Q1 2019, a decrease of 1% from the prior quarter. We completed some minor projects and activities previously identified to increase uptime and optimize plant compression to increase gas throughput. We will continue to evaluate other optimization opportunities throughout 2019 as we build more first-hand knowledge as operator.
In Germany, production in Q1 2019 averaged 3,763 boe/d, an increase of 1% from the prior quarter. The increase is primarily due to better than expected results from workovers performed on our operated oil assets. Late in the quarter, we commenced drilling the Burgmoor Z5 well (46% working interest), marking the first operated drill by Vermilion in Germany. Drilling is expected to conclude around mid-year, with well testing thereafter. We have identified several other sizeable exploration prospects on our German land base and intend to drill at least one new well per year for the foreseeable future.
In Central and Eastern Europe ("CEE"), we had no production in the quarter. The Mh-Ny-07 well in Hungary watered out at its current location, and we are evaluating the economics of sidetracking the well to access remaining gas at a higher structural location. We have received all necessary permits for the 2019 Hungarian drilling program and are making steady progress on permitting for our Croatia and Slovakia drilling programs. We plan a 10 (7.0 net) well 2019 drilling program for Central and Eastern Europe and remain very confident in the growth outlook for this region.
North America
In Canada, production averaged 61,360 boe/d in Q1 2019, an increase of 1% from the prior quarter. The production increase was driven by continued strong operating performance across our Canadian assets including positive results from our drilling programs in both Saskatchewan and Alberta. We drilled or participated in 58 (54.9 net) wells in the first quarter of 2019, including 45 (41.9 net) wells in Saskatchewan and 12 (12.0 net) Mannville wells in Alberta. In Saskatchewan, we tied in 40 wells from the Q1 program. Of the wells that have been on production for more than 15 days, we achieved an average rate of 162 boe/d (71% oil) on the Midale wells and 109 boe/d (90% oil) on the open hole Frobisher wells. In Alberta, we tied in 11 wells from the Q1 program, including ten Mannville wells that have been on production for more than 15 days achieving an average rate of 790 boe/d (40% oil, condensate and NGLs). The results from our Q1 2019 drilling program in both Saskatchewan and Alberta continue to perform at or above our expectations.
In the United States, Q1 2019 production averaged 3,653 boe/d, an increase of 3% from the prior quarter. The increase was primarily due to a full quarter contribution from our first Hilight well drilled in the prior quarter, which continues to perform in line with our expectations. We commenced our 2019 eight (7.6 net) well drilling program in the Hilight Turner Sands by drilling three (3.0 net) horizontal wells during the quarter. We are in the process of completing and testing these wells and plan to drill the remaining five (4.6 net) Hilight wells in the second and third quarters.
Australia
In Australia, production averaged 5,862 bbl/d in Q1 2019, an increase of 40% from the previous quarter primarily due to the contribution from the two (2.0 net) well program completed at the end of January 2019. The wells began producing in early February 2019 and continue to perform in line with our expectations. We produce these two wells intermittently at restricted rates in order to maximize long-term value and to manage to our annual production target of 6,000 bbl/d. Production in Q1 2019 was partially offset by weather related downtime, as two cyclones resulted in the platform being shut down for 11 days during the quarter.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of our cash flows, providing additional certainty with regard to the execution of our dividend and capital programs. In aggregate, as of April 23, 2019, we currently have 33% of our expected net-of-royalty production hedged for Q2 2019. Over half of the Q2 2019 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases, up to contract ceilings.
We have currently hedged 69% of anticipated European natural gas volumes for Q2 2019. We have also hedged 66% and 49% of our anticipated full-year 2019 and 2020 European natural gas volumes, respectively, at prices which are expected to provide for strong project economics and free cash flows. At present 30% of our Q2 2019, and 26% of our full year 2019 oil production is hedged. For Q2 2019, 27% of our North American natural gas production is priced away from AECO, due to diversification hedges to financially sell at the SoCal Border and at Henry Hub for a portion of our Alberta natural gas production, and because 14% of our North American production is located in Saskatchewan and Wyoming.
Sustainability
Sustainability is central to Vermilion's corporate strategy, as illustrated by the constitution of our Sustainability Committee by Vermilion's Board of Directors. We are pleased to note continued external confirmation of our progress in this realm. Our ISS Governance QualityScore increased from 3 to 2 (where a decile score of 1 indicates lowest governance risk), while our Environment and Social QualityScores remain at 1 and 2 respectively. This reflects our ongoing dedication to strong performance on ESG factors.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
April 25, 2019
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
Guidance
On October 25, 2018, we released our 2019 capital budget and related guidance. The 2019 total budget and production guidance remain unchanged, although we have deferred some activity to later in the year and reallocated capital between business units, the breakdown of which can be found in our corporate presentation located on our website.
The following table summarizes our guidance:
Date | Capital Expenditures ($MM) | Production (boe/d) | |||
2019 Guidance | |||||
2019 Guidance | October 25, 2018 | 530 | 101,000 to 106,000 |
Annual General Meeting Webcast
As Vermilion's Annual General Shareholders Meeting is being held today, April 25th, 2019 at 3:00 pm MDT in the Ballroom of the Metropolitan Centre, 333 – 4th Avenue SW, Calgary, Alberta, there will not be a first quarter conference call. In lieu of the conference call, a presentation will be given by Anthony Marino, President & Chief Executive Officer, after the conclusion of formal business at approximately 3:15 pm MDT.
Shareholders who are not able to join the event in person may access the meeting by webcast at https://event.on24.com/wcc/r/1963826/3A2A3F4C79C314F3346A6F5C563BA36A. The webcast link, along with the webcast slides, will be available on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the webcast.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 7.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
This document contains metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, April 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on May 15, 2019 to all shareholders of record on April 30, 2019. The ex-dividend date for this payment is April 29, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, April 11, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) announced today it will release its 2019 first quarter operating and condensed financial results on Thursday, April 25, 2019 after the close of North American markets. The unaudited financial statements and management discussion and analysis for the first quarter ended March 31, 2019 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Annual General Meeting and Webcast Details
Vermilion will hold its Annual General Meeting on April 25, 2019 at 3:00 pm MDT in the Ballroom of the Metropolitan Centre, 333 – 4th Avenue SW, Calgary, Alberta. At the end of the meeting, at approximately 3:15 PM MDT, a presentation will be given by Anthony Marino, President & Chief Executive Officer. Shareholders who are not able to join the event in person may access the meeting by webcast at https://event.on24.com/wcc/r/1963826/3A2A3F4C79C314F3346A6F5C563BA36A. The webcast link, along with the webcast slides, will be available on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the webcast.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, March 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on April 15, 2019 to all shareholders of record on March 29, 2019. The ex-dividend date for this payment is March 28, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Feb. 28, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and financial results for the year ended December 31, 2018 along with our 2018 reserves and resources information.
The audited financial statements, management discussion and analysis, and annual information form for the year ended December 31, 2018, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. |
(2) | B15ST1 well tested oil at an average rate of 8,769 bbls/d and zero barrels of water per day ("bwpd") over a 48-hour period at a flowing wellhead pressure of 900 kpa (130 psi) on a 100% open choke (130 mm or 5.1 inch diameter) with applied gas-lift of 22,000 m3/d (775 mcf/d). The well was estimated to be flowing with a 30% drawdown of reservoir pressure. |
B16ST2 well tested oil at an average rate of 7,600 bbls/d and 770 bwpd over a 36-hour period at a flowing wellhead pressure of 900 kpa (130 psi) on a 100% open choke (130 mm or 5.1 inch diameter) with applied gas-lift of 45,000 m3/d (1,590 mcf/d). The well was estimated to be flowing with a 15% drawdown of reservoir pressure. | |
(3) | Estimated proved and proved plus probable reserves as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 7, 2019 with an effective date of December 31, 2018 (the "2018 GLJ Reserves Report"). |
(4) | F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted FDC (future development capital), by the change in the reserves, incorporating revisions and production, for the same period. |
(5) | Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(6) | Vermilion retained GLJ to conduct an independent resource evaluation dated February 7, 2019 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2018 (the "GLJ 2018 Resources Report"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 82%, 81% and 81%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 24%, 23% and 24%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development. Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. Prospective resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. Please refer to Vermilion's 2018 Annual Information Form for further information on Vermilion's contingent resources and prospectus resources. |
($M except as indicated) | Q4 2018 | Q3 2018 | Q4 2017 | 2018 | 2017 | ||||||||||
Financial | |||||||||||||||
Petroleum and natural gas sales | 456,939 | 508,411 | 317,341 | 1,678,117 | 1,098,838 | ||||||||||
Fund flows from operations | 222,342 | 260,705 | 181,253 | 838,652 | 602,565 | ||||||||||
Fund flows from operations ($/basic share) (1) | 1.46 | 1.71 | 1.49 | 5.96 | 5 | ||||||||||
Fund flows from operations ($/diluted share) (1) | 1.44 | 1.69 | 1.47 | 5.89 | 4.92 | ||||||||||
Net earnings (loss) | 323,373 | (15,099) | 8,645 | 271,650 | 62,258 | ||||||||||
Net earnings (loss) ($/basic share) | 2.12 | (0.1) | 0.07 | 1.93 | 0.52 | ||||||||||
Capital expenditures | 163,580 | 146,185 | 74,303 | 518,214 | 320,449 | ||||||||||
Acquisitions | 2,689 | 198,173 | 3,048 | 1,759,425 | 27,637 | ||||||||||
Asset retirement obligations settled | 6,562 | 2,986 | 3,216 | 15,765 | 9,334 | ||||||||||
Cash dividends ($/share) | 0.690 | 0.690 | 0.645 | 2.715 | 2.580 | ||||||||||
Dividends declared | 105,310 | 105,192 | 78,653 | 388,111 | 311,397 | ||||||||||
% of fund flows from operations | 47% | 40% | 43% | 46% | 52% | ||||||||||
Net dividends (1) | 100,195 | 100,872 | 56,836 | 339,060 | 200,904 | ||||||||||
% of fund flows from operations | 45% | 39% | 31% | 40% | 33% | ||||||||||
Payout (1) | 270,337 | 250,043 | 134,355 | 873,039 | 530,687 | ||||||||||
% of fund flows from operations | 122% | 96% | 74% | 104% | 88% | ||||||||||
Net debt | 1,929,529 | 2,034,086 | 1,371,790 | 1,929,529 | 1,371,790 | ||||||||||
Ratio of net debt to annualized fund flows from operations | 2.17 | 1.95 | 1.89 | 2.30 | 2.28 | ||||||||||
Operational | |||||||||||||||
Production | |||||||||||||||
Crude oil and condensate (bbls/d) | 47,678 | 47,152 | 27,830 | 39,182 | 27,721 | ||||||||||
NGLs (bbls/d) | 7,815 | 6,839 | 5,279 | 6,366 | 4,194 | ||||||||||
Natural gas (mmcf/d) | 276.77 | 253.38 | 238.27 | 250.33 | 216.64 | ||||||||||
Total (boe/d) | 101,621 | 96,222 | 72,821 | 87,270 | 68,021 | ||||||||||
Average realized prices | |||||||||||||||
Crude oil and condensate ($/bbl) | 66.19 | 85.84 | 74.12 | 79.16 | 67.00 | ||||||||||
NGLs ($/bbl) | 25.69 | 27.97 | 29.28 | 26.33 | 25.00 | ||||||||||
Natural gas ($/mcf) | 5.83 | 5.35 | 5.23 | 5.45 | 4.91 | ||||||||||
Production mix (% of production) | |||||||||||||||
% priced with reference to WTI | 37% | 37% | 21% | 32% | 20% | ||||||||||
% priced with reference to Dated Brent | 18% | 18% | 24% | 20% | 26% | ||||||||||
% priced with reference to AECO | 26% | 26% | 25% | 26% | 25% | ||||||||||
% priced with reference to TTF and NBP | 19% | 19% | 30% | 22% | 29% | ||||||||||
Netbacks ($/boe) | |||||||||||||||
Operating netback (1) | 27.58 | 34.85 | 30.77 | 31.59 | 29.24 | ||||||||||
Fund flows from operations netback | 23.79 | 29.69 | 27.13 | 26.47 | 24.34 | ||||||||||
Operating expenses | 12.04 | 11.13 | 9.76 | 11.26 | 9.79 | ||||||||||
Average reference prices | |||||||||||||||
WTI (US $/bbl) | 58.81 | 69.50 | 55.40 | 64.77 | 50.95 | ||||||||||
Edmonton Sweet index (US $/bbl) | 32.51 | 62.68 | 54.26 | 53.65 | 48.49 | ||||||||||
Saskatchewan LSB index (US $/bbl) | 44.03 | 63.35 | 54.04 | 56.46 | 47.85 | ||||||||||
Dated Brent (US $/bbl) | 67.76 | 75.27 | 61.39 | 71.04 | 54.27 | ||||||||||
AECO ($/mcf) | 1.56 | 1.19 | 1.69 | 1.50 | 2.16 | ||||||||||
NBP ($/mcf) | 11.03 | 10.95 | 8.70 | 10.35 | 7.49 | ||||||||||
TTF ($/mcf) | 10.91 | 10.92 | 8.36 | 10.23 | 7.43 | ||||||||||
Average foreign currency exchange rates | |||||||||||||||
CDN $/US $ | 1.32 | 1.31 | 1.27 | 1.30 | 1.30 | ||||||||||
CDN $/Euro | 1.51 | 1.52 | 1.50 | 1.53 | 1.46 | ||||||||||
Share information ('000s) | |||||||||||||||
Shares outstanding - basic | 152,704 | 152,497 | 122,119 | 152,704 | 122,119 | ||||||||||
Shares outstanding - diluted (1) | 156,173 | 155,747 | 125,140 | 156,173 | 125,140 | ||||||||||
Weighted average shares outstanding - basic | 152,588 | 152,432 | 121,858 | 140,619 | 120,582 | ||||||||||
Weighted average shares outstanding - diluted (1) | 153,880 | 153,839 | 123,450 | 142,335 | 122,408 |
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
Message to Shareholders
In 2018, we drilled a total of 148.9 net wells and completed four acquisitions within our existing core areas, including the acquisition of Spartan Energy during Q2 2018, making this our most active year ever in terms of both organic and M&A activity. As a result, we delivered record annual production of 87,270 boe/d, representing a year-over-year increase of 28%, or 10% on a per share basis. Similarly, we increased our proved plus probable reserves by 63% to 488.1 mmboe(3), reflecting a year-over-year increase of 31% on a per share basis.
Our 2018 acquisitions added high netback, low decline and free cash flow(1) generating producing assets while also significantly expanding our future project inventory. We are very disciplined in our M&A approach and apply a rigorous strategic framework, comprehensive technical evaluation methodology, and consistent decision criteria for any assets that we consider in our three operating regions. Prior to 2018, we had been less active in M&A in North America due to the overly competitive nature of the North American market and consequent lower M&A returns as compared to Europe. However, market conditions became more favourable under our criteria in North America in 2018, and we were able to opportunistically conclude the Spartan acquisition, a Saskatchewan/Manitoba waterflood purchase, a Powder River Basin stacked zone land and production acquisition, and the consolidation of additional Corrib interest. These important acquisitions enhanced our margins, reduced risk in our operating and financial profiles, expanded our development project inventory, increased our operating control, and diversified our asset base away from Alberta, with its particularly-challenged product pricing. As a result of our organic and acquisition activities, we generated a ROCE of 9% in 2018, compared to our five-year average ROCE of 4%.
We achieved a significant operational milestone in Q4 2018 as our production exceeded 100,000 boe/d for the first time in our history. Q4 2018 production increased 6% from the prior quarter to an average of 101,621 boe/d, primarily as a result of organic activities which were aided by a full quarter of the Powder River Basin acquisition and a minor contribution from our increased ownership in Corrib. Looking forward, we are pleased with the continued expansion of project inventory arising from our acquisition of Spartan. As we noted at our Investor Day in November 2018, we have increased our internally-estimated drilling inventory from the Spartan assets by approximately 50% to over 1,500 locations. At our Investor Day, we also related that we have internally-estimated the potential for approximately 60 mmbbls of net waterflood recovery potential on the Spartan assets, which is a project class we did not count in our original evaluation of the Spartan deal. Our year-end reserve and resources reports(6) recognizes 11.8 mmboe of 2P reserves and 30.0 mmboe of best-estimate contingent resources, respectively, for the new waterflood projects that came with Spartan.
Our international diversification provided a significant strategic advantage to Vermilion in Q4 2018. Oil prices weakened during Q4 2018, especially Canadian benchmarks, as differentials for both heavy and light oil widened substantially due to a combination of factors which included above average refinery turnaround activity in PADD 2 and resulting high storage levels in western Canada. While Vermilion's Canadian oil production was affected by these wider differentials, it was impacted to a lesser degree than Alberta light and heavy oil, as our Alberta condensate and Saskatchewan light oil displayed relative pricing advantages over the Alberta black oil products. This is most evident when comparing the Saskatchewan LSB index price versus the Edmonton Sweet (MSW) index price. During Q4 2018, LSB traded at an US$11.52/bbl premium over MSW, compared to a US$0.22/bbl discount in Q4 2017. Approximately 41% of our total 2019 oil production is indexed to LSB while only 8% is indexed to MSW. In additional contrast, Brent oil traded at nearly a US$9/bbl premium over WTI and European natural gas traded at an approximate $9.40/mcf premium over AECO during Q4 2018. Approximately 36% of our total 2019 oil production is price referenced to Brent while roughly 45% of our total 2019 natural gas production is price referenced to European gas benchmarks.
Despite the volatile commodity prices, we delivered strong financial results in Q4 2018 with FFO of $222 million ($1.46/basic share(1)) and net earnings of $323 million ($2.12/basic share). Realized hedging losses were $28 million in Q4 2018. We estimate that cash dividends will constitute approximately $400 million in 2019. Our capital budget of $530 million for 2019 is designed to deliver a production range of 101,000 to 106,000 boe/d, resulting in year-over-year production per share growth of 8% at the mid-point of guidance. At current differentials and using the current commodity strip for Brent, WTI and European natural gas, we estimate that we will be more than self-funded for our dividends and capital program for 2019, with excess cash generation earmarked for further debt reduction. As we have noted in the past, we have significant flexibility in our capital program and could reduce capital spending if commodity prices weaken substantially. In that event, we would reduce our growth capital first in order to protect the balance sheet and the dividend. We believe this level of organic growth combined with a dividend yield over 8% represents an attractive option for investors.
Q4 2018 Operations Review
Europe
In France, Q4 2018 production averaged 11,454 boe/d, which was up slightly from the prior quarter. Production from our 2018 three (3.0 net) well drilling program in the Champotran field continued to outperform expectations, contributing 725 boe/d of production in the fourth quarter.
In the Netherlands, Q4 2018 production averaged 8,749 boe/d, an increase of 17% from the prior quarter. The increase is primarily due to the benefit of a full quarter contribution from the Eesveen-02 well (60% working interest), which we brought on production late in the third quarter at a restricted rate of 10 mmcf/d net.
In Ireland, production from the Corrib Project averaged 52 mmcf/d (8,672 boe/d) in Q4 2018, an increase of 1% from the prior quarter. On November 30, we assumed operatorship of the Corrib Project and completed the transfer of SEPIL along with an incremental 1.5% working interest in the Corrib Project to Vermilion from Nephin Energy Holdings Limited, a wholly owned subsidiary of CPPIB. Cash consideration at closing was $9 million, which was more than offset by the assumption of $15 million in positive net working capital as a result of the acquisition. Integration of the staff, processes and systems have been completed, and we welcome the addition of former-Shell employees to Vermilion. Most importantly, Vermilion now has operating control of the Corrib Project, bringing the proportion of our production that we operate to approximately 90% on a worldwide basis.
In Germany, production in Q4 2018 averaged 3,736 boe/d, an increase of 7% from the prior quarter, primarily due to the restoration of gas processing at a non-operated gas processing facility during the third quarter. During the fourth quarter, we completed site construction for the Burgmoor Z5 well (46% working interest) and have secured all drilling permits necessary to proceed. Drilling is expected to commence by the end of Q1 2019.
In Central and Eastern Europe ("CEE"), production averaged 477 boe/d in Q4 2018, an increase of 145% over the prior quarter due to production from the well drilled earlier in 2018 on the South Battonya concession in Hungary. In Croatia, we acquired an additional 150 linear kilometres of 2D seismic data in our DR-04 license to expand on the first phase of 2D seismic data we acquired in Q2 2018. We continued to progress the permitting activities associated with our 10.0 (7.0 net) well program for 2019 in the CEE business unit, and have received all the permits for our second well in Hungary. In Slovakia, we were granted the Topolcany license which is adjacent to our existing Trnava license. The Topolcany license is owned 50/50 with our partner in Slovakia (NAFTA) and adds 301,000 acres (150,500 net) to our portfolio.
North America
In Canada, production averaged a record 60,814 boe/d in Q4 2018, representing an increase of 6% from the previous quarter. The increase was primarily due to strong operating performance and new well completions in both Saskatchewan and Alberta. The strong production results were partially restrained by a system-wide power outage in Saskatchewan in December, which reduced production volumes by approximately 500 boe/d for the quarter. We drilled or participated in 72 (44.1 net) wells and brought on production 86 (56.6 net) wells in the fourth quarter. We executed a five rig program in Saskatchewan, drilling or participating in 61 (34.8 net) wells across our combined Spartan and legacy land bases. In Alberta, we drilled nine (7.3 net) Mannville wells and two (2.0 net) long-reach Cardium wells.
In the United States, Q4 2018 production averaged 3,545 boe/d, an increase of 19% from the prior quarter, due to a full quarter of production associated with the Powder River Basin acquisition completed in Q3. We drilled and completed our first (1.0 net) well on the newly acquired Hilight assets late in the fourth quarter. Production from this well commenced in mid-December. We elected to use a rod pump artificial lift system on this well, which offers lower pump displacement than previously-utilized electrical submersible pumps on new wells at Hilight, but reduces sand flowback and pump failure frequency. As a result, the current rate is 290 boe/d (86% oil) and is increasing as the well cleans up.
Australia
In Australia, production averaged 4,174 bbl/d in Q4 2018, down 11% from the previous quarter primarily due to a planned shutdown for maintenance and other downtime which was required to allow drilling of two new wells. We began drilling the two wells in early November 2018 and completed the wells in late January 2019. These were the most technically challenging wells ever executed at Vermilion. Both wells were drilled at vertical depths of approximately 650 meters, but with measured depths of 4,960 meters and 3,697 meters for the B15 and B16 wells respectively, making these some of the most extreme extended reach wells at shallow depth in the world. The B15 well also featured an approximately 180 degree turn to allow drainage of oil trapped against the updip bounding fault for the Wandoo field. We achieved our reservoir and mechanical objectives on both wells, and the wells were successfully tested in February 2019. The B15 well tested at an oil rate of 8,800 bbl/d over a 48-hour period and the B16 well tested at an oil rate of 7,600 bbl/d over a 36-hour period(2). We plan to intermittently produce the new wells at restricted rates to maximize long-term value. The total cost of the program was $75 million, which is approximately $10 million over budget due to slower-than-expected drilling in the vertical sections of the wells, lost circulation in part of the B15 horizontal section along the bounding fault, and a cyclone which required down-manning of the drilling rig for approximately a week.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of cash flows, providing additional certainty with regard to the execution of our dividend and capital programs. In aggregate, we currently have 34% of our expected net-of-royalty production hedged for Q1 2019. Over half of the Q1 2019 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases, up to contract ceilings.
We have currently hedged 67% of anticipated European natural gas volumes for Q1 2019. In view of the compelling longer-term forward market for European natural gas, we have also hedged 66% and 38% of our anticipated full-year 2019 and 2020 volumes at prices which will provide for strong project economics and free cash flows. As of February 26, 2019, 29% of our Q1 2019, and 21% of our full year 2019 oil production is hedged. We will continue to add to our hedge positions in all products as suitable opportunities arise. For Q1 2019, 30% of our North American natural gas production is priced away from AECO, by virtue of diversification hedges to sell at the SoCal Border, Chicago and Henry Hub for a portion of our Alberta gas production, and because 14% of our production comes from Saskatchewan and Wyoming.
Environmental, Social and Governance ("ESG")
Vermilion was named to the CDP Climate Leadership Level (A-) for the second consecutive year in 2018. We were the only Canadian oil and gas company and one of only two North American oil and gas companies to receive this designation, ranking Vermilion in the top 5% of oil and gas companies globally. We are proud of this achievement and believe this ranking is a reflection of our responsible operating practices and positive track record of reducing emissions on our oil and gas assets. We will continue to seek new and innovative ways to improve our overall operating performance while reducing the emission intensity of our assets.
In February 2019, we were a finalist for the Finance and Sustainability Initiative's ("FSI") award for Best Sustainability Report in the Non-Renewable Resources - Oil and Gas category for our 2017 Sustainability Report. Last year, we received this award for our 2016 Sustainability Report. Based in Montreal, the FSI is a non-profit organization dedicated to promoting sustainable finance and, more specifically, responsible investment to financial institutions, companies, and universities. Sustainability reports were graded on a number of criteria, including transparency and balance, reliability and completeness, and the use of ESG materiality. We firmly believe in the importance of measuring and understanding our current environmental impact. Furthermore, we believe the integration of sustainability principles into our business strategy increases shareholder returns and reduces long-term risks to our business model. Our recently published 2018 Sustainability Report is available now on our corporate website at http://sustainability.vermilionenergy.com.
Vermilion ranked second within the oil and gas sector, and among the top quartile of companies in the S&P/TSX Composite Index in the annual Globe and Mail Board Games evaluation for 2018. The evaluation uses a rigorous set of governance criteria that goes beyond minimum mandatory rules imposed by regulators and validates our commitment to, and execution of, best governance practices.
2018 Reserves and Resources
In 2018 we significantly increased our reserves and resources through a combination of development and acquisition activities. Based on the 2018 GLJ Reserves Report, our 2P reserves increased 63% from year-end 2017 to 488.1(3) mmboe, while our 1P reserves increased 69% from year-end 2017 to 298.2(3) mmboe in 2018. PDP reserves increased 55% from year-end 2017 to 192.1(3) mmboe. Our PDP reserves represent 64% of our 1P reserves.
The following table provides a summary of company interest reserves by reserve category and country on an oil equivalent basis. Please refer to Vermilion's 2018 Annual Information Form for detailed by product type information.
BOE (Mboe) | Proved Developed | Proved Developed | Proved Undeveloped | Proved | Probable | Proved Plus | ||||||
Australia | 8,048 | 1,620 | — | 9,668 | 4,812 | 14,480 | ||||||
Canada | 103,992 | 9,496 | 68,451 | 181,939 | 102,897 | 284,836 | ||||||
France | 37,596 | 441 | 5,429 | 43,466 | 20,452 | 63,918 | ||||||
Germany | 9,879 | 2,043 | 1,069 | 12,991 | 12,744 | 25,735 | ||||||
Hungary | 131 | — | — | 131 | 59 | 191 | ||||||
Ireland | 13,093 | — | — | 13,093 | 7,482 | 20,575 | ||||||
Netherlands | 7,629 | 3,469 | 705 | 11,802 | 10,395 | 22,196 | ||||||
United States | 11,705 | — | 13,442 | 25,147 | 31,068 | 56,214 | ||||||
Vermilion | 192,073 | 17,069 | 89,096 | 298,237 | 189,909 | 488,145 |
Through development activities, we replaced 187% of 2P reserves, 157% of 1P reserves and 130% of PDP reserves, respectively. Including acquisitions, we replaced 695% of 2P reserves, 481% of 1P reserves and 314% of PDP reserves, respectively.
Our Operating Recycle Ratio(5) (including FDC) at the 2P level increased to 4.1x in 2018, compared to 2.8x in 2017, as a result of higher operating netbacks and a significant decrease to our F&D costs (including FDC). Organic F&D costs (including FDC) decreased 26% in 2018 to $7.79/boe, compared to $10.57/boe in 2017. These metrics remain strong relative to historical industry averages, and reflect the significant improvement in our capital efficiencies over the last several years.
The following table summarizes the finding and development costs and associated operating recycle ratios by reserve category for the year ended December 31, 2018:
2018 | 3-Year Average | |||||||||||
PDP | 1P | 2P | PDP | 1P | 2P | |||||||
Finding and Development Costs, including FDC (F&D)(3) ($/boe) | $15.65 | $13.49 | $7.79 | $11.94 | $10.96 | $7.85 | ||||||
Finding, Development and Acquisition Costs, including FDC (FD&A)(3) ($/boe) | $23.92 | $19.95 | $14.99 | $18.71 | $16.87 | $13.16 | ||||||
F&D Operating Recycle Ratio(4) * | 2.0 | 2.3 | 4.1 | 2.5 | 2.7 | 3.8 | ||||||
FD&A Operating Recycle Ratio(4) * | 1.3 | 1.6 | 2.1 | 1.6 | 1.8 | 2.2 |
In addition to increasing our reserve base, we pursued various initiatives to expand our resource base to support our longer-term growth profile. According to the 2018 GLJ Resources Report, risked low, best, and high estimates for our contingent resources in the Development Pending category we evaluated as 156(6) mmboe, 240(6) mmboe, and 334(6) mmboe, respectively. The 2018 GLJ Resources Report also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 11(6) mmboe, 37(6) mmboe, and 53(6) mmboe, respectively. Over 86% of our risked contingent resources reside in the Development Pending category. Prospective resources were assessed at risked low, best and high estimates of 55(6) mmboe, 161(6) mmboe, and 284(6) mmboe, respectively. Our contingent and prospective resource bases remain a source of reserve additions, with 17 mmboe of contingent resources converted to 2P reserves during 2018.(6)
The following table provides a reconciliation of changes in reserves by reserve category and country. Please refer to Vermilion's 2018 Annual Information Form for detailed by product type information.
1P (Mboe) | Australia | Canada | France | Germany | Hungary | Ireland | Netherlands | United | Vermilion | |||||||||
December 31, 2017 | 10,915 | 81,388 | 42,094 | 12,640 | — | 13,634 | 10,347 | 5,613 | 176,631 | |||||||||
Discoveries | — | — | — | — | 193 | — | — | — | 193 | |||||||||
Extensions & Improved Recovery | — | 31,289 | 2,249 | 673 | — | — | 256 | 1,359 | 35,826 | |||||||||
Technical Revisions | 393 | 6,977 | 3,244 | 979 | — | 1,575 | 206 | 298 | 13,671 | |||||||||
Acquisitions | — | 81,328 | — | — | — | 1,241 | 3,838 | 18,604 | 105,012 | |||||||||
Dispositions | — | (134) | — | — | — | — | — | — | (134) | |||||||||
Economic Factors | — | (1,162) | 40 | 17 | — | — | (4) | (1) | (1,110) | |||||||||
Production | (1,640) | (17,750) | (4,160) | (1,319) | (62) | (3,356) | (2,839) | (727) | (31,853) | |||||||||
December 31, 2018 | 9,668 | 181,938 | 43,467 | 12,990 | 131 | 13,094 | 11,804 | 25,146 | 298,236 | |||||||||
2P (Mboe) | Australia | Canada | France | Germany | Hungary | Ireland | Netherlands | United | Vermilion | |||||||||
December 31, 2017 | 15,565 | 139,294 | 64,189 | 24,496 | — | 22,199 | 17,863 | 14,969 | 298,575 | |||||||||
Discoveries | — | — | — | — | 252 | — | — | — | 252 | |||||||||
Extensions & Improved Recovery | — | 37,024 | 1,934 | 2,158 | — | — | 2,201 | 6,265 | 49,581 | |||||||||
Technical Revisions | 555 | 5,573 | 2,713 | 393 | — | (253) | 16 | 1,880 | 10,875 | |||||||||
Acquisitions | — | 121,537 | — | — | — | 1,986 | 4,973 | 33,828 | 162,324 | |||||||||
Dispositions | — | (227) | — | — | — | — | — | — | (227) | |||||||||
Economic Factors | — | (616) | (758) | 5 | — | — | (14) | (2) | (1,383) | |||||||||
Production | (1,640) | (17,750) | (4,160) | (1,319) | (62) | (3,356) | (2,839) | (727) | (31,853) | |||||||||
December 31, 2018 | 14,480 | 284,835 | 63,918 | 25,733 | 190 | 20,576 | 22,200 | 56,213 | 488,145 |
Additional information about our 2018 GLJ Reserves Report and GLJ 2018 Resources Report can be found in our 2018 Annual Information Form on our website at www.vermilionenergy.com and on SEDAR at www.sedar.com.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
February 27, 2019
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) | B15ST1 well tested oil at an average rate of 8,769 bbls/d and zero barrels of water per day ("bwpd") over a 48-hour period at a flowing wellhead pressure of 900 kpa (130 psi) on a 100% open choke (130 mm or 5.1 inch diameter) with applied gas-lift of 22,000 m3/d (775 mcf/d). The well was estimated to be flowing with a 30% drawdown of reservoir pressure. |
B16ST2 well tested oil at an average rate of 7,600 bbls/d and 770 bwpd over a 36-hour period at a flowing wellhead pressure of 900 kpa (130 psi) on a 100% open choke (130 mm or 5.1 inch diameter) with applied gas-lift of 45,000 m3/d (1,590 mcf/d). The well was estimated to be flowing with a 15% drawdown of reservoir pressure. | |
(3) | Estimated proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 7, 2019 with an effective date of December 31, 2018 (the "2018 GLJ Reserves Report"). |
(4) | F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period. |
(5) | Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(6) | Vermilion retained GLJ to conduct an independent resource evaluation dated February 7, 2019 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2018 (the "GLJ 2018 Resources Report"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 82%, 81% and 81%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 24%, 23% and 24%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development. Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. Prospective resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. Please refer to Vermilion's 2018 Annual Information Form for further information on Vermilion's contingent resources and prospectus resources. |
Guidance
On October 30, 2017, we released our 2018 capital expenditure guidance of $315 million and associated production guidance of between 74,500 to 76,500 boe/d. On January 15, 2018, we increased our capital expenditure guidance to $325 million and production guidance to between 75,000 to 77,500 boe/d to reflect the post-closing impact of the acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer. On April 16, 2018, we increased our capital expenditure guidance to $430 million and production guidance to between 86,000 to 90,000 boe/d to reflect the post-closing impact of the acquisition of Spartan Energy Corp. On July 30, 2018, we increased our capital expenditure guidance to $500 million to reflect the acceleration of our Australia drilling campaign into Q4 2018, and to a lesser extent to account for the impact of foreign exchange fluctuations on our Canadian dollar capital levels. On October 25, 2018, we increased our capital expenditure guidance to $510 million to reflect additional capital activity associated with the assets acquired in the Powder River Basin in August of 2018. Actual 2018 capital spending of $518 million was within 2% of our guidance and 2018 average production of 87,270 boe/d was within 1% of the mid-point of our guidance range.
On October 25, 2018, we released our 2019 capital budget and related guidance. The 2019 total budget and production guidance remain unchanged, although we have deferred some activity to later in the year and reallocated capital between business units, the breakdown of which can be found in our corporate presentation located on our website.
The following table summarizes our guidance:
Date | Capital Expenditures ($MM) | Production (boe/d) | ||||
2018 Guidance | ||||||
2018 Guidance | October 30, 2017 | 315 | 74,500 to 76,500 | |||
2018 Guidance | January 15, 2018 | 325 | 75,000 to 77,500 | |||
2018 Guidance | April 16, 2018 | 430 | 86,000 to 90,000 | |||
2018 Guidance | July 30, 2018 | 500 | 86,000 to 90,000 | |||
2018 Guidance | October 25, 2018 | 510 | 86,000 to 90,000 | |||
2018 Actual Results | 518 | 87,270 | ||||
2019 Guidance | ||||||
2019 Guidance | October 25, 2018 | 530 | 101,000 to 106,000 |
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and webcast presentation on Thursday, February 28, 2019 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using the conference ID 7955826 from February 28, 2019 at 12:00 PM MST to March 14, 2019 at 9:59 PM MST.
You may also access the webcast at https://event.on24.com/wcc/r/1924756/BAC3FC6A211842CA79D33D2B88BCFBA6. The webcast link, along with conference call slides, can be found on Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm under Upcoming Events prior to the conference call.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures; Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2019 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion's future project inventory, and the wells expected to be drilled in 2019; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt, including its ability to redeem senior unsecured notes prior to maturity; statements regarding Vermilion's hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All crude oil and natural gas reserve and resource information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, Feb. 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on March 15, 2019 to all shareholders of record on February 28, 2019. The ex-dividend date for this payment is February 27, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Feb. 14, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) announced today it expects to release its 2018 fourth quarter and year-end operating and financial results, along with its 2018 reserves information on Thursday, February 28, 2019 before the open of North American markets. The audited financial statements, management discussion and analysis, and annual information form for the year ended December 31, 2018 will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Conference Call and Webcast Details
Vermilion will discuss these results in a conference call and webcast presentation on Thursday, February 28, 2019 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using conference ID 7955826 from February 28, 2019 at 12:00 PM MST to March 14, 2019 at 9:59 PM MST.
You may also access the webcast at https://event.on24.com/wcc/r/1924756/BAC3FC6A211842CA79D33D2B88BCFBA6. The webcast link, along with conference call slides, will be available on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events prior to the conference call.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Jan. 15, 2019 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on February 15, 2019 to all shareholders of record on January 31, 2019. The ex-dividend date for this payment is January 30, 2019. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Dec. 21, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce the completion of the transfer of Shell E&P Ireland Limited ("SEPIL") along with an incremental 1.5% working interest in the Corrib Natural Gas Project in Ireland ("Corrib") to Vermilion from Nephin Energy Holdings Limited (NEHL), a wholly owned subsidiary of Canada Pension Plan Investment Board. The final purchase price net of all closing adjustments for the incremental 1.5% interest was €6 million. Vermilion became operator of the Corrib project on November 30, 2018 upon the sale of SEPIL to NEHL.
With this transfer now complete, ownership in Corrib is as follows:
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion holds a 20% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 9.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Dec. 17, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on January 15, 2019 to all shareholders of record on December 31, 2018. The ex-dividend date for this payment is December 28, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 9.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Nov. 30, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce the completion of the sale of Shell Overseas Holdings Limited's ("Shell") 45% interest in the Corrib Natural Gas Project in Ireland ("Corrib") to Nephin Energy Holdings Limited (NEHL), a wholly owned subsidiary of Canada Pension Plan Investment Board (CPPIB), and the transfer of operatorship to Vermilion. NEHL has acquired 100% of Shell E&P Ireland Limited ("SEPIL"), which holds 45% interest in Corrib (the "Acquisition").
Effective immediately, Vermilion has assumed contract operatorship of Corrib on behalf of the joint venture partners. CPPIB plans to transfer SEPIL along with a 1.5% working interest to Vermilion. This transfer has received all required government approvals and is expected to be completed in the coming weeks. The estimated purchase price after interim period adjustments is approximately €6 million.
Following the transfer to Vermilion, ownership in Corrib will be as follows:
Vermilion's incremental 1.5% ownership of Corrib represents approximately 700 boe/d at current production rates and approximately 1.8 million boe of 2P reserves(1) based on an independent evaluation by GLJ Petroleum Consultants Ltd. with an effective date of December 31, 2017. Based on a final purchase price of €6 million ($9.1 million at current exchange rates), the transaction metrics are estimated at approximately $13,000 per boe per day, $5.05 per boe of proved plus probable reserves(1) including future development capital (generating a 2P recycle ratio of 9.4 times based on projected 2018 netbacks(2)), and 0.7 times estimated 2018 operating cash flow(2) using the current forward commodity strip. Vermilion expects the acquisition to be accretive for all pertinent per share metrics including production, fund flows from operations(2), reserves and net asset value. In addition, Vermilion expects to receive approximately €13 million of net working capital with the transfer of SEPIL.
Following the assumption of operatorship of Corrib, Vermilion estimates that it will operate 89% of its global production base as compared to 81% prior to the transaction.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Natural gas volumes have been converted on the basis of six thousand cubic feet ("mcf") of natural gas to one barrel equivalent of oil. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(1) Estimated total proved and proved plus probable reserves attributable to the Assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated February 1, 2018 with an effective date of December 31, 2017, in accordance with National Instrument 51-101 – Standards of Disclosure For Oil and Gas Activities of the Canadian Securities Administrators, using the GLJ (2018-01) price forecast (the "GLJ Report")
(2) This news release includes references to certain financial and performance measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). These measures include netbacks and fund flows from operations. "Netbacks" are per boe and per mcf measures used in operational and capital allocation decisions. "Fund flows from operations" represents cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management considers fund flows from operations and fund flows from operations per share to be key measures as they demonstrate Vermilion's ability to generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a useful measure of Vermilion's ability to generate cash that is not subject to short-term movements in non-cash operating working capital. In addition, this news includes references to certain financial measures which are not specified, defined, or determined under IFRS and are therefore considered non-GAAP financial measures, including after-tax fund flows recycle ratio and debt-adjusted cash flow. These non-GAAP financial measures are unlikely to be comparable to similar financial measures presented by other issuers. After-tax fund flows recycle ratio represents the after-tax netback per boe divided by FD&A costs in dollars per boe. Management considers after-tax fund flows recycle ratio to be a useful measure of capital efficiency. "Debt-adjusted cash flow" represents fund flows from operations prior to the impact of interest charges. Management considers debt-adjusted cash flow to be a useful measure to compare transaction metrics on an unlevered basis. For relevant operating netback related disclosures please refer to the reconciliation in management's discussion and analysis contained in Vermilion's 2017 Annual Report for the year ended December 31, 2017 available on SEDAR or at the company's website (www.vermilionenergy.com).
DISCLAIMER
Certain statements included or incorporated by reference in this news release may constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this news release may include, but are not limited to:
Statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
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SOURCE Vermilion Energy Inc.
CALGARY, Nov. 26, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) will hold an Investor Day in Toronto, Canada on Tuesday, November 27, 2018 starting at 8:00AM EST (6:00AM MST). The event will feature presentations by senior management and leaders from all of Vermilion's business units, providing an overview of our corporate strategy, global asset portfolio and future growth opportunities.
The event will be webcast live through this weblink https://event.on24.com/wcc/r/1799366/ECE2AA332EFC10B9CCDF6BF6369AE609, and an archived version of the webcast will be available after the event for one year. To access the audio webcast and presentation slides please visit Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Nov. 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on December 17, 2018 to all shareholders of record on November 30, 2018. The ex-dividend date for this payment is November 29, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Oct. 25, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three and nine months ended September 30, 2018.
The unaudited financial statements and management discussion and analysis for the three and nine months ended September 30, 2018, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
($M except as indicated) | Q3 2018 | Q2 2018 | Q3 2017 | YTD 2018 | YTD 2017 | |
Financial | ||||||
Petroleum and natural gas sales | 508,411 | 394,498 | 248,505 | 1,221,178 | 781,497 | |
Fund flows from operations | 260,705 | 195,190 | 130,755 | 616,310 | 421,312 | |
Fund flows from operations ($/basic share) (1) | 1.71 | 1.45 | 1.08 | 4.51 | 3.51 | |
Fund flows from operations ($/diluted share) (1) | 1.69 | 1.43 | 1.07 | 4.46 | 3.45 | |
Net (loss) earnings | (15,099) | (61,364) | (39,191) | (51,723) | 53,613 | |
Net (loss) earnings ($/basic share) | (0.10) | (0.46) | (0.32) | (0.38) | 0.45 | |
Capital expenditures | 146,185 | 79,984 | 91,382 | 354,634 | 246,146 | |
Acquisitions | 198,173 | 1,465,485 | 20,976 | 1,756,736 | 24,589 | |
Asset retirement obligations settled | 2,986 | 2,626 | 1,749 | 9,203 | 6,118 | |
Cash dividends ($/share) | 0.690 | 0.690 | 0.645 | 2.025 | 1.935 | |
Dividends declared | 105,192 | 98,604 | 78,293 | 282,801 | 232,744 | |
% of fund flows from operations | 40% | 51% | 60% | 46% | 55% | |
Net dividends (1) | 100,872 | 78,629 | 54,364 | 238,865 | 144,068 | |
% of fund flows from operations | 39% | 40% | 42% | 39% | 34% | |
Payout (1) | 250,043 | 161,239 | 147,495 | 602,702 | 396,332 | |
% of fund flows from operations | 96% | 83% | 113% | 98% | 94% | |
Net debt | 2,034,086 | 1,796,807 | 1,370,995 | 2,034,086 | 1,370,995 | |
Ratio of net debt to annualized fund flows from operations | 1.95 | 2.30 | 2.62 | 2.48 | 2.44 | |
Operational | ||||||
Production | ||||||
Crude oil and condensate (bbls/d) | 47,152 | 34,574 | 27,687 | 36,318 | 27,684 | |
NGLs (bbls/d) | 6,839 | 5,651 | 4,947 | 5,878 | 3,828 | |
Natural gas (mmcf/d) | 253.38 | 242.40 | 208.63 | 241.42 | 209.35 | |
Total (boe/d) | 96,222 | 80,625 | 67,403 | 82,433 | 66,404 | |
Average realized prices | ||||||
Crude oil and condensate ($/bbl) | 85.84 | 87.50 | 61.47 | 84.98 | 64.58 | |
NGLs ($/bbl) | 27.97 | 26.06 | 23.96 | 26.61 | 23.01 | |
Natural gas ($/mcf) | 5.35 | 4.77 | 4.01 | 5.30 | 4.79 | |
Production mix (% of production) | ||||||
% priced with reference to WTI | 37% | 29% | 22% | 30% | 20% | |
% priced with reference to Dated Brent | 18% | 21% | 26% | 21% | 27% | |
% priced with reference to AECO | 26% | 26% | 26% | 26% | 24% | |
% priced with reference to TTF and NBP | 19% | 24% | 26% | 23% | 29% | |
Netbacks ($/boe) | ||||||
Operating netback (1) | 34.85 | 33.03 | 26.06 | 33.26 | 28.69 | |
Fund flows from operations netback | 29.69 | 26.58 | 20.87 | 27.59 | 23.34 | |
Operating expenses | 11.13 | 10.75 | 9.87 | 10.94 | 9.80 | |
Average reference prices | ||||||
WTI (US $/bbl) | 69.50 | 67.88 | 48.20 | 66.75 | 49.47 | |
Edmonton Sweet index (US $/bbl) | 62.68 | 62.43 | 45.32 | 60.69 | 46.57 | |
Saskatchewan LSB index (US $/bbl) | 63.35 | 61.84 | 44.91 | 60.61 | 45.78 | |
Dated Brent (US $/bbl) | 75.27 | 74.35 | 52.08 | 72.13 | 51.90 | |
AECO ($/mmbtu) | 1.19 | 1.18 | 1.45 | 1.48 | 2.31 | |
NBP ($/mmbtu) | 10.95 | 9.42 | 6.78 | 10.12 | 7.10 | |
TTF ($/mmbtu) | 10.92 | 9.50 | 6.93 | 10.00 | 7.12 | |
Average foreign currency exchange rates | ||||||
CDN $/US $ | 1.31 | 1.29 | 1.25 | 1.29 | 1.31 | |
CDN $/Euro | 1.52 | 1.54 | 1.47 | 1.54 | 1.45 | |
Share information ('000s) | ||||||
Shares outstanding - basic | 152,497 | 152,363 | 121,585 | 152,497 | 121,585 | |
Shares outstanding - diluted (1) | 155,747 | 155,355 | 124,453 | 155,747 | 124,453 | |
Weighted average shares outstanding - basic | 152,432 | 134,603 | 121,280 | 136,585 | 120,152 | |
Weighted average shares outstanding - diluted (1) | 153,839 | 136,559 | 122,485 | 138,258 | 121,963 |
(1) The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
Message to Shareholders
We delivered record quarterly production of 96,222 boe/d in Q3 2018, marking our first full quarter with the integration of the Spartan assets and our first quarter with production and cash flow contribution from our Central and Eastern European ("CEE") business unit. We also completed another acquisition in the quarter, expanding our land base in the Turner Sand fairway. We expect both of these acquisitions and ongoing development in our CEE business unit to contribute to our long-term growth profile, while generating free cash to support our growth-and-income capital markets model.
Our Q3 2018 FFO increased 34% quarter-over-quarter to $261 million, which is twice the amount we generated in Q3 2017. The Q3 2018 results included a $37 million realized hedging loss largely driven by the recent strength in global oil prices and European natural gas prices. On a year-to date basis, we have generated $616 million in FFO, which includes the impact of an $83 million realized hedging loss.
Our Board of Directors has approved a 2019 capital budget of $530 million with associated production guidance of 101,000 to 106,000 boe/d. The midpoint of this guidance range represents year-over-year production growth of 18%, or 7% on a per share basis. Including our projected 2018 results, Vermilion will have delivered compounded average production-per-share-growth of 9% over the past 5 years, coming primarily from high margin barrels, as the majority of our production receives premium or advantaged pricing relative to our peers. The oil and gas produced from our international assets is indexed to Brent oil and European gas benchmarks, both of which trade at significant premiums to their North American counterparts. In turn, the vast majority of our North American oil is produced in areas that have relative pricing advantages to most Canadian oil streams, enhancing netbacks and free cash flow generation.
With our growing production base, continued discipline in capital spending, and the current strength in commodity prices, our free cash flow profile has never been better. Based on the mid-point of our 2019 production guidance and the current commodity strip at October 15, 2018, we expect to more than fully fund our $530 million capital program and annual dividend, resulting in a total payout ratio of approximately 82% and over $200 million in surplus cash beyond our needs for our capital program and dividends.
As part of our annual budgeting process and ongoing strategic planning for the company, we continuously update our long-range development plans. On this note, we have recently updated the investor presentation on our website to reflect our longer-term drilling plans in the Netherlands and Germany. In Germany, we have identified several future exploration prospects (working interests from 46% to 100%) which we believe may range in size from 300 Bcf to over 1 Tcf of recoverable gas (unrisked) if successful. We plan to drill these prospects over the next five years. In the Netherlands, we have outlined a preliminary drilling schedule that calls for acceleration of our annual drilling activity to six or more wells by 2021. We continue to work to identify ways to streamline our permitting process in the Netherlands, and are increasingly confident that this accelerated drilling pace can be achieved over time. Our 2019 budget includes a ten (7.0 net) well drilling program in Central and Eastern Europe, which is an area in which we have recently initiated production and expect to continue to expand in the years ahead. In aggregate, our European drilling plan calls for 19 (13.7 net) wells next year, the largest drilling program we have conducted in our 21-year history in that region. We will discuss many of these future growth prospects in greater detail at our upcoming investor day in Toronto on November 27, 2018.
Q3 2018 Operations Review
Europe
In France, Q3 2018 production averaged 11,407 boe/d, a decrease of 2% from the prior quarter. The three (3.0 net) wells from our early 2018 drilling program in the Champotran field continue to outperform, contributing 750 boe/d in the third quarter, while other workover and maintenance activities continue to progress as planned.
In the Netherlands, Q3 2018 production averaged 7,479 boe/d, an increase of 2% from the prior quarter. In mid-September, we brought the Eesveen-02 well (60% working interest) on production. The well is currently flowing at a restricted rate of 10 mmcf/d net, pursuant to the conditions of the environmental permit. The well is expected to produce at this rate through 2019. Additional activity during the third quarter was focused on maintenance and well workovers, and planning for our 2019 drilling campaign. We were recently granted a positive decision on the EIA (Environmental Impact Assessment) judgment for the two wells included in our 2019 drilling plans and are now awaiting final approval of the drilling permits before proceeding. As mentioned above, we continue to work on advancing our future drilling permits, in part by reducing our surface footprint through long departure wells from existing well pads where feasible, in preparation for an accelerated drilling program in the years ahead. As previously noted, we intend to accelerate our annual drilling program to six or more wells per year by 2021.
In Ireland, production from Corrib averaged 51 mmcf/d (8,563 boe/d) in Q3 2018, a 9% decrease from the prior quarter, primarily due to a planned plant turnaround in September, which reduced production by approximately 450 boe/d net to Vermilion. Natural declines accounted for approximately 400 boe/d of the quarter-over-quarter decrease, which is consistent with our numerical simulation of reservoir performance. Our reservoir simulation model projects an average annual decline rate of approximately 15%, with a slightly higher decline rate in the early years and a slightly lower decline rate in the later years. Based on the model, we expect the field to decline at approximately 17% in 2019, decrease to 15% in 2020, and then level off to approximately 14% thereafter. We continue to focus on activities associated with the transition of ownership and operatorship from Shell to Canada Pension Plan Investment Board ("CPPIB") and Vermilion. We anticipate receiving final approvals from the necessary authorities and closing the transaction before the end of 2018. As noted in our Q2 2018 release, although the longer than anticipated closing of this transaction will have a modest impact on our booked production from Ireland, Vermilion will still benefit from all interim period cash flows from January 1, 2017 to closing as a reduction of purchase price. We now anticipate the closing price for our incremental 1.5% working interest to be approximately €6 million, compared to €19.4 million as announced in July 2017.
In Germany, production in Q3 2018 averaged 3,498 boe/d, little changed from the prior quarter. Restoration of gas processing at a non-operated gas processing facility during the quarter was largely offset by other minor unplanned downtime events. Our capital activity in Germany continues to focus on well and facility maintenance and preparatory work related to the drilling of our first operated well in Germany, the Burgmoor Z5 well (46% working interest), which is expected to commence drilling in Q1 2019.
In Central and Eastern Europe, first gas production commenced from our Hungarian Mh-Ny-07 natural gas well (100% working interest) in the South Battonya concession. The well, which was drilled and tested in the first quarter of this year, was brought on production mid-August and contributed 195 boe/d to our Q3 2018 results. The production rate from this well has recently been increased to 5.3 mmcf/d (880 boe/d), which compares to our original test flow rate of approximately 5.8 mmcf/d (970 boe/d). Permitting activities have been initiated in preparation for our 2019 drilling campaign across Hungary, Slovakia and Croatia where we plan to drill ten (7.0 net) wells. The permitting process is progressing well as we work collaboratively with regulatory bodies in all three countries who continue to exhibit strong levels of support for our activities. In Hungary, further 3D seismic interpretation performed in the quarter revealed a new Pannonian gas prospect in our Ebes license, with seismic attributes analogous to our Mh-Ny-07 discovery in South Battonya. In Croatia, we initiated seismic permitting for a new 2D seismic data acquisition to be carried out in Q4 2018, following the positive results achieved on the first phase of our 2D seismic data acquisition in Q2 2018.
Australia
In Australia, production averaged 4,704 bbl/d in Q3 2018, representing a 14% increase from the previous quarter primarily due to reinstatement of production following well workover activity that was successfully completed in Q2 2018. Another key well workover, which is part of our electrical submersible pump/increased fluid handling project, was completed at the end of Q3 2018 and should restore additional production in Q4 2018. Subsequent to end of the third quarter, we successfully completed a planned platform turnaround. In addition to the workover activity in Q3 2018, we continued to focus on preparatory activities associated with our upcoming two (2.0 net) well drilling campaign in Q4 2018. We have secured all necessary third party contracts and regulatory permits to drill and have prepared the majority of the materials needed for the load-out offshore. The rig is scheduled to arrive by the end of October, which should enable us to complete the planned wells by early January. As stated in our Q2 release, the early drilling is not expected to contribute any production to our 2018 results, but will allow us to save approximately $12 million in capital compared to drilling in 2019.
North America
In Canada, production averaged 57,397 boe/d in Q3 2018, representing a 31% increase from the previous quarter, primarily due to a full quarter of contribution from the Spartan assets. Production was partially offset by downtime due to third party gas plant maintenance, rate restrictions on certain wells and weather-related project delays. We drilled or participated in 65 (59.0 net) wells and brought on production 53 (49.8 net) wells in Q3 2018. We successfully executed a five rig drilling program in Saskatchewan in the quarter, drilling or participating in 60 (54.6 net) wells across our combined land base. We also operated one rig in Alberta during the quarter which included the drilling of four (4.0 net) Mannville wells and one (0.4 net) Cardium well. Results from all programs have been in line with our expectations.
Canadian oil differentials widened towards the end of the quarter, which had a modestly negative impact on our realized pricing. The majority of our Canadian liquids production receives significantly advantaged pricing relative to Alberta-based light crude oil. We have no heavy crude (WCS) in our Canadian oil mix. Approximately 70% of our Canadian oil is produced in southeast Saskatchewan and receives a price referenced to LSB (Light Sour Blend). The remaining 30% of our Canadian oil production is comprised of a combination of condensate and light oil in west-central Alberta and the Kerrobert area of Saskatchewan which is price referenced to the C5+ and MSW (Mixed Sweet Blend) benchmarks respectively. In the forward market for the balance of the year, the discount on all Canadian oil products has widened significantly. However, LSB and C5+ have widened to a much lesser extent than WCS and MSW. For example, LSB in the current prompt market has strengthened by approximately US$11.00/bbl relative to MSW compared to the average for Q3 2018.
Although we do not actively target natural gas in our Canadian operations, we still produce gas from high margin condensate-rich and liquids-rich gas wells and associated gas from our light oil assets. Subsequent to the quarter, AECO gas prices have improved significantly, with the forward curve indicating a Q4 2018 price that is nearly double the Q3 2018 price, representing a potential $1.00/mcf quarter-over-quarter improvement should the forward curve be realized. For every $1.00/mcf increase in AECO gas prices, we estimate an additional annual FFO contribution of approximately $50 million.
In the United States, Q3 2018 production averaged 2,979 boe/d, an increase of 280% from the prior quarter, due to the production associated with the Powder River Basin acquisition and development activities during the quarter. Third quarter production also increased following the completion of our first half 2018 drilling program, as we brought the final two (2.0 net) wells of the five (5.0 net) well program on production.
Powder River Basin Acquisition
During the third quarter, we acquired mineral land and producing assets in the Powder River Basin in Wyoming (the "Acquisition") for total cash consideration of approximately $186 million (the "Purchase Price").
The Acquisition is comprised of low base decline, light oil-weighted production and high-quality mineral leasehold in the Powder River Basin in Campbell County, Wyoming (the "Assets"), approximately 40 miles (65 kilometres) northwest of Vermilion's existing operations. The Assets include approximately 55,700 net acres of land (approximately 96% working interest) and approximately 2,500 boe/d (63% oil and NGLs) of production with an estimated annual base decline rate of 13%. Approximately half of the current production comes from three federal secondary recovery units in the Muddy formation, with the remainder coming from higher-netback production from Turner Sand horizontal producers.
Vermilion has identified 93 future drilling locations targeting light oil in the Turner and Parkman tight sandstones, which are expected to be developed using horizontal wells with multi-stage fracs. In these future development zones, the production and reserves are expected to be comprised of approximately 75% crude oil and NGLs. Significant infrastructure already exists in the area, including gas gathering and water source and disposal, which is expected to simplify future development. All of the production on the acquired land is operated and 93% is held-by-production (HBP), giving us control over the pace of development.
The Acquisition is accretive on a per share basis for all pertinent metrics including production, debt-adjusted cash flow(2) and reserves. Making no deduction for land value, transaction metrics equate to $5.40 per boe of proved plus probable ("2P") reserves, and $74,400 per flowing barrel of production. Alternatively, ascribing zero value to the acquired production, the total Acquisition cost is approximately $3,400 per net acre or US$2,600 per net acre. Total 2P reserves attributed to the Assets at an effective date of December 31, 2017 are 34.4(3) mmboe (67% crude oil and NGL), based on an independent evaluation by GLJ Petroleum Consultants Ltd. Using WTI strip pricing of US$72.20/bbl for the remainder of 2018 at October 15, 2018, the operating netback for the current production is estimated at approximately $28.32(1) per boe. Using a 2P finding, development and acquisition cost (based on the reserves in the GLJ report) of $11.80 per boe (including future development capital), the Assets are expected to deliver a 2P after-tax fund flows recycle ratio(2) of 2.4 times. It is anticipated that future netbacks, cash flows and recycle ratios will be enhanced by more highly oil-weighted production additions from the Turner and Parkman Sands.
Using the same strip pricing assumptions as above, the cost of the Acquisition is approximately 6.4 times debt-adjusted cash flow(2) based on 2018 annualized cash flow. The transaction was financed by drawing on our revolving credit facility. Following the Acquisition, we have expanded our credit facility commitment level to $1.8 billion from $1.6 billion, maintaining unutilized revolver capacity at approximately $450 million. Pro-forma the acquisition, our projected year-end 2019 debt-to-fund flows from operations ("FFO") ratio is forecast to be 1.43 times on October 15, 2018 strip pricing, as compared to 1.33 times prior to the acquisition.
The Acquisition expands our presence in a highly-prospective basin where we already operate and are familiar with the land, regulatory, reservoir and geologic characteristics. The Acquisition also increases scale in our US business unit, providing for operational synergies with our existing Turner Sand position, a significant inventory of semi-conventional locations in a well-delineated productive area, and potential for additional consolidation and organic growth in the region. Finally, the Acquisition aligns with our sustainable growth-and-income model by accretively adding low risk assets with strong free cash flow, high netbacks, low base decline rates and strong capital efficiencies on future development.
2019 Budget
Our Board of Directors have approved an E&D capital budget of $530 million for 2019, with associated production guidance of 101,000 to 106,000 boe/d. The midpoint of our 2019 production guidance reflects year-over-year growth of 18%, or 7% on a per share basis, compared to 2018.
Our 2019 capital budget will fund additional activity in all countries except Australia, where we accelerated the originally planned 2019 two-well program into Q4 2018. The 2019 program reflects a full year of development on the Spartan assets, additional capital associated with the recently acquired assets in the Powder River Basin, and also incorporates a significantly expanded drilling program in Europe.
In Europe, we expect to resume drilling in the Netherlands, significantly expand our drilling program in Central and Eastern Europe, commence our inaugural drilling campaign in Germany, and continue with our low risk development plans in France. The majority of the new wells we plan to drill in Europe during 2019 will be targeting natural gas which continues to sell at a significant premium to North American gas prices. In total, we plan to drill 19 (13.7 net) wells in Europe in 2019, representing our most active drilling program in Europe over our 21-year history. This is more than three times the number of wells we drilled in 2018 and over 25% more than our previous high in Europe.
In North America, our activity will continue to focus on our three core areas of west-central Alberta (condensate-rich gas), southeast Saskatchewan (light oil) and the Powder River Basin in Wyoming (light oil), all of which are products with advantaged market access and resulting lower basis differentials. We plan to drill 19.0 (16.7 net) condensate-rich wells in west-central Alberta, 143 (129.0 net) light oil wells in southeast Saskatchewan, and eight (8.0 net) light oil wells in the Powder River Basin.
At October 15, 2018 strip prices, Vermilion expects to fully fund 2019 E&D capital expenditures and dividends from internally generated fund flows from operations. Excess cash generation above capital and dividend outflows is planned for further debt reduction, high-return bolt-on acquisitions, or returned to shareholders. Using the same strip prices as above, and assuming excess cash is used to paydown debt, we project a 2019 total payout of 82% with a year-end debt-to-FFO ratio of 1.43 times. Even at meaningfully lower commodity prices than the current strip, we project that we would remain self-funded for our uses of cash and that our capital program would provide high investment returns. Nonetheless, we have the flexibility to reduce our capital investment program in the event of a significant commodity downturn, and if required, we will prioritize the safety and reliability of our growth-and-income model above growth.
Europe
In France, our E&D budget of $78 million is relatively consistent with our 2018 budget. Following the success of our 2018 Champotran field drilling campaign, we plan to drill an additional four (4.0 net) Champotran wells in the Paris Basin in 2019. Following successful workover campaigns in the Lugos field in the Aquitaine Basin, Vermilion has identified additional infill-drilling opportunities. Vermilion plans to drill one (1.0 net) of these infill wells in the Lugos field in 2019.
In the Netherlands, our 2019 E&D capital budget of $26 million represents a 13% increase from 2018. We plan to drill two (0.9 net) wells in 2019. We were recently granted a positive decision on the EIA (Environmental Impact Assessment) judgement for the two wells included in our 2019 drilling plans and are now awaiting final approval of the drilling permits before proceeding. As part of our 2019 capital activities, we will also conduct permitting work to support our expanded drilling program for the coming years.
In Germany, our E&D capital budget of $24 million represents a 50% increase from our 2018 capital program. We expect to begin drilling our first operated well (0.5 net) in Q1 2019, the Burgmoor Z5 well, in which we own a 46% working interest. This semi-development well has been included as one of the commitment wells on our farm-in with ExxonMobil Production Deutschland GmbH ("EMPG"), and represents the first drilling on the EMPG farm-in. If successful, we anticipate bringing this well on production in early 2020. Additionally, we expect to drill two (2.0 net) sidetrack injector wells from existing well bores in a waterflood within our operated oil assets, along with participating in another sidetrack well on one (0.3 net) of our non-operated gas wells. We will also continue to advance our permitting and other activities associated with the farm-in agreement, with the next drilling following Burgmoor Z5 planned for 2020.
Our Central and Eastern Europe business unit is poised for significantly more activity in 2019, with a capital program of $18 million, up 50% from 2018. We expect to drill four (2.0 net) wells in Slovakia, three (2.5 net) wells in Hungary and three (2.5 net) wells in Croatia. All of these wells are targeting natural gas except for one light oil prospect in Croatia. While we expect production contributions from our Hungarian drilling in 2019, the initial drilling activity in Slovakia and Croatia is not expected to contribute any production in 2019.
In Ireland, we plan a limited capital program, primarily focused on facility maintenance. We expect to become operator of the Corrib gas field before the end of 2018, subject to regulatory approvals and completion of our acquisition, along with Canada Pension Plan Investment Board, of Shell E&P Ireland Limited. During our first year as operator, we will focus primarily on the continued integration and streamlining of the operations while identifying opportunities for future optimization and development projects.
North America
In Canada, we have approved an E&D budget of $319 million for 2019, representing a 23% increase from our post-Spartan capital budget for 2018. This will mark our most active capital program ever in Canada as we focus on our first full year operating the former Spartan assets. We plan to drill or participate in 143 (129.0 net) light oil wells in Saskatchewan and 20 (17.7 net) wells in Alberta including 19 (16.7 net) Mannville wells.
In the United States, our 2019 E&D capital budget of $51 million represents a 31% increase from our 2018 capital program. We plan to drill six (6.0 net) wells on our newly acquired lands, referred to as the Hilight assets, in addition to the drilling of two (2.0 net) wells in our legacy East Finn asset in the Powder River Basin in Wyoming.
Australia
Our 2019 E&D budget of $13 million in Australia will focus on facility maintenance following the acceleration of our originally planned 2019 drilling campaign into Q4 2018. Our intention is to manage production to an average level of approximately 6,000 bbl/d.
E&D Capital Investment by Country
Country | 2019 Budget | 2018 Budget | 2019 vs. 2018 | 2019 | 2018 | |||||
Canada | 319 | 260 | 23% | 146.7 | 125.7 | |||||
France | 78 | 79 | (1)% | 5.0 | 5.0 | |||||
Netherlands | 26 | 23 | 13% | 0.9 | — | |||||
Germany | 24 | 16 | 50% | 0.8 | — | |||||
Ireland | 1 | 1 | —% | — | — | |||||
Australia | 13 | 80 | (84)% | — | 2.0 | |||||
USA | 51 | 39 | 31% | 8.0 | 5.0 | |||||
Central and Eastern Europe | 18 | 12 | 50% | 7.0 | 1.0 | |||||
Total E&D Capital Expenditures | 530 | 510 | 4% | 168.4 | 138.7 |
E&D Capital Investment by Category
Category | 2019 Budget | 2018 Budget | 2019 vs. 2018 |
Drilling, completion, new well equipment and tie-in, workovers and recompletions | 390 | 383 | 2% |
Production equipment and facilities | 100 | 82 | 22% |
Seismic, studies, land and other | 40 | 45 | (11)% |
Total E&D Capital Expenditures | 530 | 510 | 4% |
*2019 Budget reflects foreign exchange assumptions of CAD/USD 1.27, CAD/EUR 1.51 and CAD/AUD 0.92.
Our production plan by business unit can be found in our November 2018 investor presentation on our website.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of cash flows, providing additional certainty with regards to the execution of our dividend and capital programs. In aggregate, we currently have 36% of our expected net-of-royalty production hedged for Q4 2018. Over half of the Q4 2018 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases, up to contract ceilings.
We have currently hedged 62% of anticipated European natural gas volumes for Q4 2018. In view of the compelling longer-term forward market for European gas, we have also hedged 56% and 27% of our anticipated 2019 and 2020 volumes at prices which will provide for strong project economics and free cash flows. In addition, we have hedged 30% of anticipated North American gas volumes for Q4 2018. At present, our philosophy is to keep our oil hedges shorter-term, in view of the backwardation in the oil futures curve. As of October 23, 2018, 16% of our oil production is hedged for 2019. We will continue to add to our hedge positions in all products as suitable opportunities arise.
Environmental, Social and Governance ("ESG")
Vermilion received a top quartile ranking for 2018 for our industry sector in RobecoSAM's annual Corporate Sustainability Assessment ("CSA"). The CSA analyzes sustainability performance across economic, environmental, governance and social criteria, and is the basis of the Dow Jones Sustainability Indices. We believe the integration of sustainability principles into our business is the right thing to do, increases shareholder returns, and reduces long-term risks to our business model. This rating demonstrates our commitment to maintaining leadership in sustainability and ESG performance.
Further demonstrating Vermilion's commitment, our Board of Directors has established a Sustainability Committee to provide oversight with respect to sustainability policy and performance. Members of the committee include independent directors as follows: Tim Marchant (Chair), Carin Knickel, Steve Larke and Bill Roby.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
October 24, 2018
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) | "Debt-adjusted cash flow" represents fund flows from operations prior to the impact of interest charges. Management considers debt-adjusted cash flow to be a useful measure to compare transaction metrics on an unlevered basis. "After-tax fund flows recycle ratio" represents the after-tax netback per boe divided by FD&A costs in dollars per boe. Management considers after-tax fund flows recycle ratio to be a useful measure of capital efficiency. |
(3) | Estimated total proved and proved plus probable reserves attributable to the Assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated August 7, 2018 with an effective date of December 31, 2017, in accordance with National Instrument 51-101 - Standards of Disclosure For Oil and Gas Activities of the Canadian Securities Administrators, using the GLJ (2018-01) price forecast (the "GLJ Report"). |
Guidance
On October 30, 2017, we released our 2018 capital expenditure guidance of $315 million and associated production guidance of between 74,500 to 76,500 boe/d. On January 15, 2018, we increased our capital expenditure guidance to $325 million and production guidance to between 75,000 to 77,500 boe/d to reflect the post-closing impact of the acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer. On April 16, 2018, we increased our capital expenditure guidance to $430 million and production guidance to between 86,000 to 90,000 boe/d to reflect the post-closing impact of the acquisition of Spartan Energy Corp. On July 30, 2018, we increased our capital expenditure guidance to $500 million to reflect the acceleration of our Australia drilling campaign into Q4 2018, and to a lesser extent to account for the impact of foreign exchange fluctuations on our Canadian dollar capital levels. As of October 25, 2018, we are increasing our capital expenditure guidance to $510 million to reflect additional capital activity associated with the assets acquired in the Powder River Basin in August of 2018.
We released our 2019 capital budget and related guidance concurrent with the release of our Q3 2018 results.
The following table summarizes our guidance:
Date | Capital Expenditures ($MM) | Production (boe/d) | |
2018 Guidance | |||
2018 Guidance | October 30, 2017 | 315 | 74,500 to 76,500 |
2018 Guidance | January 15, 2018 | 325 | 75,000 to 77,500 |
2018 Guidance | April 16, 2018 | 430 | 86,000 to 90,000 |
2018 Guidance | July 30, 2018 | 500 | 86,000 to 90,000 |
2018 Guidance | October 25, 2018 | 510 | 86,000 to 90,000 |
2019 Guidance | |||
2019 Guidance | October 25, 2018 | 530 | 101,000 to 106,000 |
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call on Thursday, October 25, 2018 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using conference ID 4254459 from October 25, 2018 at 12:00 PM MST to November 8, 2018 at 9:59 PM MST.
You may also access the audio webcast at https://event.on24.com/wcc/r/1847286/09B4BCE44366A1E0B68513CB800BBEED. The webcast link can be found on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events.
2018 Investor Day
Vermilion will be hosting an Investor Day in Toronto, Ontario on November 27, 2018 to provide an overview of our business operations and future growth prospects. The event will include presentations by senior management from each of our business units. Details of the webcast for the event will be provided closer to the date of the event.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 7.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: cash flows and capital expenditures including, without limitation, statements regarding our 2019 budget; business strategies and objectives; future production and production levels (including the timing thereof); permitting, workover and maintenance, exploration and development plans; drilling plans and schedules; the timing of the anticipated closing of the transition of ownership and operatorship of assets from Shell E&P Ireland Limited and the expected impact of that closing; expected benefits of Vermilion's acquisition of assets in the Powder River Basin in Wyoming; acquisition and disposition plans (including the costs, timing and completion thereof); statements regarding our hedging activities and plans; the ability of Vermilion to maintain its current dividend; the incurrence and rate of income taxes; tax pools and future income taxes; statements regarding our ability to finance planned capital expenditures, dividends, and abandonment and reclamation expenditures; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
This document contains metrics commonly used in the oil and gas industry. These oil and gas metrics do not have any standardized meaning or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used and should therefore not be used to make comparisons. Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, Oct. 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on November 15, 2018 to all shareholders of record on October 31, 2018. The ex-dividend date for this payment is October 30, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 7%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Sept. 17, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on October 15, 2018 to all shareholders of record on September 28, 2018. The ex-dividend date for this payment is September 27, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, Aug. 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on September 17, 2018 to all shareholders of record on August 31, 2018. The ex-dividend date for this payment is August 30, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content with multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-0-23-cdn-cash-dividend-for-september-17--2018-payment-date-300697596.html
SOURCE Vermilion Energy Inc.
DENVER, Aug. 9, 2018 /PRNewswire/ -- The 23rd annual EnerCom conference will deliver the best of the industry to the Denver Downtown Westin Hotel on Aug. 19-22, 2018.
The publicly-traded energy companies at the 2018 EnerCom conference represent a combined enterprise value of more than $275 billion of assets and operations in the U.S. and Canadian shale plays, the Gulf of Mexico, international exploration, plus oilfield service and technology companies.
Conference attendees have a rare opportunity to hear operational and development strategies from several private operators and expert panels that will discuss conventional and unconventional E&P operations, midstream challenges, developing and managing oil and gas operations internationally, and how oil companies can take part in Mexico's energy reform.
Among the private oil companies making presentations at the conference is Anschutz Exploration, a large operator with assets in the Powder River and Washakie Basins of Wyoming, the Piceance and DJ Basins of Colorado and the Unita Basin of Utah.
Other private E&Ps making company presentations include Permian producer Felix Energy and Powder River and Green River Basin operator Samson Resources II.
Panels bring energy industry insight
Private Company Panel
Midstream Panel
Sponsored by Energy Intelligence
Oil & Gas in Mexico Panel
Sponsored by TGS
International Panel
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests. Buyside investors may request meetings on the conference website or contact EnerCom for more information at 303-296-8834.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
2018 Presenting Companies: The Oil & Gas Conference® 2018 presenting companies consist of the following:
Looking at basin and sector, the 2018 EnerCom conference presenting companies and companies participating in panels break out as follows (list is subject to change prior to the conference– please refer to The Oil & Gas Conference website for an updated schedule of presenting companies):
Exploration & Production and Other Energy Companies by Focus Area and Sector
Bakken/Three Forks
Eagle Ford
Permian Basin
Woodford & Other Mid-Continent – SCOOP/STACK
Marcellus/Utica
Niobrara
Gulf of Mexico/Offshore
Haynesville
Enhanced Oil Recovery
Canadian E&Ps
International E&Ps
LNG Export Projects
Oilfield Service Companies
Midstream
Mineral, Royalty, Infrastructure Holders, Acquisition Companies
Private Companies – E&Ps, Midstream, Energy Data and Technology, Energy Capital, Government Energy Agencies
A work-in-progress schedule of the 2018 presenting companies is posted on the conference website and is regularly updated.
Sponsors of The Oil & Gas Conference®
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest independent energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates.
Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; SMBC; Opportune LLP; Petrie Partners; EnergyNet; McGriff, Seibels & Williams, Inc.; Energy Intelligence; and TGS.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Feb. 27-28, 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees. Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
About Opportune LLP
Founded in 2005, Opportune is a leading global energy consulting firm specializing in adding value to clients across the energy industry, including upstream, midstream, downstream, power and gas, commodities trading and oilfield services.
Since we are not an audit firm, we are advocates of our clients and are not subject to the restrictions placed on other firms by regulatory bodies. Using our extensive knowledge of all sectors of the energy industry, we work with clients to provide comprehensive solutions to their operational and financial challenges.
Our practice areas include complex financial reporting, dispute resolution, enterprise risk, outsourcing, process and technology, reserve engineering and geosciences, restructuring, strategy and organization, tax, transactional due diligence and valuation. Opportune LLP is not a CPA firm.
Opportune's corporate headquarters are in Houston, Texas. The firm also has offices in Dallas, Denver, New York City, Tulsa, and the UK. For more information please call Ashley Hunt, Marketing Coordinator,
713.490.5050 and visit the web site https://opportune.com/.
About Petrie Partners, LLC
Petrie Partners, LLC is a boutique investment banking firm offering financial advisory services to the oil and gas industry. We provide specialized advice on mergers, divestitures and acquisitions and private placements.
The firm was formed in 2011 (as Strategic Energy Advisors) by senior bankers formerly with Bank of America Merrill Lynch and Petrie Parkman & Co., an investment bank that built a reputation as a most trusted advisor to energy clients during the nearly two decades leading up to its merger into Merrill Lynch in 2006.
Through tenure with Petrie Parkman, Merrill Lynch and Bank of America Merrill Lynch, the senior members of the Petrie team bring to bear an average of more than 25 years of energy investment banking experience, including over 300 energy M&A and capital raising transactions representing over $350 billion of aggregate consideration.
For information about the firm, please visit www.petrie.com or call the firm's Denver office (303.953.6768) or the Houston office (713.659.0760).
About EnergyNet
EnergyNet is the only continuous oil and gas auction and sealed bid transaction service that facilitates the sale of producing working interests (operated and non-operated), overrides, royalties, mineral interests, and non-producing leasehold. EnergyNet is a continuous oil and gas property marketplace with due diligence and bidding available 24/7/365, where auctions and sealed bid packages close weekly. Most of the properties EnergyNet sells are located in the lower 48 United States and typically range in value from $1,000 to $100,000,000.
Details about how to buy and sell oil and gas properties using the EnergyNet online auction service are available on the website at https://www.energynet.com/.
About McGriff, Seibels & Williams, Inc.
McGriff, Seibels & Williams is one of the most progressive insurance brokerage firms in the United States, leading the way with innovative programs to protect clients' financial interests. Services include construction risk, energy and marine, surety, employee benefits and financial services. McGriff's Energy & Marine Division offers specialty services for clients with worldwide operations and potentially catastrophic exposures. Our expertise in this niche industry has made us one of the largest independent energy brokers in the U.S. and one of the top five energy brokers worldwide.
Our client base includes more than 50 electric/gas utility and merchant energy companies, several coal mining companies, and more than 70 E&P companies. It also includes the Strategic Petroleum Reserve and numerous oilfield service companies, including vessel operators, offshore drilling companies, and international marine construction companies.
We will structure and implement a domestic or foreign program for virtually any type of energy-related risk. We have more than 125 professionals in our energy division. Using alternative risk transfer and traditional insurance solutions, we determine the appropriate combination of coverage and risk assumption.
Please contact the company through the website or by calling 800 476 - 2211.
About Energy Intelligence
Energy Intelligence has been a leading independent provider of objective insight, unbiased analysis and reliable data for over 60 years. With offices in New York, London, Houston, Dubai, Moscow, Washington, Singapore and Brussels, we provide decision-makers with critically important information on issues and events affecting the global energy complex.
Our benchmark Information Services, Petroleum Intelligence Weekly, Oil Daily, Natural Gas Week, World Gas Intelligence and Energy Compass, are produced by highly experienced journalists, and our research reports and advisory services are provided by highly regarded analysts and economists.
Information on Energy Intelligence is available at the company website: https://www.energyintel.com/pages/non-subscriber.aspx
About TGS
TGS was founded in Houston in 1981 and over time built the dominant 2D multi-client data library in the Gulf of Mexico. The company expanded further into North America and West Africa and added a substantial 3D portfolio in the Gulf of Mexico.
Also in 1981, NOPEC was founded in Oslo and began building an industry-leading multi-client 2D database in the North Sea, with additional operations in Australia and the Far East. In 1997, NOPEC went public on the Oslo Stock Exchange. In 1998, the companies merged to form TGS-NOPEC Geophysical Company (TGS), creating a winning combination for investors, customers and employees. Since then, TGS has set the standard for geoscientific data around the world.
Additional information is available at the company website: http://www.tgs.com/about-tgs/company-history/.
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SOURCE EnerCom, Inc.
CALGARY, July 30, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three and six months ended June 30, 2018.
The unaudited financial statements and management discussion and analysis for the three and six months ended June 30, 2018, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
($M except as indicated) |
Q2 2018 |
Q1 2018 |
Q2 2017 |
YTD 2018 |
YTD 2017 | |
Financial |
||||||
Petroleum and natural gas sales |
394,498 |
318,269 |
271,391 |
712,767 |
532,992 | |
Fund flows from operations |
192,990 |
157,480 |
147,123 |
350,470 |
290,557 | |
Fund flows from operations ($/basic share) (1) |
1.43 |
1.29 |
1.22 |
2.73 |
2.43 | |
Fund flows from operations ($/diluted share) (1) |
1.41 |
1.27 |
1.20 |
2.69 |
2.39 | |
Net (loss) earnings |
(60,224) |
25,139 |
48,264 |
(35,085) |
92,804 | |
Net (loss) earnings ($/basic share) |
(0.45) |
0.21 |
0.40 |
(0.27) |
0.78 | |
Capital expenditures |
80,129 |
128,618 |
58,875 |
208,747 |
154,764 | |
Acquisitions |
1,468,645 |
93,078 |
993 |
1,561,723 |
3,613 | |
Asset retirement obligations settled |
2,626 |
3,591 |
2,120 |
6,217 |
4,369 | |
Cash dividends ($/share) |
0.690 |
0.645 |
0.645 |
1.290 |
1.335 | |
Dividends declared |
98,604 |
79,005 |
77,858 |
154,451 |
177,609 | |
% of fund flows from operations |
51% |
50% |
53% |
51% |
53% | |
Net dividends (1) |
78,629 |
59,364 |
48,617 |
89,704 |
137,993 | |
% of fund flows from operations |
41% |
38% |
33% |
39% |
31% | |
Payout (1) |
161,384 |
191,573 |
109,612 |
248,837 |
352,957 | |
% of fund flows from operations |
84% |
122% |
75% |
101% |
86% | |
Net debt |
1,787,603 |
1,514,645 |
1,314,766 |
1,787,603 |
1,314,766 | |
Ratio of net debt to annualized fund flows from operations |
2.3 |
2.4 |
2.2 |
2.6 |
2.3 | |
Operational |
||||||
Production |
||||||
Crude oil and condensate (bbls/d) |
34,574 |
27,008 |
28,525 |
30,812 |
27,683 | |
NGLs (bbls/d) |
5,651 |
5,126 |
3,821 |
5,390 |
3,260 | |
Natural gas (mmcf/d) |
242.40 |
228.20 |
209.36 |
235.34 |
209.71 | |
Total (boe/d) |
80,625 |
70,167 |
67,240 |
75.425 |
65.896 | |
Average realized prices |
||||||
Crude oil and condensate ($/bbl) |
87.50 |
80.03 |
64.35 |
84.32 |
66.25 | |
NGLs ($/bbl) |
26.06 |
25.37 |
20.98 |
25.73 |
22.28 | |
Natural gas ($/mcf) |
4.77 |
5.81 |
4.75 |
5.27 |
5.18 | |
Production mix (% of production) |
||||||
% priced with reference to WTI |
29% |
21% |
20% |
25% |
19% | |
% priced with reference to AECO |
26% |
26% |
24% |
26% |
23% | |
% priced with reference to TTF and NBP |
24% |
29% |
28% |
26% |
30% | |
% priced with reference to Dated Brent |
21% |
24% |
28% |
23% |
28% | |
Netbacks ($/boe) |
||||||
Operating netback (1) |
32.85 |
31.05 |
28.72 |
32.01 |
30.08 | |
Fund flows from operations netback |
26.29 |
25.29 |
23.66 |
25.81 |
24.63 | |
Operating expenses |
10.82 |
10.99 |
10.14 |
0.01 |
0.01 | |
Average reference prices |
||||||
WTI (US $/bbl) |
67.88 |
62.87 |
48.28 |
65.37 |
50.10 | |
Edmonton Sweet index (US $/bbl) |
62.43 |
56.98 |
46.03 |
59.70 |
47.20 | |
Dated Brent (US $/bbl) |
74.35 |
66.76 |
49.83 |
70.55 |
51.81 | |
AECO ($/mmbtu) |
1.18 |
2.08 |
2.78 |
1.63 |
2.74 | |
NBP ($/mmbtu) |
9.42 |
9.96 |
6.52 |
9.69 |
7.26 | |
TTF ($/mmbtu) |
9.50 |
9.59 |
6.74 |
9.54 |
7.21 | |
Average foreign currency exchange rates |
||||||
CDN $/US $ |
1.29 |
1.26 |
1.34 |
1.28 |
1.33 | |
CDN $/Euro |
1.54 |
1.55 |
1.48 |
1.55 |
1.44 | |
Share information ('000s) |
||||||
Shares outstanding - basic |
152,363 |
122,769 |
120,947 |
152,363 |
120,947 | |
Shares outstanding - diluted (1) |
155,355 |
125,794 |
123,794 |
155,355 |
123.794 | |
Weighted average shares outstanding - basic |
134,603 |
122,390 |
120,514 |
128,531 |
119,578 | |
Weighted average shares outstanding - diluted (1) |
136,559 |
124,304 |
122,660 |
130,224 |
121,488 |
(1) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
Message to Shareholders
During the second quarter, we completed the $1.4 billion acquisition of Spartan Energy Corp., a publicly traded southeast Saskatchewan oil producer. This was the largest acquisition in the history of our company. We are extremely pleased to bring the former Spartan employees and assets into the Vermilion family. The integration of both the assets and employees has progressed very well, and we have no doubt that each new employee will make a meaningful contribution to our future success. The transaction significantly increases our presence in the desirable operating jurisdiction of southeast Saskatchewan, while increasing our exposure to high netback light oil in a highly advantaged product marketing setting. While the development plans for the balance of the year will largely align with the capital program Spartan previously had in place, we have already identified additional future development and production optimization opportunities across the asset base, along with a number of cost savings opportunities. Following the full integration of the Spartan assets, Vermilion will have an established production base of approximately 100,000 boe/d with the capability of generating over $1.2 billion of FFO based on an annualized estimate for Q4 2018 at the strip. We expect the Spartan acquisition to enhance our ability to execute our self-funded growth and income business model, while increasing our capital markets market scale.
We achieved quarter-over-quarter production growth of 15%, or 5% on a per share basis, largely driven by the Spartan acquisition and organic growth in Canada, France and the US following our first quarter 2018 drilling programs in these countries. Production was down slightly in our other business units primarily due to a combination of natural decline, maintenance and third-party facility downtime. For the remainder of the year, we expect production to increase in most business units due to lower downtime and, in some cases, regulatory approvals.
Oil prices strengthened by over 10% in Canadian dollar terms during the second quarter of 2018, contributing to a 23% increase in FFO relative to the prior quarter. The combination of higher oil prices and a weaker Canadian dollar provides significant leverage to our FFO and free cash flow(1) ("FCF") as the majority of our costs, capital investments and dividends are paid in Canadian dollars.
We have increased our 2018 capital budget by $70 million to $500 million to take advantage of cost savings associated with accelerating our Australia drilling program, and to account for minor capital increases in other business units mainly due to changes in foreign exchange rates as compared to our original budget. We had originally planned to drill two wells in Australia in 2019, but have identified an opportunity to save approximately $12 million by drilling them in Q4 2018. In addition, we have also reallocated some capital and revised the production mix between business units to account for permitting delays in the Netherlands. Our 2018 corporate production guidance remains unchanged at 86,000 to 90,000 boe/d, as we remain on track to achieve this target with an anticipated exit rate in excess of 100,000 boe/d. The change in capital allocation and production split across business units can be found in our updated corporate presentation located on our website.
In conjunction with the Spartan acquisition, we announced the elimination of the discount associated with our dividend reinvestment program ("DRIP") effective with the June 2018 dividend payable in July 2018. The DRIP participation rate for the July dividend payment dropped to 5%, compared to approximately 25% previously, resulting in significantly less proceeds and equity issuance from this program. We anticipate the participation rate to remain at about 5% in the future. Based on the forward commodity strip, we expect to fully fund our revised capital program and our dividend with internally generated FFO, resulting in a total payout ratio of 90%.
Q2 2018 Operations Review
Europe
In France, Q2 2018 production averaged 11,683 boe/d, an increase of 6% from the prior quarter. The increase was primarily due to production additions following the completion of our Q1 2018 drilling program in the Neocomian and Champotran fields. Production also benefited from less well downtime compared to the previous quarter, in addition to the successful execution of several workovers performed during the first half of the year.
In the Netherlands, Q2 2018 production averaged 7,335 boe/d, which was down 3% from the prior quarter. Activity during the second quarter was focused on maintenance, well workovers, permitting and evaluation of 3D seismic acquired last year. We have completed an initial assessment of the 3D seismic data and have identified 15 future drilling prospects, the majority of which can be reached from existing wellsites. Subsequent to the end of the second quarter, we received regulatory approval for the production plan for the Eesveen-02 well. This well produced at approximately 10 mmcf/d net to Vermilion during its extended production test last fall, and is expected to come on production in mid-August 2018. We continue to pursue permitting of our planned three well (1.5 net) drilling program included in our original 2018 budget. However, we believe delays in the permitting process, largely driven by regulatory bandwidth being consumed by the response to seismicity in the Groningen field, will push these wells out of this budget year. More broadly, the Ministry of Economic Affairs recently published a policy letter reiterating its support for Small Fields development in the Netherlands. We have detailed in our corporate presentation a new drilling schedule for the Netherlands, which takes into account regulatory delays in the near term, as well as our long-term plan for more time-efficient well proposals by utilizing a greater proportion of long reach wells to access new pools. This schedule anticipates increasing the pace of our permitting and drilling activities in the Netherlands over time and continuing to grow our production base in this high-netback business unit.
In Ireland, production from Corrib averaged 57 mmcf/d (9,426 boe/d) in Q2 2018, a 7% decrease from the prior quarter due to natural declines and minor plant downtime related to external electricity supply issues. Production declines were consistent with our numerical simulation of reservoir performance. We made significant progress on activities associated with the transition of ownership and operatorship from Shell to CPPIB and Vermilion. The transition has progressed well with all technical aspects being ready. We now anticipate receiving final approvals from the necessary authorities and closing of the transaction in the second half of 2018. Although this closing date is later than our original expectation, and will have a modest impact on our booked production from Ireland, Vermilion will still benefit from all interim period cash flows between January 1, 2017 and closing as a reduction of purchase price.
In Germany, production in Q2 2018 averaged 3,447 boe/d, a decrease of 9% from the previous quarter. The decrease was primarily due to downtime at a non-operated gas processing facility resulting in 22 days of downtime during the quarter. A portion of the volumes were brought back on-line mid-June; however, approximately two-thirds of the volumes affected by the downtime are not anticipated to come back on-line until later in the third quarter of 2018. Our capital activity in Germany continues to focus on well workover and optimization projects on our operated assets and planning activities related to the Burgmoor Z5 well (46% working interest) to be drilled in early 2019.
In Hungary, activity during the second quarter of 2018 was primarily focused on preparations to bring our first exploratory well in the South Battonya concession, the Mh-Ny-07 well (100% working interest), on production during Q3 2018. Work on pipeline and facility tie-in continues, and we anticipate bringing the well on production during August 2018. Permitting activities have been initiated in preparation for the drilling of our second commitment well in the South Battonya concession in 2019. In Croatia, we completed the first phase of our 2D seismic data acquisition, which revealed positive results on the 150 km of data obtained to date. We have also begun permitting and planning activities in Croatia and Slovakia in preparation for our 2019 drilling campaigns.
North America
In Canada, production averaged 43,817 boe/d in Q2 2018, representing a 37% increase from the previous quarter primarily due to the production contribution from the Spartan acquisition. Production also benefited from our successful Q1 drilling program and less weather-related downtime and planned maintenance on third party infrastructure as compared to Q1 2018. We drilled or participated in 18 (16.2 net) wells and brought on production nine (7.9 net) wells in Q2 2018. The majority of the drilling activity in the quarter occurred on the acquired Spartan assets, with 17 (15.2 net) of the 18 wells drilled in Canada coming from the inventory we acquired from Spartan. We currently have 4 rigs operating on the acquired Spartan assets and one rig operating on our legacy southeast Saskatchewan assets, along with one rig operating in Alberta.
In the United States, Q2 2018 production averaged 784 boe/d, an increase of 27% from the prior quarter primarily due to the contribution from two (2.0 net) of the five (5.0 net) wells drilled in Q1 2018 and resumption of gas sales following the restart of a third-party gas facility in mid-Q1 2018. The two wells placed on production averaged peak 30-day production rates of 280 boe/d per well (84% oil). Two (2.0 net) wells are in the process of being completed and one (1.0 net) well was shut-in after initial testing due to uneconomic production levels.
Australia
In Australia, production averaged 4,132 bbl/d in Q2 2018, representing a 17% decrease from the previous quarter primarily due to downtime associated with well workover activity to optimize electrical submersible pump completions. These maintenance activities have been completed and we expect to recover this production during the second half of the year. Other activity during the second quarter was focused on preparing for our next drilling program. We have elected to accelerate our originally planned 2019 Australia drilling campaign into Q4 2018. There are several significant advantages to conducting this activity ahead of our original schedule. First, a suitable rig is now working for another operator on the northwest shelf, while there is no assurance that such a rig could be mobilized at reasonable cost in 2019. Second, the presence of the rig generates economies in mobilization and demobilization, support vessels and other services. Third, offshore services are already tightening, and the potential for higher services costs exists in 2019. Finally, engaging the rig that is currently operating on the northwest shelf should ensure that our wells are completed before the onset of cyclone season in Q1 2019. Although the early drilling is not expected to contribute production in 2018, it will save approximately $12 million in capital compared to drilling in 2019 (even assuming no rebound in offshore services prices in 2019). The total estimated cost for the two-well program is approximately $65 million.
Environmental, Social and Governance ("ESG")
Vermilion's MSCI ESG rating was recently re-affirmed as "A" for 2018, marking the second consecutive year Vermilion has scored at this level, and our Governance Metrics score ranked in the top decile globally. Vermilion also scored 82 out of 100 on the annual ratings conducted by Sustainalytics, ranking at the top of our peer group. Sustainalytics rates the sustainability of participating companies based on their environmental, social and governance performance. Both of these ratings are a product of our commitment to maintaining leadership in sustainability and ESG performance.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of cash flows, providing additional certainty with regards to the execution of our dividend and capital programs. In aggregate, we currently have 40% of our expected net-of-royalty production hedged for 2018. These hedges include both swaps and collars. Our diversified commodity mix, including more than a one-third cash flow contribution from relatively high-priced European natural gas, gives us unique flexibility in managing our individual commodity exposures. Based on the current level and term structures in the oil, North American gas and European gas forward curves, we have elected to lock down a greater percentage of our gas exposures, particularly for European gas. We have currently hedged 66% of anticipated European natural gas volumes for 2018. In view of the compelling longer-term forward market for European gas we have also hedged 54% and 27% of our anticipated 2019 and 2020 volumes at prices which should provide for strong project economics and free cash flows. In addition, we have hedged 32% of anticipated North American gas volumes for 2018. In view of backwardation in the oil forward markets, we are keeping oil hedges shorter-term, with 24% hedged for the second half of this year. At present, our philosophy is to maintain greater torque to longer-term oil prices, with only 7% of our expected oil production hedged for 2019. We will continue to add to our hedge positions in all products as suitable opportunities arise.
Board of Directors
Vermilion is pleased to announce the appointment of Ms. Carin Knickel to the Board of Directors, effective August 1, 2018. Ms. Knickel brings over 39 years of experience in human resources, business development and crude oil and natural gas marketing. She currently serves on the boards of Hudbay Minerals Inc, Whiting Petroleum Corporation and the National MS Society (Colorado/Wyoming Chapter). Prior to joining these boards, Ms. Knickel worked at ConocoPhillips for 33 years, where she held a variety of leadership positions globally across several business lines, most recently as the Corporate Vice President of Global Human Resources. She has a BSc - Business, Marketing from the University of Colorado at Boulder and an MSc - Sloan Fellowship, Management from the Massachusetts Institute of Technology.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
July 27, 2018
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis |
2018 Guidance
On October 30, 2017, we released our 2018 capital expenditure guidance of $315 million and associated production guidance of between 74,500 to 76,500 boe/d. On January 15, 2018, we increased our capital expenditure guidance to $325 million and production guidance to between 75,000 to 77,500 boe/d to reflect the post-closing impact of the acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer. On April 16, 2018, we increased our capital expenditure guidance to $430 million and production guidance to between 86,000 to 90,000 boe/d to reflect the post-closing impact of the acquisition of Spartan Energy Corp. On July 30, 2018, we increased our capital expenditure guidance to $500 million to reflect the acceleration of our Australia drilling campaign into Q4 2018, and to a lesser extent to account for the impact of foreign exchange fluctuations on our Canadian dollar capital levels.
The following table summarizes our guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | |
2018 Guidance |
|||
2018 Guidance |
October 30, 2017 |
315 |
74,500 to 76,500 |
2018 Guidance |
January 15, 2018 |
325 |
75,000 to 77,500 |
2018 Guidance |
April 16, 2018 |
430 |
86,000 to 90,000 |
2018 Guidance |
July 30, 2018 |
500 |
86,000 to 90,000 |
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call on Monday, July 30, 2018 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). A recording of the conference call will be available for replay by calling 1-855-859-2056 and using conference ID 8229598 from July 30, 2018 at 12:00 PM MST to August 13, 2018 at 9:59 PM MST.
You may also access the audio webcast at https://event.on24.com/wcc/r/1782675/5DC6DC44C8A4F63A0B7186B3D7113224. The webcast link can be found on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 5.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
DENVER, July 25, 2018 /PRNewswire/ -- An impressive roster of CEOs across the upstream and oilfield service and technology spectrum will be at the Denver Downtown Westin Hotel Aug. 20, 21 and 22, 2018, to give presentations at EnerCom's The Oil & Gas Conference®.
EnerCom conference E&Ps are producing more than 3.2 million barrels of oil per day. The presenting North American shale E&Ps, other explorers and producers, international E&Ps, and global oilfield service and technology companies represent a combined market value of $203 billion and a combined enterprise value of $252 billion—53% higher than last year.
As to basin and sector, the 2018 EnerCom conference presenting companies break out as follows (list is subject to change prior to conference– please refer to The Oil & Gas Conference website for an updated schedule of presenting companies):
Exploration & Production, Oilfield Service Companies by Focus Area and Sector
Bakken/Three Forks
Eagle Ford
Permian Basin
Woodford & Other Mid-Continent – SCOOP/STACK
Marcellus/Utica
Niobrara
Gulf of Mexico/Offshore
Haynesville
Pinedale – Jonah Field – Uinta Basin
Enhanced Oil Recovery
Canadian E&Ps
International E&Ps
Oilfield Service Companies
Midstream
Mineral, Royalty, Infrastructure Holders, Acquisition Companies
Private Companies – E&Ps, Midstream, Energy Data and Technology Providers, Energy Capital, Government Energy Agencies
A work-in-progress schedule of the 2018 presenting companies is posted on the conference website and will be regularly updated.
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests. Buyside investors may request meetings on the conference website or contact EnerCom for more information at 303-296-8834.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; SMBC; Opportune LLP; Petrie Partners; and SunTrust Robinson Humphrey.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Feb. 27-28, 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
About Opportune LLP
Founded in 2005, Opportune is a leading global energy consulting firm specializing in adding value to clients across the energy industry, including upstream, midstream, downstream, power and gas, commodities trading and oilfield services.
Since we are not an audit firm, we are advocates of our clients and are not subject to the restrictions placed on other firms by regulatory bodies. Using our extensive knowledge of all sectors of the energy industry, we work with clients to provide comprehensive solutions to their operational and financial challenges.
Our practice areas include complex financial reporting, dispute resolution, enterprise risk, outsourcing, process and technology, reserve engineering and geosciences, restructuring, strategy and organization, tax, transactional due diligence and valuation. Opportune LLP is not a CPA firm.
Opportune's corporate headquarters are in Houston, Texas. The firm also has offices in Dallas, Denver, New York City, Tulsa, and the UK. For more information please call Ashley Hunt, Marketing Coordinator,
713.490.5050 and visit the web site https://opportune.com/.
About Petrie Partners, LLC
Petrie Partners, LLC is a boutique investment banking firm offering financial advisory services to the oil and gas industry. We provide specialized advice on mergers, divestitures and acquisitions and private placements.
The firm was formed in 2011 (as Strategic Energy Advisors) by senior bankers formerly with Bank of America Merrill Lynch and Petrie Parkman & Co., an investment bank that built a reputation as a most trusted advisor to energy clients during the nearly two decades leading up to its merger into Merrill Lynch in 2006.
Through tenure with Petrie Parkman, Merrill Lynch and Bank of America Merrill Lynch, the senior members of the Petrie team bring to bear an average of more than 25 years of energy investment banking experience, including over 300 energy M&A and capital raising transactions representing over $350 billion of aggregate consideration.
For information about the firm, please visit www.petrie.com or call the firm's Denver office (303.953.6768) or the Houston office (713.659.0760).
About SunTrust Robinson Humphrey
SunTrust Robinson Humphrey (STRH) is a leading, full-service corporate and investment bank dedicated to helping you successfully manage and grow your company through a comprehensive range of strategic advisory, capital raising, risk management, financing and investment solutions. We also offer a complete array of sales, trading and research services in both fixed income and equity.
Our firm's history dates back to 1894, and through the years we have built a reputation for delivering superior client service and in-depth market and industry expertise. At STRH, we are committed to your success. Our team of experienced professionals works closely with you to understand your unique needs and goals to provide sound, unbiased guidance that draws from the significant resources from across our entire universal banking platform. This collaborative One Team approach is focused solely on partnering with you to secure meaningful value throughout the life cycle of your company.
Our Energy & Power Investment Banking Group provides corporate and investment banking services to domestically headquartered companies in the energy and power sectors. We partner with our clients across the energy value chain to deliver full-service strategic advisory and financing solutions.
For more information please visit https://www.suntrustrh.com/industry-coverage/energy-power .
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SOURCE EnerCom, Inc.
CALGARY, July 16, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on August 15, 2018 to all shareholders of record on July 31, 2018. The ex-dividend date for this payment is July 30, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 5.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
DENVER, June 27, 2018 /PRNewswire/ -- EnerCom, Inc. has posted the list of oil and gas companies and energy sector experts who will be presenters at the 23rd annual edition of The Oil & Gas Conference®, coming August 19-22, 2018, to the Westin Denver Downtown.
Public and Private Company Presenters: The 2018 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations spanning 40 countries and six continents, including all U.S. shale basins, the Gulf of Mexico, Canada, Latin America and Africa.
A work-in-progress schedule of the 2018 presenting companies is now posted on the conference website and will be regularly updated.
Some of the companies that are scheduled to present in August at EnerCom's The Oil & Gas Conference® include, but are not limited to:
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests. Buyside investors may request meetings on the conference website or contact EnerCom for more information at 303-296-8834.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; and SMBC.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Feb. 27-28, 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA
joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
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SOURCE EnerCom, Inc.
CALGARY, June 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on July 16, 2018 to all shareholders of record on June 29, 2018. The ex-dividend date for this payment is June 28, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
As previously announced, we have also approved an amendment to our Dividend Reinvestment Plan ("DRIP") to eliminate the discount to the prevailing Average Market Price of dividends reinvested in Vermilion shares from the current level of 2%. All other terms and conditions related to participation in our DRIP remain unchanged. Please visit our website for the amended plan documents.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content with multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-0-23-cdn-cash-dividend-for-july-16--2018-payment-date-300666864.html
SOURCE Vermilion Energy Inc.
CALGARY, May 28, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We" or "Our") (TSX, NYSE: VET) is pleased to announce that we have closed the acquisition of Spartan Energy Corp. ("Spartan") for total consideration of $1.40 billion, comprised of $1.23 billion in Vermilion shares (valued at closing price prior to announcement) plus the assumption of approximately $175 million in debt, pursuant to the terms of the previously announced arrangement agreement (the "Arrangement").
Under the terms of the Arrangement, Vermilion acquired all of the issued and outstanding common shares of Spartan on the basis of 0.1476 of a Vermilion share for each Spartan common share, resulting in the issuance of 27.9 million Vermilion common shares (the "Acquisition").
The Spartan common shares will be delisted from the TSX in approximately 2 or 3 trading days. The Vermilion shares issued to the former holders of Spartan common shares pursuant to the Arrangement will be listed on the TSX and NYSE under the symbol "VET".
The Spartan assets are comprised of high-netback, light oil producing properties covering approximately 480,000 net acres of land (80% average working interest), including 400,000 net acres in southeast Saskatchewan with multi-zone potential. In addition, the Acquisition includes approximately 80,000 net acres of land in other areas of Saskatchewan, Alberta and Manitoba. Production from the assets is projected to be approximately 23,000 boe/d (91% oil) during 2018. The Acquisition also includes ownership and control of producing infrastructure that are synergistic with our existing assets, as well as significant 2D and 3D seismic data. Under the current commodity strip, we expect the assets to generate cash flow in excess of capital requirements for continued growth plus the incremental gross dividends associated with the new shares issued.
We look forward to integrating Spartan employees into our organization, and believe our combined enterprise will have the operating, technical and financial capability to maximize the value of our combined southeast Saskatchewan assets.
Credit Facility Extension and Increase
We have negotiated an extension of our revolving credit facility with our syndicate of lenders to May 31, 2022. We elected to increase the total facility amount to $1.6 billion from $1.4 billion, maintaining roughly the same unutilized capacity as before the Acquisition.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Disclaimer
Certain statements included or incorporated by reference in this press release may constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this press release may include, but are not limited to:
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
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SOURCE Vermilion Energy Inc.
CALGARY, May 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on June 15, 2018 to all shareholders of record on May 31, 2018. The ex-dividend date for this payment is May 30, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
View original content with multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-0-23-cdn-cash-dividend-for-june-15--2018-payment-date-300648154.html
SOURCE Vermilion Energy Inc.
CALGARY, April 26, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three months ended March 31, 2018.
The unaudited financial statements and management discussion and analysis for the three months ended March 31, 2018, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
Highlights
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Mh-Ny-07 well tested gas at a rate of 5.8 mmcf/d over the final two hours of a 22 hour |test period at a stabilized wellhead pressure of 1,065 psi on a |
($M except as indicated) |
Q1 2018 |
Q4 2017 |
Q1 2017 | |||
Financial |
||||||
Petroleum and natural gas sales |
318,269 |
317,341 |
261,601 | |||
Fund flows from operations |
157,480 |
181,253 |
143,434 | |||
Fund flows from operations ($/basic share) (1) |
1.29 |
1.49 |
1.21 | |||
Fund flows from operations ($/diluted share) (1) |
1.27 |
1.47 |
1.19 | |||
Net earnings |
25,139 |
8,645 |
44,540 | |||
Net earnings ($/basic share) |
0.21 |
0.07 |
0.38 | |||
Capital expenditures |
128,618 |
74,303 |
95,889 | |||
Acquisitions |
93,078 |
3,048 |
2,620 | |||
Asset retirement obligations settled |
3,591 |
3,216 |
2,249 | |||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 | |||
Dividends declared |
79,005 |
78,653 |
76,593 | |||
% of fund flows from operations |
50% |
43% |
53% | |||
Net dividends (1) |
59,364 |
56,836 |
41,087 | |||
% of fund flows from operations |
38% |
31% |
29% | |||
Payout (1) |
191,573 |
134,355 |
139,225 | |||
% of fund flows from operations |
122% |
74% |
97% | |||
Net debt |
1,514,645 |
1,371,790 |
1,377,636 | |||
Ratio of net debt to annualized fund flows from operations |
2.4 |
1.9 |
2.4 | |||
Operational |
||||||
Production |
||||||
Crude oil and condensate (bbls/d) |
27,008 |
27,830 |
26,832 | |||
NGLs (bbls/d) |
5,126 |
5,279 |
2,694 | |||
Natural gas (mmcf/d) |
228.2 |
238.27 |
210.07 | |||
Total (boe/d) |
70,167 |
72,821 |
64,537 | |||
Average realized prices |
||||||
Crude oil and condensate ($/bbl) |
80.03 |
74.12 |
68.59 | |||
NGLs ($/bbl) |
25.37 |
29.28 |
24.13 | |||
Natural gas ($/mcf) |
5.81 |
5.23 |
5.62 | |||
Production mix (% of production) |
||||||
% priced with reference to WTI |
21% |
21% |
17% | |||
% priced with reference to AECO |
26% |
25% |
22% | |||
% priced with reference to TTF and NBP |
29% |
30% |
32% | |||
% priced with reference to Dated Brent |
24% |
24% |
29% | |||
Netbacks ($/boe) |
||||||
Operating netback (1) |
31.05 |
30.77 |
31.62 | |||
Fund flows from operations netback |
25.29 |
27.13 |
25.75 | |||
Operating expenses |
10.99 |
9.76 |
9.35 | |||
Average reference prices |
||||||
WTI (US $/bbl) |
62.87 |
55.40 |
51.92 | |||
Edmonton Sweet index (US $/bbl) |
56.98 |
54.26 |
48.37 | |||
Dated Brent (US $/bbl) |
66.76 |
61.39 |
53.78 | |||
AECO ($/mmbtu) |
2.08 |
1.69 |
2.69 | |||
NBP ($/mmbtu) |
9.96 |
8.70 |
7.96 | |||
TTF ($/mmbtu) |
9.59 |
8.36 |
7.65 | |||
Average foreign currency exchange rates |
||||||
CDN $/US $ |
1.26 |
1.27 |
1.32 | |||
CDN $/Euro |
1.55 |
1.50 |
1.41 | |||
Share information ('000s) |
||||||
Shares outstanding - basic |
122,769 |
122,119 |
119,046 | |||
Shares outstanding - diluted (1) |
125,794 |
125,140 |
122,135 | |||
Weighted average shares outstanding - basic |
122,390 |
121,858 |
118,632 | |||
Weighted average shares outstanding - diluted |
124,304 |
123,450 |
120,722 |
(1) The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
Message to Shareholders
Our 2018 capital program is now well underway. We completed our planned 2018 drilling programs in France, Hungary, and the US, while initiating Canadian drilling and continuing to advance future projects for our other business units. Most of the wells drilled in Q1 2018 were completed and tied-in late in the first quarter or early in the second quarter and will provide meaningful contributions to our growth profile for the remainder of 2018. As previously reported, we drilled our first well in Hungary during the quarter, representing our first well in the Central and Eastern European Business Unit, and are pleased with the initial results. We are planning to drill several more wells in Hungary, Slovakia and Croatia over the coming years, and are optimistic about the future development prospects for this region. In Ireland, the transition of Corrib ownership continues to progress, with the transfer of operatorship to Vermilion expected to occur in the middle of 2018. Following the close of this transaction, we will operate approximately 90% of our production.
Subsequent to the end of the quarter, we announced the strategic acquisition of Spartan Energy Corp. ("Spartan") for total consideration of $1.40 billion, comprised of $1.23 billion in Vermilion shares plus the assumption of approximately $175 million of Spartan's debt. This acquisition is a value-adding investment which meets our disciplined M&A criteria and is accretive to all pertinent metrics, adding 7% to production per share, 15% to fund flows per share and 13% to total proved plus probable reserves per share. It significantly increases our position in southeast Saskatchewan, and aligns with our sustainable growth-and-income model by adding 23,000 boe/d (91% oil) of high-netback, low decline oil assets with free cash flow and strong capital efficiencies on future development. We believe that this business combination will significantly benefit both Vermilion's existing shareholders and Spartan's shareholders. In addition, we believe that both shareholder groups will benefit from increased scale in both our operations and in the capital markets. We look forward to integrating Spartan employees into our organization, and believe our combined enterprise will have the operating, technical and financial capability to maximize the value of these southeast Saskatchewan assets. Our news release from April 16, 2018 contains further discussion and details on the transaction.
Global commodity prices were strong during Q1 2018. With the exception of natural gas in western Canada, they have exhibited further strength in recent weeks as supply and demand fundamentals continue to improve. We continue to benefit from our exposure to global commodity benchmarks, including Brent oil which currently trades at an approximate US$5.00 per barrel premium over WTI, and European gas which is currently trading at approximately $9.00 Canadian equivalent per mmbtu. This exposure to higher global commodity prices, combined with our low cost structure, translates into strong netbacks and significant free cash flow, supporting our self-funded growth and income business model. As previously announced, we increased our monthly dividend by 7% to $0.23 per share effective with the April 2018 dividend payable May 15, 2018. This marks the fourth dividend/distribution increase since the company started paying a monthly distribution (as a trust) in 2003.
Vermilion's Q1 2018 production volumes decreased by 4% from the prior quarter to 70,167 boe/d. The decrease was primarily due to idling a well we drilled last year in the Netherlands while we await regulatory approval of our long-term production plan, cold weather related downtime and third party maintenance in North America, and the temporary shut-in of gas at a German site for instrumentation installation. Despite the expected quarter-over-quarter decrease in Q1 2018 production levels, we expect to increase production each quarter throughout 2018 to achieve our previous full year production guidance of 75,000 to 77,500 boe/d, without the inclusion of the Spartan assets. Including the Spartan acquisition, our revised production guidance is 86,000 to 90,000 boe/d.
Fund flows from operations for Q1 2018 was $157 million ($1.29/basic share(1)), a decrease of 13% from the prior quarter as the benefit of higher commodity pricing was more than offset by lower production volumes, higher realized losses on derivatives, a stronger Euro and the absence of a favourable tax adjustment in the Netherlands.
We also released our 2017 sustainability report during the quarter, highlighting the economic, environmental and social impacts of our operations, and how we integrate their associated opportunities and risks into our business strategies. One of Vermilion's defining strengths is our belief that sharing our success is essential to being a success. We have embedded this philosophy in our mission, and we continue to live it today. Our objective is to ensure that our all of our stakeholders, including shareholders, employees, communities and partners, benefit from our achievements.
Q1 2018 Operations Review
Europe
In France, Q1 2018 production averaged 11,037 boe/d, a decrease of 2% from the prior quarter. The decrease was primarily due to production declines and higher than normal well downtime resulting from cold weather, which more than offset new well production. We drilled two (2.0 net) wells in the Neocomian field in Q1 2018, which were put on production at a combined initial rate of approximately 190 bbls/d. We also drilled three (3.0 net) wells in the Champotran field in Q1 2018, including a sidetrack well from an existing well. The two grassroots Champotran wells were brought on production late in the quarter and produced at a combined rate of 780 boe/d over the final two weeks of March. The side-track well is scheduled to be brought on production mid-Q2 2018.
Production in the Netherlands averaged 7,541 boe/d in Q1 2018, a decrease of 20% from the prior quarter. The decrease was primarily due to the shut-in of the Eesveen-02 test well near the end of Q4 2017 and a planned workover on a key well. The test rate from the Eesveen-02 well (60% working interest) was approximately 10 mmcf/d net over a two-month period during Q4 2017. The Eesveen-02 well is expected to be brought on production in mid-2018. Production in the first quarter was also impacted by downtime on one of our key wells for a successful workover to upsize the tubing to increase its production rate, resulting in approximately two weeks of downtime.
In Ireland, production from Corrib averaged 61 mmcf/d (10,144 boe/d) in Q1 2018, an 8% increase from Q4 2017 due to the absence of significant downtime during the quarter. Production in Q4 was impacted by an unplanned downtime period following a plant turnaround during September and October 2017. This downtime reduced Vermilion's Q4 2017 production by approximately 1,200 boe/d, as previously reported. The increase in quarter-over-quarter production was partially offset by the initiation of decline on the Corrib gas field, which began in Q1 2018 as predicted from numerical reservoir simulation. We continue to work closely with Canada Pension Plan Investment Board ("CPPIB") and Shell on the transition of ownership and operations from Shell to CPPIB and Vermilion, and anticipate closing the transaction in mid-2018.
In Germany, production in Q1 2018 averaged 3,777 boe/d, a decrease of 10% from the previous quarter. The decrease was primarily due to a temporary shut-in of one gas well for a SCADA installation in December, as previously reported. The well was brought back on production in mid-Q1 2018. In addition, higher than normal downtime at a non-operated gas processing plant in the quarter also negatively impacted production. Our capital activity in Germany continues to focus on well workover and optimization projects on our operated assets and planning activities related to the Burgmoor Z5 well to be drilled in early 2019.
In Hungary, we drilled and tested our first exploratory well (100% working interest) in the South Battonya concession, as previously reported. The Mh-Ny-07 natural gas well tested at a rate of 5.8 mmcf/d(2) during the test period and is expected to be brought on production mid-2018.
North America
In Canada, production averaged 32,078 boe/d in Q1 2018, representing a 3% decrease from the previous quarter primarily due to cold weather related downtime and planned maintenance on third party infrastructure. These events more than offset new well production because most wells drilled in the quarter were not completed and brought on production until late in the quarter or early Q2 2018. We drilled or participated in 18 (16.7 net) wells and brought on production nine (8.8 net) Mannville and five (5.0 net) southeast Saskatchewan wells in Q1 2018, with almost all coming on production late in the quarter. The Q1 2018 wells currently on production are performing in-line with our existing type curves. We also announced and closed an acquisition of a private company with light oil producing assets straddling the Saskatchewan and Manitoba border near Vermilion's existing southeast Saskatchewan operations.
In the United States, Q1 2018 production averaged 618 boe/d, a decrease of 18% from the prior quarter primarily due to planned downtime for workover activity and the previously disclosed force majeure event on a third-party gas gathering system. The third-party gas gathering system returned to service mid-Q1 2018. We drilled all five (5.0 net) of the planned wells in our 2018 drilling program and completed four of these wells late in the first quarter. We continue to optimize our drilling and completion methods, with lateral lengths ranging from 1,840 to 2,215 metres, and frac stages ranging from a low of 25 to a high of 62 stages per well. The remaining well is scheduled to be completed early in Q2 2018. Through well planning optimization efforts, drilling times were reduced by 22% on a per metre basis as compared to the 2017 drilling program.
Environmental, Social and Governance ("ESG")
Vermilion was recently ranked 11th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list. This marks the fifth year in a row that Vermilion has been recognized by Corporate Knights as one of Canada's top sustainability performers. Vermilion continues to be the highest rated oil and gas company on the list. This recognition reflects our commitment to sustainability, transparency and performance regarding ESG matters.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of cash flows, providing additional certainty with regards to the execution of our dividend and capital programs. In aggregate, we currently have 44% of our expected net-of-royalty production hedged for 2018. These hedges include both swaps and collars. Our diversified commodity mix, including more than a one-third cash flow contribution from relatively high-priced European natural gas, gives us unique flexibility in managing our individual commodity exposures. Based on the current level and term structures in the oil, North American gas and European gas forward curves, we have elected to lock down a greater percentage of our gas exposures, particularly for European gas. We have currently hedged 59% of anticipated European natural gas volumes for 2018. In view of the compelling longer-term forward market for European gas we have also hedged 43% and 15% of our anticipated 2019 and 2020 volumes at prices which should provide for strong project economics and free cash flows. In addition, we have hedged 35% of anticipated North American gas volumes for 2018. In view of steep backwardation in the oil forward markets, we are keeping oil hedges shorter-term, with 50% hedged for the first half of 2018, and 30% in the second half of this year. At present, our philosophy is to maintain greater torque to longer-term oil prices, with only 1% of our expected oil production hedged for 2019. We will continue to add to our hedge positions in all products as suitable opportunities arise.
Board of Directors
Mr. William Madison and Ms. Sarah Raiss have decided not to stand for re-election in 2018, following thirteen and four years of valuable service to Vermilion respectively. We would like to thank Mr. Madison and Ms. Raiss for their numerous contributions, and we wish them the very best in their retirement from our Board.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
April 26, 2018
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Mh-Ny-07 well tested gas at a rate of 5.8 mmcf/d over the final two hours of a 22 hour test period at a stabilized wellhead pressure of 1,065 psi on a 0.55 inch diameter choke and a shut-in wellhead pressure of 1,305 psi. No water production was observed during testing. The well logged 21 feet of net gas pay with an average porosity of 31% from an Upper Miocene Pannonian sandstone occurring within a gross measured depth interval of 3,438- 3,465 feet. |
2018 Guidance
On October 30, 2017, we released our 2018 capital expenditure guidance of $315 million and associated production guidance of between 74,500 to 76,500 boe/d. On January 15, 2018, we increased our capital expenditure guidance to $325 million and production guidance to between 75,000 to 77,500 boe/d to reflect the post-closing impact of the acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer. On April 16, 2018, we increased our capital expenditure guidance to $430 million and production guidance to between 86,000 to 90,000 boe/d to reflect the post-closing impact of the acquisition of Spartan Energy.
The following table summarizes our guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | ||||
2018 Guidance |
||||||
2018 Guidance |
October 30, 2017 |
315 |
74,500 to 76,500 | |||
2018 Guidance |
January 15, 2018 |
325 |
75,000 to 77,500 | |||
2018 Guidance |
April 16, 2018 |
430 |
86,000 to 90,000 |
Annual General Meeting Webcast
As Vermilion's Annual General Shareholders Meeting is being held today, April 26th, 2018 at 3:00 PM MST at the Metropolitan Centre, 333 - 4th Avenue S.W., Calgary, Alberta, there will not be a first quarter conference call. In lieu of the conference call, a presentation will be given by Anthony Marino, President & Chief Executive Officer, at the end of the meeting. Questions from the public can be submitted remotely via webcast.
To view the webcast, which will commence at approximately 3:15 PM MST, please visit https://event.on24.com/wcc/r/1635023/2C13CF05F6709CF71E1DC001EABB20E5. The webcast link can also be found on Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm under Upcoming Events.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
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SOURCE Vermilion Energy Inc.
CALGARY, April 16, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.23 CDN per share payable on May 15, 2018 to all shareholders of record on April 30, 2018. The ex-dividend date for this payment is April 27, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
This marks the fourth increase to Vermilion's monthly dividend (previously Vermilion's distribution during the income trust era) since we started paying a distribution in 2003.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
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SOURCE Vermilion Energy Inc.
CALGARY, April 16, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce that we have entered into an arrangement agreement (the "Arrangement") to acquire Spartan Energy Corp. ("Spartan"), a publicly traded southeast Saskatchewan oil and gas producer, with annual production of approximately 23,000 boe/d (91% oil). Total consideration for Spartan is approximately $1.40 billion, comprised of $1.23 billion in Vermilion shares plus the assumption of approximately $175 million in debt.
Under the terms of the Arrangement, Vermilion has agreed to acquire all of the common shares of Spartan issued and outstanding at the effective time of the Arrangement (the "Acquisition"). Spartan shareholders will receive 0.1476 of a Vermilion share for each Spartan common share. Based on Vermilion's closing price of $44.04 on April 13, 2018, the exchange ratio translates to $6.50 per Spartan common share, representing a 5% premium to Spartan's closing price. All of the officers and directors of Spartan have entered into voting support agreements and agreed to vote their Spartan shares in favour of the Arrangement. The Arrangement includes a reciprocal break fee of $40 million.
The Board of Directors of Vermilion and Spartan have unanimously approved the Arrangement and recommended that Spartan shareholders vote in favour of the Arrangement. The Arrangement remains subject to customary closing conditions, including receipt of applicable court, Spartan shareholder, TSX and NYSE, and other regulatory approvals, and is expected to close on or about June 15, 2018.
STRATEGIC RATIONALE
Vermilion focuses on high-netback producing areas with favourable fiscal and regulatory regimes. We entered southeast Saskatchewan with the acquisition of Elkhorn Resources in 2014, and have since continuously evaluated opportunities to expand our position in this area. We added approximately 30 sections of land to our southeast Saskatchewan core area through the end of 2017, and further augmented our asset base with the acquisition of a private southeast Saskatchewan oil producer in early 2018. The acquisition of Spartan is a value-adding investment which meets our disciplined M&A criteria. The Acquisition significantly increases our position in southeast Saskatchewan, and aligns with our sustainable growth-and-income model by appending high-netback, low decline assets with free cash flow and strong capital efficiencies on future development.
Making no deduction for undeveloped land value, transaction metrics equate to $12.33 per boe of proved plus probable ("2P") reserves (based on Spartan's reserve report(1)), and $60,900 per flowing barrel of production. Based on April 13, 2018 WTI strip pricing of US$65.19/bbl, the operating netback for the acquired assets is estimated at approximately $38.42 (2) per boe. Using a 2P finding, development and acquisition cost of $19.48 per boe (including future development capital) based on the Acquisition consideration and Spartan's reserve report, the acquired assets are expected to deliver a 2P operating recycle ratio of 2.0 times (including the Acquisition cost).
Using the same strip pricing assumption, the total Acquisition cost (including assumed debt) is approximately 4.7 times estimated annualized 2018 fund flows from operations ("FFO"), after deducting incremental interest expense. Pro-forma including the Acquisition, our year end 2018 net debt-to-FFO ratio is forecast to be 1.7 times based on current strip pricing, as compared to 2.0 times prior to the Acquisition.
The Acquisition is accretive on a fully-diluted per share basis for all pertinent metrics including production, fund flows from operations(2), and reserves:
|
7% |
|
15% |
|
13% |
We believe that this business combination will significantly benefit both Vermilion's existing shareholders and Spartan's shareholders. The acquired assets' netback, base decline, and capital efficiency characteristics give them the capability to grow while generating significant free cash flow, and are therefore well-suited to our growth-and-income capital markets model. In addition, we believe that both shareholder groups will benefit from increased scale in both our operations and in the capital markets. We look forward to integrating Spartan employees into our organization, and believe our combined enterprise will have the operating, technical and financial capability to maximize the value of these southeast Saskatchewan assets.
SPARTAN ASSET SUMMARY
The Spartan assets are comprised of high-netback, light oil producing properties covering approximately 480,000 net acres of land (80% average working interest), including 400,000 net acres in southeast Saskatchewan with multi-zone potential. In addition, the Acquisition includes approximately 80,000 net acres of land in other areas of Saskatchewan, Alberta and Manitoba. Production from the assets is projected to be approximately 23,000 boe/d (91% oil) during 2018. The Acquisition also includes ownership and control of producing infrastructure that are synergistic with our existing assets, as well as significant 2D and 3D seismic data.
Total proved ("1P") and 2P reserves attributed to the assets at December 31, 2017 are 73 mmboe(1) (92% crude oil and natural gas liquids) and 113.5 mmboe(1) (92% crude oil and natural gas liquids), respectively, based on an independent evaluation by Sproule Associates Limited. Vermilion has internally evaluated Spartan's reserves, and we expect to have the capability to book similar volumes of reserves. We have identified over 1,000 development locations targeting the Ratcliffe, Midale, Frobisher/Alida, Bakken, and Three Forks/Torquay formations. Most of the future drilling targets are inexpensive open-hole completions not requiring hydraulic fracturing, generating rapid payouts. There are also a large number of identified drilling locations in the hydraulically-fractured Midale play. In addition, there are significant waterflood development opportunities in the Ratcliffe and Midale zones. The assets demonstrate a current base decline rate of approximately 23% for the first year, and decreasing thereafter. Under the current commodity strip, we expect the assets to generate cash flow in excess of capital requirements for continued growth plus the incremental gross dividends associated with the new shares issued.
2018 GUIDANCE AND REDUCED DRIP DISCOUNT
As a result of the Acquisition, and based on an expected June 15, 2018 closing date, we are revising our 2018 production guidance to a range of 86,000 to 90,000 boe/d (from 75,000 to 77,500 boe/d previously). In addition, we are increasing our 2018 capital budget to $430 million (from $325 million previously) to reflect additional capital activity associated with the acquired assets. Upon closing of the Acquisition, we also intend to eliminate the 2% discount associated with our Dividend Reinvestment Plan, beginning with the June 2018 dividend payable on July 16, 2018.
CONFERENCE CALL AND AUDIO WEBCAST DETAILS
Vermilion will discuss the Acquisition in a conference call on Monday, April 16, 2018 at 9:00 am MT (11:00 am ET). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will be available on replay until Monday, April 30, 2018 at 9:59 PM MST by calling 1-855-859-2056 and using conference ID number 2054718.
To listen to the audio webcast, click https://event.on24.com/wcc/r/1658611/C20057B8D39D2389E5BC8BFBC09ACE58 or visit Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm. An investor presentation providing an overview of this acquisition can also be found on our website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Natural gas volumes have been converted on the basis of six thousand cubic feet ("mcf") of natural gas to one barrel equivalent of oil. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. | |
(1) |
Estimated total proved and proved plus probable reserves attributable to the Spartan assets as evaluated by Sproule Associates Limited in a report dated February 20, 2018 with an effective date of December 31, 2017, in accordance with National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities of the Canadian Securities Administrators, using the Sproule December 31, 2017 price forecast. |
(2) |
Non-GAAP Financial Measures: Netbacks, fund flows from operations, and free cash flow are non-GAAP (as defined herein) or additional GAAP financial measures that do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") and therefore may not be comparable with the calculations of similar measures for other entities. "Netbacks" are per boe and per mcf measures used in operational and capital allocation decisions. "Fund flows from operations" represents cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management considers fund flows from operations and fund flows from operations per share to be key measures as they demonstrate Vermilion's ability to generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a useful measure of Vermilion's ability to generate cash that is not subject to short-term movements in non-cash operating working capital. For relevant operating netback related disclosures please refer to the reconciliation in management's discussion and analysis contained in Vermilion's 2017 Annual Report for the year ended December 31, 2017 available on SEDAR or at the company's website (www.vermilionenergy.com). |
DISCLAIMER
Certain statements included or incorporated by reference in this press release may constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this press release may include, but are not limited to:
Statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
View original content with multimedia:http://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-acquisition-of-spartan-energy-corp-300630218.html
SOURCE Vermilion Energy Inc.
CALGARY, March 20, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) announces a correction to the ex-dividend and record dates for the dividend payment on April 16, 2018. The ex-dividend date will be March 28, 2018 and the record date will be March 29, 2018, rather than the previously announced dates of March 29, 2018 and March 30, 2018, respectively, due to the statutory holiday on March 30, 2018.
Vermilion previously announced a cash dividend of $0.215 CDN per share payable on April 16, 2018, which is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, March 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on April 16, 2018 to all shareholders of record on March 30, 2018. The ex-dividend date for this payment is March 29, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, March 1, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2017 year-end reserves and resource information. The estimates of reserves and resources and other oil and gas information contained in this news release have been estimated by GLJ Petroleum Consultants Ltd. ("GLJ") effective as at December 31, 2017 and prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGEH"). For additional information about Vermilion, including Vermilion's statement of reserves data and other information in Form 51-101F1, report on reserves data by independent qualified reserves evaluator or auditor in Form 51-101F2 and report of management and directors on oil and gas disclosure in Form 51-101F3, please review the Company's Annual Information Form for the year ended December 31, 2017, to be filed on March 1, 2018 and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov/edgar.shtml.
HIGHLIGHTS
(1) |
As evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2018 with an effective date of December 31, 2017. |
(2) |
F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period. |
(3) |
"Operating Recycle Ratio" is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). "Operating Netback" is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(4) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2018 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2017 (the "GLJ 2017 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively. The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Unclarified category are 56%, 46% and 47%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 23%, 22% and 22%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. For further information, see the "Contingent Resources" section of this news release. |
DISCLAIMER
Certain statements included or incorporated by reference in this news release may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this news release may include, but are not limited to:
Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding the Company's financial strength and business objectives and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
RESERVES, FUTURE NET REVENUE AND OTHER OIL AND GAS INFORMATION
The following is a summary of the oil and natural gas reserves and the value of future net revenue of Vermilion as evaluated by GLJ, independent petroleum engineering consultants in Calgary in a report dated February 1, 2018 with an effective date of December 31, 2017 (the "GLJ 2017 Reserves Evaluation"). The GLJ 2017 Reserves Evaluation was prepared in accordance with National Instrument 51-101 and COGEH.
Reserves and other oil and gas information in this news release is effective December 31, 2017 unless otherwise stated.
All evaluations of future net production revenue set forth in the tables below are stated after overriding and lessor royalties, Crown royalties, freehold royalties, mineral taxes, direct lifting costs, normal allocated overhead and future capital investments, including abandonment and reclamation obligations. Future net production revenues estimated by the GLJ 2017 Reserves Evaluation do not represent the fair market value of the reserves. Other assumptions relating to the costs, prices for future production and other matters are included in the GLJ 2017 Reserve Evaluation. There is no assurance that the future price and cost assumptions used in the GLJ 2017 Reserves Evaluation will prove accurate and variances could be material.
Reserves for Australia, Canada, France, Germany, Ireland, the Netherlands and the United States are established using deterministic methodology. Total proved reserves are established at the 90 percent probability (P90) level. There is a 90 percent probability that the actual reserves recovered will be equal to or greater than the P90 reserves. Total proved plus probable reserves are established at the 50 percent probability (P50) level. There is a 50 percent probability that the actual reserves recovered will be equal to or greater than the P50 reserves.
Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development.
With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
Pricing used in the forecast price estimates is set forth in the table below and referenced in the notes to subsequent tables.
Table 1: Forecast Prices used in Estimates (1)
Light Crude Oil and |
Crude Oil |
Conventional |
Conventional |
Natural Gas |
Inflation |
Exchange |
Exchange | |||||||||||||||
Year |
WTI |
Edmonton |
Cromer |
Brent Blend |
AECO |
National Balancing |
FOB |
Percent |
($US/$Cdn) |
($Cdn/EUR) | ||||||||||||
2017 |
50.88 |
62.78 |
59.90 |
54.16 |
2.16 |
5.63 |
46.67 |
1.60 |
0.77 |
1.46 | ||||||||||||
Forecast |
||||||||||||||||||||||
2018 |
59.00 |
70.25 |
65.34 |
65.50 |
2.20 |
6.25 |
56.85 |
2.00 |
0.79 |
1.49 | ||||||||||||
2019 |
59.00 |
70.25 |
65.34 |
63.50 |
2.54 |
6.50 |
53.46 |
2.00 |
0.79 |
1.46 | ||||||||||||
2020 |
60.00 |
70.31 |
65.39 |
63.00 |
2.88 |
6.75 |
53.18 |
2.00 |
0.80 |
1.44 | ||||||||||||
2021 |
66.00 |
72.84 |
67.74 |
66.00 |
3.24 |
7.00 |
54.74 |
2.00 |
0.81 |
1.42 | ||||||||||||
2022 |
69.00 |
75.61 |
70.32 |
69.00 |
3.47 |
7.15 |
56.37 |
2.00 |
0.82 |
1.40 | ||||||||||||
2023 |
72.00 |
78.31 |
72.83 |
72.00 |
3.58 |
7.30 |
58.31 |
2.00 |
0.83 |
1.39 | ||||||||||||
2024 |
75.00 |
81.93 |
76.19 |
75.00 |
3.66 |
7.45 |
60.94 |
2.00 |
0.83 |
1.39 | ||||||||||||
2025 |
78.00 |
85.54 |
79.55 |
78.00 |
3.73 |
7.60 |
63.57 |
2.00 |
0.83 |
1.39 | ||||||||||||
2026 |
80.33 |
88.35 |
82.16 |
80.33 |
3.80 |
7.75 |
65.61 |
2.00 |
0.83 |
1.39 | ||||||||||||
2027 |
81.88 |
90.22 |
83.90 |
81.88 |
3.88 |
7.90 |
66.96 |
2.00 |
0.83 |
1.39 | ||||||||||||
Thereafter |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
0.83 |
1.39 |
Note: |
|
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
All forecast prices in the tables above are provided by GLJ. For 2017, the price of crude oil in the United States is based on WTI. The benchmark price for Canadian crude oil is Edmonton Par and Canadian natural gas is priced against AECO. The benchmark price for Australia, France and Germany crude oil is Dated Brent. The price of our natural gas in Ireland is based on the NBP index. The price of Vermilion's natural gas in the Netherlands and Germany is based on the TTF day/month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point. For the year ended December 31, 2017, the average realized sales prices before hedging were $57.64 per bbl (United States) for WTI, $51.36 per bbl for Canadian-based crude oil, condensate and NGLs and $2.34 per Mcf for Canadian natural gas, $73.99 per bbl (Australia), $67.08 per bbl (France) for Brent-based crude oil, $7.19 per Mcf (Ireland), $7.18 per Mcf (Netherlands), and $6.38 per Mcf (Germany).
The following table summarizes the capital expenditures made by Vermilion on oil and gas properties for the year ended December 31, 2017:
Table 2: Capital Costs Incurred
Acquisition Costs |
|||||||||
(M$) |
Proved |
Unproved |
Exploration |
Development |
Total | ||||
Australia |
— |
— |
— |
29,896 |
29,896 | ||||
Canada |
22,011 |
— |
— |
148,211 |
170,222 | ||||
Croatia |
— |
— |
2,764 |
— |
2,764 | ||||
France |
— |
— |
2,294 |
69,026 |
71,320 | ||||
Germany |
— |
— |
3,366 |
5,710 |
9,076 | ||||
Hungary |
— |
— |
2,596 |
— |
2,596 | ||||
Ireland |
— |
— |
— |
544 |
544 | ||||
Netherlands |
— |
— |
16,468 |
14,956 |
31,424 | ||||
United States |
3,403 |
— |
— |
19,058 |
22,461 | ||||
Total |
25,414 |
— |
32,103 |
287,401 |
344,918 |
The following table sets forth the reserve life index based on total proved and proved plus probable reserve and fourth quarter 2017 production of 72,821 boe/d.
Table 3: Reserve Life Index
Commodity |
Production |
Reserve Life Index (years) | ||||
Fourth Quarter 2017 |
Total Proved |
Proved Plus Probable | ||||
Crude oil, condensate and natural gas liquids (bbl/d) |
33,109 |
8.5 |
13.8 | |||
Natural gas (mmcf/d) |
238.27 |
5.1 |
9.1 | |||
Oil Equivalent (boe/d) |
72,821 |
6.6 |
11.2 |
The following tables provide reserves data and a breakdown of future net revenue by component and production group using forecast prices and costs. For Canada, the tables following include Alberta gas cost allowance.
The following tables may not total due to rounding.
Table 4: Oil and Gas Reserves - Based on Forecast Prices and Costs (1)
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |||||||||||||||||
Proved Developed Producing (3) (5) (6) |
||||||||||||||||||||||||
Australia |
9,065 |
9,065 |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Canada |
11,148 |
10,219 |
— |
— |
— |
— |
139,772 |
128,023 | ||||||||||||||||
France |
35,944 |
33,265 |
— |
— |
— |
— |
8,619 |
7,939 | ||||||||||||||||
Germany |
5,008 |
4,880 |
— |
— |
— |
— |
29,791 |
26,881 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
81,803 |
81,803 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
— |
— |
37,296 |
24,721 | ||||||||||||||||
United States |
982 |
782 |
— |
— |
— |
— |
1,071 |
854 | ||||||||||||||||
Total Proved Developed Producing |
62,147 |
58,211 |
— |
— |
— |
— |
298,352 |
270,221 | ||||||||||||||||
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |||||||||||||||||
Proved Developed Producing (3) (5) (6) |
||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
9,065 |
9,065 | ||||||||||||||||
Canada |
60 |
56 |
2,330 |
2,153 |
11,215 |
9,102 |
46,057 |
41,026 | ||||||||||||||||
France |
— |
— |
— |
— |
— |
— |
37,381 |
34,588 | ||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
9,973 |
9,360 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
13,634 |
13,634 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
137 |
90 |
6,353 |
4,210 | ||||||||||||||||
United States |
— |
— |
— |
— |
147 |
117 |
1,308 |
1,041 | ||||||||||||||||
Total Proved Developed Producing |
60 |
56 |
2,330 |
2,153 |
11,499 |
9,309 |
123,771 |
112,924 | ||||||||||||||||
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |||||||||||||||||
Proved Developed Non-Producing (3) (5) (7) |
||||||||||||||||||||||||
Australia |
350 |
350 |
— |
— |
— |
— |
||||||||||||||||||
Canada |
878 |
768 |
— |
— |
— |
— |
9,420 |
8,489 | ||||||||||||||||
France |
562 |
492 |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Germany |
539 |
521 |
— |
— |
— |
— |
8,959 |
8,156 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
— |
— |
21,010 |
20,482 | ||||||||||||||||
United States |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Total Proved Developed Non-Producing |
2,329 |
2,131 |
— |
— |
— |
— |
39,389 |
37,127 | ||||||||||||||||
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |||||||||||||||||
Proved Developed Non-Producing (3) (5) (7) |
||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
350 |
350 | ||||||||||||||||
Canada |
1,079 |
1,025 |
2,360 |
2,200 |
410 |
309 |
3,431 |
3,029 | ||||||||||||||||
France |
— |
— |
— |
— |
— |
— |
562 |
492 | ||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
2,032 |
1,880 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
56 |
54 |
3,558 |
3,468 | ||||||||||||||||
United States |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Total Proved Developed Non-Producing |
1,079 |
1,025 |
2,360 |
2,200 |
466 |
363 |
9,933 |
9,219 | ||||||||||||||||
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |||||||||||||||||
Proved Undeveloped (3) (8) |
||||||||||||||||||||||||
Australia |
1,500 |
1,500 |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Canada |
7,634 |
6,929 |
— |
— |
— |
— |
91,104 |
83,603 | ||||||||||||||||
France |
4,140 |
3,767 |
— |
— |
— |
— |
64 |
64 | ||||||||||||||||
Germany |
241 |
235 |
— |
— |
— |
— |
2,361 |
1,939 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
— |
— |
2,620 |
2,620 | ||||||||||||||||
United States |
3,300 |
2,693 |
— |
— |
— |
— |
3,309 |
2,700 | ||||||||||||||||
Total Proved Undeveloped |
16,815 |
15,124 |
— |
— |
— |
— |
99,458 |
90,926 | ||||||||||||||||
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |||||||||||||||||
Proved Undeveloped (3) (8) |
||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
1,500 |
1,500 | ||||||||||||||||
Canada |
— |
— |
2,023 |
1,849 |
8,679 |
7,689 |
31,834 |
28,860 | ||||||||||||||||
France |
— |
— |
— |
— |
— |
— |
4,151 |
3,778 | ||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
635 |
558 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
— |
— |
437 |
437 | ||||||||||||||||
United States |
— |
— |
— |
— |
454 |
370 |
4,306 |
3,513 | ||||||||||||||||
Total Proved Undeveloped |
— |
— |
2,023 |
1,849 |
9,133 |
8,059 |
42,863 |
38,646 | ||||||||||||||||
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |||||||||||||||||
Proved (3) |
||||||||||||||||||||||||
Australia |
10,915 |
10,915 |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Canada |
19,660 |
17,916 |
— |
— |
— |
— |
240,296 |
220,115 | ||||||||||||||||
France |
40,646 |
37,524 |
— |
— |
— |
— |
8,683 |
8,003 | ||||||||||||||||
Germany |
5,788 |
5,636 |
— |
— |
— |
— |
41,111 |
36,976 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
81,803 |
81,803 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
— |
— |
60,926 |
47,823 | ||||||||||||||||
United States |
4,282 |
3,475 |
— |
— |
— |
— |
4,380 |
3,554 | ||||||||||||||||
Total Proved |
81,291 |
75,466 |
— |
— |
— |
— |
437,199 |
398,274 | ||||||||||||||||
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |||||||||||||||||
Proved (3) |
||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
10,915 |
10,915 | ||||||||||||||||
Canada |
1,139 |
1,081 |
6,713 |
6,202 |
20,304 |
17,100 |
81,322 |
72,916 | ||||||||||||||||
France |
— |
— |
— |
— |
— |
— |
42,093 |
38,858 | ||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
12,640 |
11,799 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
13,634 |
13,634 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
193 |
144 |
10,347 |
8,115 | ||||||||||||||||
United States |
— |
— |
— |
— |
601 |
487 |
5,613 |
4,554 | ||||||||||||||||
Total Proved |
1,139 |
1,081 |
6,713 |
6,202 |
21,098 |
17,731 |
176,564 |
160,791 | ||||||||||||||||
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |||||||||||||||||
Probable (4) |
||||||||||||||||||||||||
Australia |
4,650 |
4,650 |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Canada |
12,885 |
11,417 |
— |
— |
— |
— |
181,055 |
164,336 | ||||||||||||||||
France |
21,786 |
20,115 |
— |
— |
— |
— |
1,854 |
1,769 | ||||||||||||||||
Germany |
3,000 |
2,931 |
— |
— |
— |
— |
53,134 |
47,092 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
51,389 |
51,389 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
— |
— |
44,380 |
35,383 | ||||||||||||||||
United States |
7,073 |
5,827 |
— |
— |
— |
— |
7,520 |
6,194 | ||||||||||||||||
Total Probable |
49,394 |
44,940 |
— |
— |
— |
— |
339,332 |
306,163 | ||||||||||||||||
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |||||||||||||||||
Probable (4) |
||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
4,650 |
4,650 | ||||||||||||||||
Canada |
214 |
203 |
3,053 |
2,846 |
14,282 |
12,186 |
57,887 |
51,501 | ||||||||||||||||
France |
— |
— |
— |
— |
— |
— |
22,095 |
20,410 | ||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
11,856 |
10,780 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
8,565 |
8,565 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
119 |
90 |
7,516 |
5,987 | ||||||||||||||||
United States |
— |
— |
— |
— |
1,031 |
849 |
9,357 |
7,708 | ||||||||||||||||
Total Probable |
214 |
203 |
3,053 |
2,846 |
15,432 |
13,125 |
121,926 |
109,601 | ||||||||||||||||
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |||||||||||||||||
Proved Plus Probable (3) (4) |
||||||||||||||||||||||||
Australia |
15,565 |
15,565 |
— |
— |
— |
— |
— |
— | ||||||||||||||||
Canada |
32,545 |
29,333 |
— |
— |
— |
— |
421,351 |
384,451 | ||||||||||||||||
France |
62,432 |
57,639 |
— |
— |
— |
— |
10,537 |
9,772 | ||||||||||||||||
Germany |
8,788 |
8,567 |
— |
— |
— |
— |
94,245 |
84,068 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
133,192 |
133,192 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
— |
— |
105,306 |
83,206 | ||||||||||||||||
United States |
11,355 |
9,302 |
— |
— |
— |
— |
11,900 |
9,748 | ||||||||||||||||
Total Proved Plus Probable |
130,685 |
120,406 |
— |
— |
— |
— |
776,531 |
704,437 | ||||||||||||||||
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||||||||||||||||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |||||||||||||||||
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |||||||||||||||||
Proved Plus Probable (3) (4) |
||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
15,565 |
15,565 | ||||||||||||||||
Canada |
1,353 |
1,284 |
9,766 |
9,048 |
34,586 |
29,286 |
139,209 |
124,416 | ||||||||||||||||
France |
— |
— |
— |
— |
— |
— |
64,188 |
59,268 | ||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
24,496 |
22,578 | ||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
22,199 |
22,199 | ||||||||||||||||
Netherlands |
— |
— |
— |
— |
312 |
234 |
17,863 |
14,102 | ||||||||||||||||
United States |
— |
— |
— |
— |
1,632 |
1,336 |
14,970 |
12,263 | ||||||||||||||||
Total Proved Plus Probable |
1,353 |
1,284 |
9,766 |
9,048 |
36,530 |
30,856 |
298,490 |
270,391 |
Notes: |
|
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
"Gross Reserves" are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net Reserves" are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in reserves. |
(3) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(4) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(5) |
"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. |
(6) |
"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
(7) |
"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. |
(8) |
"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. |
Table 5: Net Present Values of Future Net Revenue - Based on Forecast Prices and Costs (1)
Before Deducting Future Income Taxes Discounted At |
After Deducting Future Income Taxes Discounted At | |||||||||||||||||||
(M$) |
0% |
5% |
10% |
15% |
20% |
0% |
5% |
10% |
15% |
20% | ||||||||||
Proved Developed Producing (2) (4) (5) |
||||||||||||||||||||
Australia |
(17,017) |
90,880 |
132,474 |
146,048 |
147,713 |
77,180 |
124,390 |
136,979 |
136,121 |
130,383 | ||||||||||
Canada |
929,867 |
770,860 |
647,843 |
559,708 |
494,964 |
929,867 |
770,860 |
647,843 |
559,708 |
494,964 | ||||||||||
France |
1,791,774 |
1,315,070 |
1,030,403 |
849,032 |
725,407 |
1,473,144 |
1,091,894 |
858,839 |
708,168 |
604,390 | ||||||||||
Germany |
276,577 |
249,619 |
206,965 |
174,876 |
151,703 |
276,578 |
249,619 |
206,965 |
174,876 |
151,703 | ||||||||||
Ireland |
389,204 |
376,115 |
346,327 |
316,408 |
290,143 |
389,204 |
376,115 |
346,327 |
316,408 |
290,143 | ||||||||||
Netherlands |
48,794 |
60,781 |
66,245 |
68,260 |
68,404 |
48,793 |
60,781 |
66,245 |
68,260 |
68,404 | ||||||||||
United States |
44,617 |
34,550 |
28,272 |
24,106 |
21,170 |
44,619 |
34,550 |
28,272 |
24,106 |
21,170 | ||||||||||
Total Proved Developed Producing |
3,463,816 |
2,897,875 |
2,458,529 |
2,138,438 |
1,899,504 |
3,239,385 |
2,708,209 |
2,291,470 |
1,987,647 |
1,761,157 | ||||||||||
Proved Developed Non-Producing (2) (4) (6) |
||||||||||||||||||||
Australia |
28,079 |
24,122 |
20,869 |
18,180 |
15,942 |
28,079 |
24,122 |
20,869 |
18,180 |
15,942 | ||||||||||
Canada |
60,804 |
42,405 |
32,416 |
26,238 |
22,048 |
60,804 |
42,405 |
32,417 |
26,238 |
22,048 | ||||||||||
France |
10,082 |
8,113 |
6,095 |
4,559 |
3,438 |
6,848 |
5,499 |
3,953 |
2,763 |
1,896 | ||||||||||
Germany |
49,825 |
37,600 |
27,510 |
20,411 |
15,501 |
32,059 |
29,369 |
23,502 |
18,374 |
14,426 | ||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||
Netherlands |
70,140 |
70,244 |
67,599 |
63,916 |
59,989 |
53,099 |
54,167 |
52,375 |
49,452 |
46,205 | ||||||||||
United States |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||
Total Proved Developed Non-Producing |
218,930 |
182,484 |
154,489 |
133,304 |
116,918 |
180,889 |
155,562 |
133,116 |
115,007 |
100,517 | ||||||||||
Proved Undeveloped (2) (7) |
||||||||||||||||||||
Australia |
54,981 |
43,263 |
34,175 |
27,105 |
21,564 |
25,101 |
18,532 |
13,890 |
10,524 |
8,032 | ||||||||||
Canada |
524,830 |
354,396 |
246,584 |
175,252 |
126,009 |
397,236 |
281,016 |
202,741 |
148,193 |
108,836 | ||||||||||
France |
177,851 |
128,923 |
96,156 |
73,638 |
57,592 |
127,650 |
88,876 |
63,091 |
45,660 |
33,460 | ||||||||||
Germany |
17,161 |
11,696 |
8,012 |
5,495 |
3,737 |
12,154 |
8,910 |
6,412 |
4,551 |
3,166 | ||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||
Netherlands |
10,559 |
8,825 |
7,405 |
6,255 |
5,323 |
7,921 |
6,405 |
5,174 |
4,189 |
3,401 | ||||||||||
United States |
110,911 |
64,500 |
39,231 |
24,394 |
15,111 |
105,425 |
62,306 |
38,295 |
23,973 |
14,912 | ||||||||||
Total Proved Undeveloped |
896,293 |
611,603 |
431,563 |
312,139 |
229,336 |
675,487 |
466,045 |
329,603 |
237,090 |
171,807 | ||||||||||
Proved (2) |
||||||||||||||||||||
Australia |
66,043 |
158,265 |
187,518 |
191,333 |
185,219 |
130,360 |
167,044 |
171,738 |
164,825 |
154,357 | ||||||||||
Canada |
1,515,501 |
1,167,661 |
926,843 |
761,198 |
643,021 |
1,387,907 |
1,094,281 |
883,001 |
734,139 |
625,848 | ||||||||||
France |
1,979,707 |
1,452,106 |
1,132,654 |
927,229 |
786,437 |
1,607,642 |
1,186,269 |
925,883 |
756,591 |
639,746 | ||||||||||
Germany |
343,563 |
298,915 |
242,487 |
200,782 |
170,941 |
320,791 |
287,898 |
236,879 |
197,801 |
169,295 | ||||||||||
Ireland |
389,204 |
376,115 |
346,327 |
316,408 |
290,143 |
389,204 |
376,115 |
346,327 |
316,408 |
290,143 | ||||||||||
Netherlands |
129,493 |
139,850 |
141,249 |
138,431 |
133,716 |
109,813 |
121,353 |
123,794 |
121,901 |
118,010 | ||||||||||
United States |
155,528 |
99,050 |
67,503 |
48,500 |
36,281 |
150,044 |
96,856 |
66,567 |
48,079 |
36,082 | ||||||||||
Total Proved |
4,579,039 |
3,691,962 |
3,044,581 |
2,583,881 |
2,245,758 |
4,095,761 |
3,329,816 |
2,754,189 |
2,339,744 |
2,033,481 | ||||||||||
Probable (3) |
||||||||||||||||||||
Australia |
154,459 |
149,732 |
125,619 |
102,719 |
84,652 |
93,591 |
88,478 |
72,912 |
58,670 |
47,633 | ||||||||||
Canada |
1,363,584 |
814,347 |
539,091 |
384,014 |
288,722 |
1,003,602 |
592,655 |
390,429 |
278,355 |
210,521 | ||||||||||
France |
1,200,008 |
673,205 |
431,159 |
299,927 |
219,972 |
879,913 |
477,377 |
292,831 |
193,985 |
134,663 | ||||||||||
Germany |
414,585 |
244,149 |
151,416 |
100,767 |
70,641 |
293,314 |
172,157 |
104,603 |
68,306 |
47,063 | ||||||||||
Ireland |
350,695 |
246,321 |
182,785 |
141,844 |
114,117 |
350,695 |
246,321 |
182,785 |
141,844 |
114,117 | ||||||||||
Netherlands |
197,136 |
167,242 |
141,871 |
121,179 |
104,496 |
130,277 |
108,388 |
89,527 |
74,196 |
61,980 | ||||||||||
United States |
353,649 |
198,078 |
124,603 |
84,897 |
61,103 |
278,493 |
157,846 |
100,547 |
69,404 |
50,591 | ||||||||||
Total Probable |
4,034,116 |
2,493,074 |
1,696,544 |
1,235,347 |
943,703 |
3,029,885 |
1,843,222 |
1,233,634 |
884,760 |
666,568 | ||||||||||
Proved Plus Probable (2) (3) |
||||||||||||||||||||
Australia |
220,502 |
307,997 |
313,137 |
294,052 |
269,871 |
223,951 |
255,522 |
244,650 |
223,495 |
201,990 | ||||||||||
Canada |
2,879,085 |
1,982,008 |
1,465,934 |
1,145,212 |
931,743 |
2,391,509 |
1,686,936 |
1,273,430 |
1,012,494 |
836,369 | ||||||||||
France |
3,179,715 |
2,125,311 |
1,563,813 |
1,227,156 |
1,006,409 |
2,487,555 |
1,663,646 |
1,218,714 |
950,576 |
774,409 | ||||||||||
Germany |
758,148 |
543,064 |
393,903 |
301,549 |
241,582 |
614,105 |
460,055 |
341,482 |
266,107 |
216,358 | ||||||||||
Ireland |
739,899 |
622,436 |
529,112 |
458,252 |
404,260 |
739,899 |
622,436 |
529,112 |
458,252 |
404,260 | ||||||||||
Netherlands |
326,629 |
307,092 |
283,120 |
259,610 |
238,212 |
240,090 |
229,741 |
213,321 |
196,097 |
179,990 | ||||||||||
United States |
509,177 |
297,128 |
192,106 |
133,397 |
97,384 |
428,537 |
254,702 |
167,114 |
117,483 |
86,673 | ||||||||||
Total Proved Plus Probable |
8,613,155 |
6,185,036 |
4,741,125 |
3,819,228 |
3,189,461 |
7,125,646 |
5,173,038 |
3,987,823 |
3,224,504 |
2,700,049 |
Notes:
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(3) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(4) |
"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. |
(5) |
"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
(6) |
"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. |
(7) |
"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. |
Table 6: Total Future Net Revenue (Undiscounted) Based on Forecast Prices and Costs (1)
(M$) |
Revenue |
Royalties |
Operating |
Capital |
Abandonment |
Future Net |
Future |
Future Net | |||||||
Proved (2) |
|||||||||||||||
Australia |
978,200 |
— |
564,074 |
100,883 |
247,200 |
66,043 |
(64,317) |
130,360 | |||||||
Canada |
3,488,501 |
344,924 |
1,118,811 |
412,323 |
96,942 |
1,515,501 |
127,594 |
1,387,907 | |||||||
France |
3,591,175 |
272,788 |
997,961 |
125,874 |
214,845 |
1,979,707 |
372,065 |
1,607,642 | |||||||
Germany |
853,470 |
44,503 |
298,194 |
20,409 |
146,801 |
343,563 |
22,772 |
320,791 | |||||||
Ireland |
643,435 |
— |
170,325 |
18,907 |
64,999 |
389,204 |
— |
389,204 | |||||||
Netherlands |
546,125 |
104,158 |
203,425 |
28,166 |
80,883 |
129,493 |
19,680 |
109,813 | |||||||
United States |
404,551 |
112,559 |
65,468 |
66,993 |
4,003 |
155,528 |
5,484 |
150,044 | |||||||
Total Proved |
10,505,457 |
878,932 |
3,418,258 |
773,555 |
855,673 |
4,579,039 |
483,278 |
4,095,761 | |||||||
Proved Plus Probable (2) (3) |
|||||||||||||||
Australia |
1,432,958 |
— |
775,932 |
166,801 |
269,723 |
220,502 |
(3,449) |
223,951 | |||||||
Canada |
6,224,592 |
647,349 |
1,828,575 |
744,672 |
124,911 |
2,879,085 |
487,576 |
2,391,509 | |||||||
France |
5,718,238 |
433,546 |
1,481,349 |
346,196 |
277,432 |
3,179,715 |
692,160 |
2,487,555 | |||||||
Germany |
1,672,382 |
105,662 |
507,204 |
104,899 |
196,469 |
758,148 |
144,043 |
614,105 | |||||||
Ireland |
1,113,630 |
— |
270,554 |
38,178 |
64,999 |
739,899 |
— |
739,899 | |||||||
Netherlands |
950,074 |
180,041 |
296,854 |
53,369 |
93,181 |
326,629 |
86,539 |
240,090 | |||||||
United States |
1,137,518 |
308,001 |
166,074 |
145,966 |
8,300 |
509,177 |
80,640 |
428,537 | |||||||
Total Proved Plus Probable |
18,249,392 |
1,674,599 |
5,326,542 |
1,600,081 |
1,035,015 |
8,613,155 |
1,487,509 |
7,125,646 |
Notes:
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(3) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
Table 7: Future Net Revenue by Production Group Based on Forecast Prices and Costs (1)
Future Net Revenue |
Unit Value | ||
Proved Developed Producing |
(M$) |
($/boe) | |
Light Crude Oil & Medium Crude Oil (3) |
1,764,235 |
27.51 | |
Heavy Oil (3) |
— |
— | |
Conventional Natural Gas (4) |
693,722 |
14.33 | |
Shale Gas |
122 |
8.56 | |
Coal Bed Methane |
450 |
1.25 | |
Total Proved Developed Producing |
2,458,529 |
21.77 | |
Proved Developed Non-Producing |
|||
Light Crude Oil & Medium Crude Oil (3) |
43,821 |
18.44 | |
Heavy Oil (3) |
— |
— | |
Conventional Natural Gas (4) |
108,904 |
17.4 | |
Shale Gas |
984 |
4.54 | |
Coal Bed Methane |
780 |
2.13 | |
Total Proved Developed Non-Producing |
154,489 |
16.76 | |
Proved Undeveloped |
|||
Light Crude Oil & Medium Crude Oil (3) |
273,008 |
14.16 | |
Heavy Oil (3) |
— |
— | |
Conventional Natural Gas (4) |
158,318 |
8.31 | |
Shale Gas |
— |
— | |
Coal Bed Methane |
237 |
0.77 | |
Total Proved Undeveloped |
431,563 |
12.04 | |
Proved |
|||
Light Crude Oil & Medium Crude Oil (3) |
2,081,064 |
24.35 | |
Heavy Oil (3) |
— |
— | |
Conventional Natural Gas (4) |
960,944 |
12.92 | |
Shale Gas |
1,106 |
4.58 | |
Coal Bed Methane |
1,467 |
1.36 | |
Total Proved |
3,044,581 |
18.94 | |
Probable |
|||
Light Crude Oil & Medium Crude Oil (3) |
1,031,625 |
19.21 | |
Heavy Oil (3) |
— |
— | |
Conventional Natural Gas (4) |
663,113 |
11.98 | |
Shale Gas |
238 |
5.49 | |
Coal Bed Methane |
1,568 |
3.31 | |
Total Probable |
1,696,544 |
15.48 | |
Proved Plus Probable |
|||
Light Crude Oil & Medium Crude Oil (3) |
3,112,689 |
22.47 | |
Heavy Oil (3) |
— |
— | |
Conventional Natural Gas (4) |
1,624,057 |
12.42 | |
Shale Gas |
1,344 |
4.85 | |
Coal Bed Methane |
3,035 |
1.92 | |
Total Proved Plus Probable |
4,741,125 |
17.53 |
Notes:
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
Other Company revenue and costs not related to a specific product type have been allocated proportionately to the specified product types. Unit values are based on Company net reserves. Net present value of reserves categories are an approximation based on major products. |
(3) |
Including solution gas and other by-products. |
(4) |
Including by-products but excluding solution gas. |
Reconciliations of Changes in Reserves
The following tables set forth a reconciliation of the changes in Vermilion's gross light and medium crude oil, heavy oil and associated and non-associated gas (combined) reserves as at December 31, 2017 compared to such reserves as at December 31, 2016.
Table 8: Reconciliation of Company Gross Reserves by Principal Product Type - Based on Forecast Prices and Costs (3)
AUSTRALIA Total Oil (4) Light Crude Oil & Heavy Oil Tight Oil Proved Probable P+P (1) (2) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) At December 31, 2016 12,418 4,650 17,068 12,418 4,650 17,068 — — — — — — Discoveries — — — — — — — — — — — — Extensions & Improved Recovery — — — — — — — — — — — — Technical Revisions 603 — 603 603 — 603 — — — — — — Acquisitions — — — — — — — — — — — — Dispositions — — — — — — — — — — — — Economic Factors — — — — — — — — — — — — Production (2,106) — (2,106) (2,106) — (2,106) — — — — — — At December 31, 2017 10,915 4,650 15,565 10,915 4,650 15,565 — — — — — — Total Gas (4) Conventional Natural Gas Coal Bed Methane (5) Shale Gas (5) Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Proved Probable Proved + Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) At December 31, 2016 — — — — — — — — — — — — Discoveries — — — — — — — — — — — — Extensions & Improved Recovery — — — — — — — — — — — — Technical Revisions — — — — — — — — — — — — Acquisitions — — — — — — — — — — — — Dispositions — — — — — — — — — — — — Economic Factors — — — — — — — — — — — — Production — — — — — — — — — — — — At December 31, 2017 — — — — — — — — — — — — Natural Gas Liquids BOE Proved Probable Proved + Proved Probable Proved + Factors (Mbbl) (Mbbl) (Mbbl) (Mboe) (Mboe) (Mboe) At December 31, 2016 — — — 12,418 4,650 17,068 Discoveries — — — — — — Extensions & Improved Recovery — — — — — — Technical Revisions — — — 603 — 603 Acquisitions — — — — — — Dispositions — — — — — — Economic Factors — — — — — — Production — — — (2,106) — (2,106) At December 31, 2017 — — — 10,915 4,650 15,565
Medium Crude Oil
Probable
Probable
Probable
Probable
Probable
Probable
Probable
Probable
Probable
Probable
CANADA |
Total Oil (4) |
Light Crude Oil & |
Heavy Oil |
Tight Oil |
|||||||||||||||||||||||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
|||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
|||||||||||||||||||||||
At December 31, 2016 |
21,974 |
14,105 |
36,079 |
21,962 |
14,103 |
36,065 |
— |
— |
— |
12 |
2 |
14 |
|||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||
Extensions & Improved Recovery |
594 |
302 |
896 |
594 |
302 |
896 |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||
Technical Revisions |
(681) |
(1,542) |
(2,223) |
(670) |
(1,540) |
(2,210) |
— |
— |
— |
(11) |
(2) |
(13) |
|||||||||||||||||||||||
Acquisitions |
16 |
4 |
20 |
16 |
4 |
20 |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||
Economic Factors |
(48) |
16 |
(32) |
(48) |
16 |
(32) |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||
Production |
(2,195) |
— |
(2,195) |
(2,194) |
— |
(2,194) |
— |
— |
— |
(1) |
— |
(1) |
|||||||||||||||||||||||
At December 31, 2017 |
19,660 |
12,885 |
32,545 |
19,660 |
12,885 |
32,545 |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) |
||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
||||||||||||||||||||||||
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
|||||||||||||||||||||||
At December 31, 2016 |
226,530 |
156,668 |
383,198 |
217,098 |
151,707 |
368,805 |
8,061 |
4,677 |
12,738 |
1,371 |
284 |
1,655 |
|||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||
Extensions & Improved Recovery |
58,040 |
29,520 |
87,560 |
57,075 |
28,977 |
86,052 |
965 |
543 |
1,508 |
— |
— |
— |
|||||||||||||||||||||||
Technical Revisions |
1,696 |
372 |
2,068 |
1,057 |
378 |
1,435 |
799 |
64 |
863 |
(160) |
(70) |
(230) |
|||||||||||||||||||||||
Acquisitions |
3,452 |
1,113 |
4,565 |
2,686 |
872 |
3,558 |
766 |
241 |
1,007 |
— |
— |
— |
|||||||||||||||||||||||
Dispositions |
(2,182) |
(2,150) |
(4,332) |
(576) |
(231) |
(807) |
(1,606) |
(1,919) |
(3,525) |
— |
— |
— |
|||||||||||||||||||||||
Economic Factors |
(3,658) |
(1,201) |
(4,859) |
(2,497) |
(648) |
(3,145) |
(1,161) |
(553) |
(1,714) |
— |
— |
— |
|||||||||||||||||||||||
Production |
(35,730) |
— |
(35,730) |
(34,547) |
— |
(34,547) |
(1,111) |
— |
(1,111) |
(72) |
— |
(72) |
|||||||||||||||||||||||
At December 31, 2017 |
248,148 |
184,322 |
432,470 |
240,296 |
181,055 |
421,351 |
6,713 |
3,053 |
9,766 |
1,139 |
214 |
1,353 |
|||||||||||||||||||||||
Natural Gas Liquids |
BOE |
||||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
||||||||||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
|||||||||||||||||||||||||||||
At December 31, 2016 |
17,363 |
12,907 |
30,270 |
77,092 |
53,123 |
130,215 |
|||||||||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Extensions & Improved Recovery |
5,669 |
1,235 |
6,904 |
15,936 |
6,457 |
22,393 |
|||||||||||||||||||||||||||||
Technical Revisions |
(271) |
95 |
(176) |
(668) |
(1,386) |
(2,054) |
|||||||||||||||||||||||||||||
Acquisitions |
351 |
113 |
464 |
942 |
303 |
1,245 |
|||||||||||||||||||||||||||||
Dispositions |
(3) |
(1) |
(4) |
(367) |
(359) |
(726) |
|||||||||||||||||||||||||||||
Economic Factors |
(184) |
(67) |
(251) |
(842) |
(251) |
(1,093) |
|||||||||||||||||||||||||||||
Production |
(2,621) |
— |
(2,621) |
(10,771) |
— |
(10,771) |
|||||||||||||||||||||||||||||
At December 31, 2017 |
20,304 |
14,282 |
34,586 |
81,322 |
57,887 |
139,209 |
FRANCE |
Total Oil (4) |
Light Crude Oil & |
Heavy Oil |
Tight Oil | ||||||||||||||||||||||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | ||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) | ||||||||||||||||||||||
At December 31, 2016 |
42,044 |
21,933 |
63,977 |
42,044 |
21,933 |
63,977 |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Extensions & Improved Recovery |
1,688 |
1,879 |
3,567 |
1,688 |
1,879 |
3,567 |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Technical Revisions |
1,086 |
(1,912) |
(826) |
1,086 |
(1,912) |
(826) |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Economic Factors |
(126) |
(114) |
(240) |
(126) |
(114) |
(240) |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Production |
(4,046) |
— |
(4,046) |
(4,046) |
— |
(4,046) |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
At December 31, 2017 |
40,646 |
21,786 |
62,432 |
40,646 |
21,786 |
62,432 |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | |||||||||||||||||||||||
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) | ||||||||||||||||||||||
At December 31, 2016 |
5,482 |
892 |
6,374 |
5,482 |
892 |
6,374 |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Extensions & Improved Recovery |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Technical Revisions |
3,239 |
968 |
4,207 |
3,239 |
968 |
4,207 |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Economic Factors |
(37) |
(6) |
(43) |
(37) |
(6) |
(43) |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Production |
(1) |
— |
(1) |
(1) |
— |
(1) |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
At December 31, 2017 |
8,683 |
1,854 |
10,537 |
8,683 |
1,854 |
10,537 |
— |
— |
— |
— |
— |
— | ||||||||||||||||||||||
Natural Gas Liquids |
BOE |
|||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
|||||||||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||||||||||||||||||||||||
At December 31, 2016 |
— |
— |
— |
42,958 |
22,082 |
65,040 |
||||||||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||||
Extensions & Improved Recovery |
— |
— |
— |
1,688 |
1,879 |
3,567 |
||||||||||||||||||||||||||||
Technical Revisions |
— |
— |
— |
1,625 |
(1,751) |
(126) |
||||||||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||||
Economic Factors |
— |
— |
— |
(132) |
(115) |
(247) |
||||||||||||||||||||||||||||
Production |
— |
— |
— |
(4,046) |
— |
(4,046) |
||||||||||||||||||||||||||||
At December 31, 2017 |
— |
— |
— |
42,093 |
22,095 |
64,188 |
GERMANY |
Total Oil (4) |
Light Crude Oil & |
Heavy Oil |
Tight Oil | |||||||||||||||||||||||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | |||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) | |||||||||||||||||||||||
At December 31, 2016 |
5,288 |
2,279 |
7,567 |
5,288 |
2,279 |
7,567 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
300 |
275 |
575 |
300 |
275 |
575 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
699 |
480 |
1,179 |
699 |
480 |
1,179 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
(112) |
(34) |
(146) |
(112) |
(34) |
(146) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
(387) |
— |
(387) |
(387) |
— |
(387) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
5,788 |
3,000 |
8,788 |
5,788 |
3,000 |
8,788 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | ||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | ||||||||||||||||||||||||
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) | |||||||||||||||||||||||
At December 31, 2016 |
41,481 |
54,284 |
95,765 |
41,481 |
54,284 |
95,765 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
117 |
108 |
225 |
117 |
108 |
225 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
6,590 |
(1,027) |
5,563 |
6,590 |
(1,027) |
5,563 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
— |
(231) |
(231) |
— |
(231) |
(231) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
(7,077) |
— |
(7,077) |
(7,077) |
— |
(7,077) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
41,111 |
53,134 |
94,245 |
41,111 |
53,134 |
94,245 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Natural Gas Liquids |
BOE |
||||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
||||||||||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
|||||||||||||||||||||||||||||
At December 31, 2016 |
— |
— |
— |
12,202 |
11,326 |
23,528 |
|||||||||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Extensions & Improved Recovery |
— |
— |
— |
320 |
293 |
613 |
|||||||||||||||||||||||||||||
Technical Revisions |
— |
— |
— |
1,797 |
310 |
2,107 |
|||||||||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Economic Factors |
— |
— |
— |
(112) |
(73) |
(185) |
|||||||||||||||||||||||||||||
Production |
— |
— |
— |
(1,567) |
— |
(1,567) |
|||||||||||||||||||||||||||||
At December 31, 2017 |
— |
— |
— |
12,640 |
11,856 |
24,496 |
IRELAND |
Total Oil (4) |
Light Crude Oil & |
Heavy Oil |
Tight Oil | |||||||||||||||||||||||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | |||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) | |||||||||||||||||||||||
At December 31, 2016 |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | ||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | ||||||||||||||||||||||||
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) | |||||||||||||||||||||||
At December 31, 2016 |
99,575 |
50,787 |
150,362 |
99,575 |
50,787 |
150,362 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
3,553 |
602 |
4,155 |
3,553 |
602 |
4,155 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
(21,325) |
— |
(21,325) |
(21,325) |
— |
(21,325) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
81,803 |
51,389 |
133,192 |
81,803 |
51,389 |
133,192 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Natural Gas Liquids |
BOE |
||||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
||||||||||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
|||||||||||||||||||||||||||||
At December 31, 2016 |
— |
— |
— |
16,596 |
8,465 |
25,061 |
|||||||||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Extensions & Improved Recovery |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Technical Revisions |
— |
— |
— |
592 |
100 |
692 |
|||||||||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Economic Factors |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Production |
— |
— |
— |
(3,554) |
— |
(3,554) |
|||||||||||||||||||||||||||||
At December 31, 2017 |
— |
— |
— |
13,634 |
8,565 |
22,199 |
NETHERLANDS |
Total Oil (4) |
Light Crude Oil & |
Heavy Oil |
Tight Oil | |||||||||||||||||||||||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | |||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) | |||||||||||||||||||||||
At December 31, 2016 |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | ||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | ||||||||||||||||||||||||
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) | |||||||||||||||||||||||
At December 31, 2016 |
62,350 |
43,184 |
105,534 |
62,350 |
43,184 |
105,534 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
8,163 |
7,807 |
15,970 |
8,163 |
7,807 |
15,970 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
5,232 |
(6,579) |
(1,347) |
5,232 |
(6,579) |
(1,347) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
(22) |
(32) |
(54) |
(22) |
(32) |
(54) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
(14,797) |
— |
(14,797) |
(14,797) |
— |
(14,797) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
60,926 |
44,380 |
105,306 |
60,926 |
44,380 |
105,306 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Natural Gas Liquids |
BOE |
||||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
||||||||||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
|||||||||||||||||||||||||||||
At December 31, 2016 |
81 |
63 |
144 |
10,473 |
7,260 |
17,733 |
|||||||||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Extensions & Improved Recovery |
30 |
21 |
51 |
1,391 |
1,322 |
2,713 |
|||||||||||||||||||||||||||||
Technical Revisions |
115 |
35 |
150 |
986 |
(1,061) |
(75) |
|||||||||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Economic Factors |
— |
— |
— |
(4) |
(5) |
(9) |
|||||||||||||||||||||||||||||
Production |
(33) |
— |
(33) |
(2,499) |
— |
(2,499) |
|||||||||||||||||||||||||||||
At December 31, 2017 |
193 |
119 |
312 |
10,347 |
7,516 |
17,863 |
UNITED STATES |
Total Oil (4) |
Light Crude Oil & |
Heavy Oil |
Tight Oil | |||||||||||||||||||||||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | |||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) | |||||||||||||||||||||||
At December 31, 2016 |
3,169 |
5,727 |
8,896 |
3,169 |
5,727 |
8,896 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
1,413 |
1,483 |
2,896 |
1,413 |
1,483 |
2,896 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
(49) |
(133) |
(182) |
(49) |
(133) |
(182) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
(9) |
(4) |
(13) |
(9) |
(4) |
(13) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
(242) |
— |
(242) |
(242) |
— |
(242) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
4,282 |
7,073 |
11,355 |
4,282 |
7,073 |
11,355 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | ||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | ||||||||||||||||||||||||
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) | |||||||||||||||||||||||
At December 31, 2016 |
2,969 |
5,481 |
8,450 |
2,969 |
5,481 |
8,450 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
1,328 |
1,554 |
2,882 |
1,328 |
1,554 |
2,882 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
231 |
489 |
720 |
231 |
489 |
720 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
(5) |
(4) |
(9) |
(5) |
(4) |
(9) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
(143) |
— |
(143) |
(143) |
— |
(143) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
At December 31, 2017 |
4,380 |
7,520 |
11,900 |
4,380 |
7,520 |
11,900 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Natural Gas Liquids |
BOE |
||||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
||||||||||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
|||||||||||||||||||||||||||||
At December 31, 2016 |
412 |
760 |
1,172 |
4,076 |
7,401 |
11,477 |
|||||||||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Extensions & Improved Recovery |
182 |
213 |
395 |
1,816 |
1,955 |
3,771 |
|||||||||||||||||||||||||||||
Technical Revisions |
28 |
59 |
87 |
18 |
7 |
25 |
|||||||||||||||||||||||||||||
Acquisitions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Economic Factors |
(1) |
(1) |
(2) |
(11) |
(6) |
(17) |
|||||||||||||||||||||||||||||
Production |
(20) |
— |
(20) |
(286) |
— |
(286) |
|||||||||||||||||||||||||||||
At December 31, 2017 |
601 |
1,031 |
1,632 |
5,613 |
9,357 |
14,970 |
TOTAL COMPANY |
Total Oil (4) |
Light Crude Oil & |
Heavy Oil |
Tight Oil | |||||||||||||||||||||||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | |||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) | |||||||||||||||||||||||
At December 31, 2016 |
84,893 |
48,694 |
133,587 |
84,881 |
48,692 |
133,573 |
— |
— |
— |
12 |
2 |
14 | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
3,995 |
3,939 |
7,934 |
3,995 |
3,939 |
7,934 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
1,658 |
(3,107) |
(1,449) |
1,669 |
(3,105) |
(1,436) |
— |
— |
— |
(11) |
(2) |
(13) | |||||||||||||||||||||||
Acquisitions |
16 |
4 |
20 |
16 |
4 |
20 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
(295) |
(136) |
(431) |
(295) |
(136) |
(431) |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Production |
(8,976) |
— |
(8,976) |
(8,975) |
— |
(8,975) |
— |
— |
— |
(1) |
— |
(1) | |||||||||||||||||||||||
At December 31, 2017 |
81,291 |
49,394 |
130,685 |
81,291 |
49,394 |
130,685 |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | ||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + | ||||||||||||||||||||||||
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) | |||||||||||||||||||||||
At December 31, 2016 |
438,387 |
311,296 |
749,683 |
428,955 |
306,335 |
735,290 |
8,061 |
4,677 |
12,738 |
1,371 |
284 |
1,655 | |||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— | |||||||||||||||||||||||
Extensions & Improved Recovery |
67,648 |
38,989 |
106,637 |
66,683 |
38,446 |
105,129 |
965 |
543 |
1,508 |
— |
— |
— | |||||||||||||||||||||||
Technical Revisions |
20,541 |
(5,175) |
15,366 |
19,902 |
(5,169) |
14,733 |
799 |
64 |
863 |
(160) |
(70) |
(230) | |||||||||||||||||||||||
Acquisitions |
3,452 |
1,113 |
4,565 |
2,686 |
872 |
3,558 |
766 |
241 |
1,007 |
— |
— |
— | |||||||||||||||||||||||
Dispositions |
(2,182) |
(2,150) |
(4,332) |
(576) |
(231) |
(807) |
(1,606) |
(1,919) |
(3,525) |
— |
— |
— | |||||||||||||||||||||||
Economic Factors |
(3,722) |
(1,474) |
(5,196) |
(2,561) |
(921) |
(3,482) |
(1,161) |
(553) |
(1,714) |
— |
— |
— | |||||||||||||||||||||||
Production |
(79,073) |
— |
(79,073) |
(77,890) |
— |
(77,890) |
(1,111) |
— |
(1,111) |
(72) |
— |
(72) | |||||||||||||||||||||||
At December 31, 2017 |
445,051 |
342,599 |
787,650 |
437,199 |
339,332 |
776,531 |
6,713 |
3,053 |
9,766 |
1,139 |
214 |
1,353 | |||||||||||||||||||||||
Natural Gas Liquids |
BOE |
||||||||||||||||||||||||||||||||||
Proved |
Probable |
Proved + |
Proved |
Probable |
Proved + |
||||||||||||||||||||||||||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
|||||||||||||||||||||||||||||
At December 31, 2016 |
17,856 |
13,730 |
31,586 |
175,815 |
114,307 |
290,122 |
|||||||||||||||||||||||||||||
Discoveries |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||||||
Extensions & Improved Recovery |
5,881 |
1,469 |
7,350 |
21,151 |
11,906 |
33,057 |
|||||||||||||||||||||||||||||
Technical Revisions |
(128) |
189 |
61.49 |
4,953 |
(3,781) |
1,172 |
|||||||||||||||||||||||||||||
Acquisitions |
351 |
113 |
464 |
942 |
303 |
1,245 |
|||||||||||||||||||||||||||||
Dispositions |
(3) |
(1) |
(4) |
(367) |
(359) |
(726) |
|||||||||||||||||||||||||||||
Economic Factors |
(185) |
(68) |
(253) |
(1,101) |
(450) |
(1,551) |
|||||||||||||||||||||||||||||
Production |
(2,674) |
— |
(2,674) |
(24,829) |
— |
(24,829) |
|||||||||||||||||||||||||||||
At December 31, 2017 |
21,098 |
15,432 |
36,530.49 |
176,564 |
121,926 |
298,490 |
Notes: | |
(1) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(2) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(3) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(4) |
For reporting purposes, "Total Oil" is the sum of Light Crude oil and Medium Crude Oil, Heavy Oil and Tight Oil. For reporting purposes, "Total Gas" is the sum of Conventional Natural Gas, Coal Bed Methane and Shale Gas. |
(5) |
"Coal Bed Methane" and "Shale Gas" were considered "Unconventional Natural Gas" in previous years. NI 51-101 no longer differentiates between conventional and unconventional activities. |
The table below sets out the future development costs deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).
Table 9: Future Development Costs(1)
(M$) |
Total Proved |
Total Proved Plus Probable | |
Australia |
|||
2018 |
11,565 |
11,565 | |
2019 |
70,052 |
70,052 | |
2020 |
3,026 |
3,026 | |
2021 |
3,140 |
58,821 | |
2022 |
3,164 |
3,164 | |
Remainder |
9,936 |
20,173 | |
Total for all years undiscounted |
100,883 |
166,801 | |
Canada |
|||
2018 |
136,499 |
150,107 | |
2019 |
142,540 |
155,186 | |
2020 |
110,461 |
139,784 | |
2021 |
20,828 |
119,929 | |
2022 |
622 |
114,329 | |
Remainder |
1,373 |
65,337 | |
Total for all years undiscounted |
412,323 |
744,672 | |
France |
|||
2018 |
30,969 |
52,162 | |
2019 |
34,118 |
84,258 | |
2020 |
19,848 |
100,335 | |
2021 |
26,017 |
59,875 | |
2022 |
4,289 |
24,707 | |
Remainder |
10,633 |
24,859 | |
Total for all years undiscounted |
125,874 |
346,196 | |
Germany |
|||
2018 |
2,116 |
5,381 | |
2019 |
11,172 |
17,742 | |
2020 |
3,162 |
10,590 | |
2021 |
3,185 |
29,808 | |
2022 |
124 |
38,918 | |
Remainder |
650 |
2,460 | |
Total for all years undiscounted |
20,409 |
104,899 | |
Ireland |
|||
2018 |
— |
— | |
2019 |
1,855 |
1,855 | |
2020 |
— |
19,271 | |
2021 |
— |
— | |
2022 |
— |
— | |
Remainder |
17,052 |
17,052 | |
Total for all years undiscounted |
18,907 |
38,178 | |
Netherlands |
|||
2018 |
3,205 |
9,569 | |
2019 |
12,253 |
13,923 | |
2020 |
6,181 |
14,170 | |
2021 |
324 |
4,909 | |
2022 |
326 |
4,921 | |
Remainder |
5,877 |
5,877 | |
Total for all years undiscounted |
28,166 |
53,369 | |
United States |
|||
2018 |
3,797 |
11,392 | |
2019 |
28,082 |
39,224 | |
2020 |
35,114 |
46,818 | |
2021 |
— |
48,532 | |
2022 |
— |
— | |
Remainder |
— |
— | |
Total for all years undiscounted |
66,993 |
145,966 | |
Total Company |
|||
2018 |
188,151 |
240,176 | |
2019 |
300,072 |
382,240 | |
2020 |
177,792 |
333,994 | |
2021 |
53,494 |
321,874 | |
2022 |
8,525 |
186,039 | |
Remainder |
45,521 |
135,758 | |
Total for all years undiscounted |
773,555 |
1,600,081 |
Note:
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
Vermilion expects to source its capital expenditure requirements from internally generated cash flow and, as appropriate, from Vermilion's existing credit facility or equity or debt financing. It is anticipated that costs of funding the future development costs will not impact development of its properties or Vermilion's reserves or future net revenue.
APPENDIX A
CONTINGENT RESOURCES
Summary information regarding contingent resources and net present value of future net revenues from contingent resources are set forth below and are derived, in each case, from the GLJ Resources Assessment. The GLJ Resources Assessment was prepared in accordance with COGEH and NI-51-101 by GLJ, an independent qualified reserve evaluator. All contingent resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2017. Contingent resources are in addition to reserves estimated in the GLJ Report.
A range of contingent resources estimates (low, best and high) were prepared by GLJ. See notes 6 to 8 of the tables below for a description of low estimate, best estimate and high estimate.
The GLJ Resources Assessment estimated gross risked contingent resources with a project maturity subclass of "Development Pending" of 107.3 million boe (low estimate) to 253.6 million boe (high estimate), with a best estimate of 176.7 million boe. Contingent resources are in addition to reserves estimated in the GLJ Report.
The GLJ Resources Assessment estimated gross risked contingent resources with a project maturity subclass of "Development Unclarified" of 7.5 million boe (low estimate) to 46.1 million boe (high estimate), with a best estimate of 32.8 million boe.
An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
Table 10: Summary of Risked Oil and Gas Contingent Resources as at December 31, 2017 (1) (2) - Forecast Prices and Costs (3) (4)
Resources |
Light Crude Oil & |
Conventional |
Coal Bed |
Natural Gas |
BOE |
Unrisked | ||||||||||||||||||||||||||||||||
Project |
||||||||||||||||||||||||||||||||||||||
Maturity |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Chance |
Gross |
Net | |||||||||||||||||||||||||
Sub-Class |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
% (9) |
(Mboe) |
(Mboe) | |||||||||||||||||||||||||
Contingent (1C) - Low Estimate |
||||||||||||||||||||||||||||||||||||||
Development Pending (10) |
||||||||||||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Canada |
11,918 |
10,818 |
217,576 |
200,317 |
2,081 |
1,977 |
17,879 |
15,803 |
66,407 |
60,337 |
82 |
% |
80,740 |
73,403 |
||||||||||||||||||||||||
France |
13,677 |
12,798 |
940 |
940 |
— |
— |
— |
— |
13,834 |
12,955 |
87 |
% |
15,923 |
14,908 |
||||||||||||||||||||||||
Germany |
— |
— |
19,342 |
16,795 |
— |
— |
— |
— |
3,224 |
2,799 |
77 |
% |
4,187 |
3,635 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Netherlands |
61 |
61 |
4,647 |
4,647 |
— |
— |
1 |
1 |
837 |
837 |
81 |
% |
1,038 |
1,038 |
||||||||||||||||||||||||
USA |
17,651 |
14,699 |
17,643 |
14,693 |
— |
— |
2,416 |
2,104 |
23,008 |
19,252 |
90 |
% |
25,567 |
21,391 |
||||||||||||||||||||||||
Total |
43,307 |
38,376 |
260,148 |
237,392 |
2,081 |
1,977 |
20,296 |
17,908 |
107,310 |
96,180 |
84 |
% |
127,453 |
114,375 |
||||||||||||||||||||||||
Contingent (2C) - Best Estimate |
||||||||||||||||||||||||||||||||||||||
Development Pending (10) |
||||||||||||||||||||||||||||||||||||||
Australia (11) |
2,440 |
2,440 |
— |
— |
— |
— |
— |
— |
2,440 |
2,440 |
80 |
% |
3,050 |
3,050 |
||||||||||||||||||||||||
Canada (12) |
19,312 |
17,209 |
352,291 |
322,162 |
2,520 |
2,394 |
27,354 |
23,739 |
105,801 |
95,041 |
81 |
% |
131,380 |
118,063 |
||||||||||||||||||||||||
France (13) |
27,054 |
25,229 |
1,245 |
1,245 |
— |
— |
— |
— |
27,262 |
25,437 |
85 |
% |
32,027 |
29,891 |
||||||||||||||||||||||||
Germany (14) |
— |
— |
33,721 |
29,267 |
— |
— |
— |
— |
5,620 |
4,878 |
77 |
% |
7,299 |
6,335 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Netherlands (15) |
121 |
121 |
13,995 |
13,995 |
— |
— |
8 |
8 |
2,462 |
2,462 |
78 |
% |
3,170 |
3,169 |
||||||||||||||||||||||||
USA (16) |
25,289 |
21,060 |
25,924 |
21,589 |
— |
— |
3,554 |
2,960 |
33,164 |
27,618 |
90 |
% |
36,849 |
30,687 |
||||||||||||||||||||||||
Total |
74,216 |
66,059 |
427,176 |
388,258 |
2,520 |
2,394 |
30,916 |
26,707 |
176,749 |
157,876 |
83 |
% |
213,775 |
191,195 |
||||||||||||||||||||||||
Contingent (3C) - High Estimate |
||||||||||||||||||||||||||||||||||||||
Development Pending (10) |
||||||||||||||||||||||||||||||||||||||
Australia |
3,280 |
3,280 |
3,280 |
3,280 |
80 |
% |
4,100 |
4,100 |
||||||||||||||||||||||||||||||
Canada |
24,079 |
21,133 |
488,328 |
443,399 |
2,943 |
2,796 |
37,617 |
31,953 |
143,575 |
127,452 |
80 |
% |
179,355 |
159,116 |
||||||||||||||||||||||||
France |
43,275 |
40,278 |
1,618 |
1,618 |
— |
— |
— |
— |
43,545 |
40,548 |
84 |
% |
51,613 |
48,043 |
||||||||||||||||||||||||
Germany |
— |
— |
62,480 |
54,212 |
— |
— |
— |
— |
10,413 |
9,035 |
77 |
% |
13,523 |
11,734 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Netherlands |
242 |
242 |
27,237 |
27,237 |
— |
— |
16 |
16 |
4,798 |
4,798 |
79 |
% |
6,100 |
6,097 |
||||||||||||||||||||||||
USA |
36,411 |
30,320 |
38,218 |
31,826 |
— |
— |
5,240 |
4,363 |
48,021 |
39,987 |
90 |
% |
53,356 |
44,430 |
||||||||||||||||||||||||
Total |
107,287 |
95,253 |
617,881 |
558,292 |
2,943 |
2,796 |
42,873 |
36,332 |
253,632 |
225,100 |
82 |
% |
308,047 |
273,520 |
Resources |
Light Crude Oil & |
Conventional |
Coal Bed |
Natural Gas |
BOE |
Unrisked | ||||||||||||||||||||||||||||||||
Project |
||||||||||||||||||||||||||||||||||||||
Maturity |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Chance |
Gross |
Net | |||||||||||||||||||||||||
Sub-Class |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
% (9) |
(Mboe) |
(Mboe) | |||||||||||||||||||||||||
Contingent (1C) - Low Estimate |
||||||||||||||||||||||||||||||||||||||
Development Unclarified (17) |
||||||||||||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Canada |
— |
— |
30,844 |
27,821 |
— |
— |
531 |
439 |
5,672 |
5,076 |
60 |
% |
9,463 |
8,474 |
||||||||||||||||||||||||
France |
1,302 |
1,235 |
— |
— |
— |
— |
— |
— |
1,302 |
1,235 |
41 |
% |
3,212 |
3,049 |
||||||||||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Netherlands |
— |
— |
3,120 |
3,120 |
— |
— |
— |
— |
520 |
520 |
70 |
% |
743 |
743 |
||||||||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Total |
1,302 |
1,235 |
33,964 |
30,941 |
— |
— |
531 |
439 |
7,494 |
6,831 |
56 |
% |
13,418 |
12,266 |
||||||||||||||||||||||||
Contingent (2C) - Best Estimate |
||||||||||||||||||||||||||||||||||||||
Development Unclarified (17) |
||||||||||||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Canada (18) |
— |
— |
60,273 |
53,873 |
60,886 |
57,652 |
6,641 |
5,995 |
26,834 |
24,583 |
46 |
% |
58,404 |
53,558 |
||||||||||||||||||||||||
France (19) |
2,539 |
2,410 |
— |
— |
— |
— |
— |
— |
2,539 |
2,410 |
45 |
% |
5,690 |
5,404 |
||||||||||||||||||||||||
Germany |
— |
— |
1,496 |
1,190 |
— |
— |
— |
— |
249 |
198 |
35 |
% |
711 |
566 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Netherlands (20) |
— |
— |
18,678 |
18,104 |
— |
— |
32 |
16 |
3,145 |
3,033 |
51 |
% |
6,134 |
5,912 |
||||||||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Total |
2,539 |
2,410 |
80,447 |
73,167 |
60,886 |
57,652 |
6,673 |
6,011 |
32,767 |
30,224 |
46 |
% |
70,939 |
65,440 |
||||||||||||||||||||||||
Contingent (3C) - High Estimate |
||||||||||||||||||||||||||||||||||||||
Development Unclarified (17) |
||||||||||||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Canada |
— |
— |
78,561 |
69,281 |
77,410 |
72,283 |
10,104 |
8,744 |
36,099 |
32,338 |
46 |
% |
78,918 |
70,761 |
||||||||||||||||||||||||
France |
3,825 |
3,632 |
— |
— |
— |
— |
— |
— |
3,825 |
3,632 |
46 |
% |
8,250 |
7,828 |
||||||||||||||||||||||||
Germany |
— |
— |
2,327 |
1,850 |
— |
— |
— |
— |
388 |
308 |
35 |
% |
1,109 |
880 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Netherlands |
— |
— |
34,682 |
33,807 |
— |
— |
48 |
24 |
5,828 |
5,659 |
54 |
% |
10,743 |
10,441 |
||||||||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||||||||
Total |
3,825 |
3,632 |
115,570 |
104,938 |
77,410 |
72,283 |
10,152 |
8,768 |
46,140 |
41,937 |
47 |
% |
99,020 |
89,910 |
Table 11: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2017 - Forecast Prices and Costs (3)
Resources Project |
|||||||||||||||||||||||||||||
Maturity Sub-Class |
Before Income Taxes, Discounted at (5) |
After Income Taxes, Discounted at (5) | |||||||||||||||||||||||||||
(M$) |
0% |
5% |
10% |
15% |
20% |
0% |
5% |
10% |
15% |
20% | |||||||||||||||||||
Contingent (1C) - Low Estimate (6) |
|||||||||||||||||||||||||||||
Development Pending (10) |
|||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Canada |
1,324,088 |
692,454 |
384,479 |
223,327 |
133,827 |
968,246 |
491,682 |
261,417 |
143,098 |
78,999 |
|||||||||||||||||||
France |
646,356 |
356,990 |
207,518 |
125,059 |
77,334 |
475,460 |
249,755 |
136,639 |
76,160 |
42,380 |
|||||||||||||||||||
Germany |
25,368 |
15,606 |
8,171 |
2,911 |
(697) |
15,012 |
7,957 |
2,377 |
(1,574) |
(4,234) |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands |
30,463 |
22,364 |
16,718 |
12,743 |
9,886 |
18,249 |
13,309 |
9,784 |
7,297 |
5,522 |
|||||||||||||||||||
USA |
705,352 |
353,098 |
190,899 |
109,417 |
65,316 |
553,775 |
277,974 |
149,964 |
85,463 |
50,507 |
|||||||||||||||||||
Total |
2,731,627 |
1,440,512 |
807,785 |
473,457 |
285,666 |
2,030,742 |
1,040,677 |
560,181 |
310,444 |
173,174 |
|||||||||||||||||||
Contingent (2C) - Best Estimate (7) |
|||||||||||||||||||||||||||||
Development Pending (10) |
|||||||||||||||||||||||||||||
Australia (11) |
81,610 |
50,240 |
31,044 |
19,219 |
11,873 |
17,295 |
7,186 |
1,687 |
(1,167) |
(2,534) |
|||||||||||||||||||
Canada (12) |
2,286,705 |
1,179,969 |
662,147 |
394,654 |
245,475 |
1,674,927 |
844,557 |
458,109 |
261,348 |
153,799 |
|||||||||||||||||||
France (13) |
1,414,420 |
759,973 |
439,654 |
268,026 |
170,036 |
1,048,109 |
540,491 |
298,625 |
172,711 |
103,017 |
|||||||||||||||||||
Germany (14) |
116,948 |
83,758 |
60,390 |
44,003 |
32,395 |
80,292 |
56,601 |
39,643 |
27,741 |
19,370 |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands (15) |
81,618 |
57,215 |
41,025 |
29,997 |
22,252 |
43,748 |
28,728 |
18,805 |
12,189 |
7,679 |
|||||||||||||||||||
USA (16) |
1,275,912 |
623,677 |
342,983 |
205,348 |
130,725 |
1,004,012 |
492,135 |
270,653 |
161,886 |
102,881 |
|||||||||||||||||||
Total |
5,257,213 |
2,754,832 |
1,577,243 |
961,247 |
612,756 |
3,868,383 |
1,969,698 |
1,087,522 |
634,708 |
384,212 |
|||||||||||||||||||
Contingent (3C) - High Estimate (8) |
|||||||||||||||||||||||||||||
Development Pending (10) |
|||||||||||||||||||||||||||||
Australia |
162,700 |
104,204 |
67,988 |
45,184 |
30,555 |
54,329 |
31,507 |
18,140 |
10,277 |
5,629 |
|||||||||||||||||||
Canada |
3,312,383 |
1,649,632 |
923,352 |
557,850 |
354,901 |
2,402,861 |
1,167,883 |
630,702 |
364,282 |
219,347 |
|||||||||||||||||||
France |
2,463,627 |
1,310,231 |
760,541 |
468,396 |
301,212 |
1,827,017 |
934,100 |
520,513 |
306,268 |
186,763 |
|||||||||||||||||||
Germany |
302,880 |
217,383 |
159,970 |
120,614 |
92,931 |
212,387 |
151,748 |
110,557 |
82,278 |
62,446 |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands |
205,065 |
142,394 |
103,727 |
78,262 |
60,611 |
110,555 |
74,368 |
52,017 |
37,485 |
27,588 |
|||||||||||||||||||
USA |
2,174,766 |
1,004,149 |
546,550 |
330,707 |
215,009 |
1,713,929 |
792,856 |
431,644 |
261,128 |
169,703 |
|||||||||||||||||||
Total |
8,621,421 |
4,427,993 |
2,562,128 |
1,601,013 |
1,055,219 |
6,321,078 |
3,152,462 |
1,763,573 |
1,061,718 |
671,476 |
|||||||||||||||||||
Contingent (1C) - Low Estimate (6) |
|||||||||||||||||||||||||||||
Development Unclarified (17) |
|||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Canada |
53,655 |
21,601 |
9,005 |
3,855 |
1,673 |
41,934 |
16,497 |
6,597 |
2,643 |
1,029 |
|||||||||||||||||||
France |
97,733 |
53,885 |
31,470 |
19,270 |
12,266 |
73,554 |
40,473 |
23,562 |
14,377 |
9,118 |
|||||||||||||||||||
Germany |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands |
13,366 |
8,426 |
5,351 |
3,406 |
2,156 |
6,990 |
3,867 |
1,988 |
855 |
175 |
|||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Total |
164,754 |
83,912 |
45,826 |
26,531 |
16,095 |
122,478 |
60,837 |
32,147 |
17,875 |
10,322 |
|||||||||||||||||||
Contingent (2C) - Best Estimate (7) |
|||||||||||||||||||||||||||||
Development Unclarified (17) |
|||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Canada (18) |
371,151 |
160,012 |
67,074 |
23,472 |
2,109 |
267,364 |
108,714 |
38,845 |
6,527 |
(8,792) |
|||||||||||||||||||
France (19) |
180,756 |
91,957 |
50,625 |
29,643 |
18,218 |
134,726 |
67,893 |
36,941 |
21,367 |
12,973 |
|||||||||||||||||||
Germany |
472 |
736 |
724 |
616 |
487 |
(353) |
41 |
132 |
107 |
45 |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands (20) |
101,333 |
60,727 |
37,612 |
23,937 |
15,510 |
58,291 |
33,549 |
19,395 |
11,127 |
6,149 |
|||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Total |
653,712 |
313,432 |
156,035 |
77,668 |
36,324 |
460,028 |
210,197 |
95,313 |
39,128 |
10,375 |
|||||||||||||||||||
Contingent (3C) - High Estimate (8) |
|||||||||||||||||||||||||||||
Development Unclarified (17) |
|||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Canada |
685,972 |
314,515 |
159,130 |
85,452 |
47,007 |
547,002 |
261,869 |
138,799 |
78,569 |
46,086 |
|||||||||||||||||||
France |
292,883 |
138,555 |
73,474 |
42,171 |
25,626 |
217,128 |
101,766 |
53,321 |
30,222 |
18,141 |
|||||||||||||||||||
Germany |
4,579 |
4,019 |
3,344 |
2,727 |
2,210 |
2,638 |
2,450 |
2,054 |
1,651 |
1,300 |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands |
244,742 |
135,716 |
82,312 |
53,187 |
35,980 |
141,378 |
76,237 |
44,453 |
27,335 |
17,400 |
|||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Total |
1,228,176 |
592,805 |
318,260 |
183,537 |
110,823 |
908,146 |
442,322 |
238,627 |
137,777 |
82,927 |
Notes:
(1) |
Contingent resources are defined in the COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated, as at a given date, and that the resources can be profitably produced in the future. The risked net present value of the future net revenue from the contingent resources does not represent the fair market value of the contingent resources. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein. | |||
(2) |
GLJ prepared the estimates of contingent resources shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. | |||
(3) |
The forecast price and cost assumptions utilized in the year-end 2017 reserves report were also utilized by GLJ in preparing the GLJ Resource Assessment. See "Forecast Prices Used in Estimates" in this AIF. | |||
(4) |
"Gross" contingent resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net" contingent resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in contingent resources. | |||
(5) |
The risked net present value of future net revenue attributable to the contingent resources does not represent the fair market value of the contingent resources. Estimated abandonment and reclamation costs have been included in the evaluation. | |||
(6) |
This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. | |||
(7) |
This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. | |||
(8) |
This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. | |||
(9) |
The Chance of Development (CoDev) is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows: | |||
• |
CoDev = Ps (Economic Factor) × Ps (Technology Factor) × Ps (Development Plan Factor) ×Ps (Development Timeframe Factor) × Ps (Other Contingency Factor) wherein | |||
• |
Ps is the probability of success | |||
• |
Economic Factor – For reserves to be assessed, a project must be economic. With respect to contingent resources, this factor captures uncertainty in the assessment of economic status principally due to uncertainty in cost estimates and marketing options. Economic viability uncertainty due to technology is more aptly captured with the Technology Factor. The Economic Factor will be 1 for reserves and will often be 1 for development pending projects and for projects with a development study or pre-development study with a robust rate of return. A robust rate of return means that the project retains economic status with variation in costs and/or marketing plans over the expected range of outcomes for these variables. | |||
• |
Technology Factor - For reserves to be assessed, a project must utilize established technology. With respect to contingent resources, this factor captures the uncertainty in the viability of the proposed technology for the subject reservoir, namely, the uncertainty associated with technology under development. By definition, technology under development is a recovery process or process improvement that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir. The Technology Factor will be 1 for reserves and for established technology. For technology under development, this factor will consider different risks associated with technologies being developed at the scale of the well versus the scale of a project and technologies which are being modified or extended for the subject reservoir versus new emerging technologies which have not previously been applied in any commercial application. The risk assessment will also consider the quality and sufficiency of the test data available, the ability to reliably scale such data and the ability to extrapolate results in time. | |||
• |
Development Plan Factor – For reserves to be assessed, a project must have a detailed development plan. With respect to contingent resources, this factor captures the uncertainty in the project evaluation scenario. The Development Plan Factor will be 1 for reserves and high, approaching 1, for development pending projects. This factor will consider development plan detail variations including the degree of delineation, reservoir specific development and operating strategy detail (technology decision, well layouts (spacing and pad locations), completion strategy, start-up strategy, water source and disposal, other infrastructure, facility design, marketing plans) and the quality of the cost estimates as provided by the developer. | |||
• |
Development Timeframe Factor – In the case of major projects, for reserves to be assessed, first major capital spending must be initiated within 5 years of the effective date. The Development Timeframe Factor will be 1 for reserves and will often be 1 for development pending projects provided the project is planned on-stream based on the same criteria used in the assessment of reserves. With respect to contingent resources, the factor will approach 1 for projects planned on-stream with a timeframe slightly longer than the limiting reserves criteria. | |||
• |
Other Contingency Factor – For reserves to be assessed, all contingencies must be eliminated. With respect to contingent resources, this factor captures major contingencies, usually beyond the control of the operator, other than those captured by economic status, technology status, project evaluation scenario status and the development timeframe. The Other Contingency Factor will be 1 for reserves and for development pending projects and less than 1 for on hold. Provided all contingencies have been identified and their resolution is reasonably certain, this factor would also be 1 for development unclarified projects. | |||
• |
These factors may be inter-related (dependent) and care has been taken to ensure that risks are appropriately accounted. | |||
(10) |
Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development). | |||
(11) |
Risked development pending best estimate contingent resources for Australia have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The risked estimated cost to bring these contingent resources on commercial production is $143 MM and the expected timeline is between 6 and 8 years. The specific contingencies for these resources are corporate commitment and development timing. | |||
(12) |
Risked development pending best estimate contingent resources for Canada have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The risked estimated cost to bring these contingent resources on commercial production is $1,066 MM and the expected timeline is between 3 and 12 years. The specific contingencies for these resources are corporate commitment and development timing. | |||
(13) |
Risked development pending best estimate contingent resources for France have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The risked estimated cost to bring these contingent resources on commercial production is $571 MM and the expected timeline is between 3 and 12 years. The specific contingencies for these resources are corporate commitment and development timing. | |||
(14) |
Risked development pending best estimate contingent resources for Germany have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The risked estimated cost to bring these contingent resources on commercial production is $75 MM and the expected timeline is between 2 and 4 years. The specific contingencies for these resources are corporate commitment and development timing. | |||
(15) |
Risked development pending best estimate contingent resources for Netherlands have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The risked estimated cost to bring these contingent resources on commercial production is $45 MM and the expected timeline is between 2 and 4 years. The specific contingencies for these resources are corporate commitment and development timing. | |||
(16) |
Risked development pending best estimate contingent resources for USA have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The risked risked estimated cost to bring these contingent resources on commercial production is $380 MM and the expected timeline is between 1 and 11 years. The specific contingencies for these resources are corporate commitment and development timing. | |||
(17) |
Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. | |||
(18) |
In Canada, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 26.8 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $323 MM with an expected timeline of 3 to 12 years. | |||
Edson Duvernay |
Based on contingencies related to corporate commitment and development timing, economic risks associated with lower liquid yields, and capital and operating cost uncertainty, GLJ has estimated risked unclarified best estimate contingent resources at 15.5 mmboe and the risked estimated cost to bring these resources on commercial production is $242.8 MM. The expected timeline is 3 to 7 years. | |||
Ferrier Notikewin |
Based on contingencies related to corporate commitment and development timing that is greater than 10 years, GLJ has estimated risked unclarified best estimate contingent resources at 4.7 mmboe and the risked estimated cost to bring these resources on commercial production is $31 MM. The expected timeline is 11 to 15 years. | |||
Ferrier Falher |
Based on contingencies related to corporate commitment and development timing that is greater than 10 years, GLJ has estimated risked unclarified best estimate contingent resources at 3.2 mmboe and the risked estimated cost to bring these resources on commercial production is $23 MM. The expected timeline is 11 to 15 years. | |||
West Pembina Glauconite |
Based on contingencies related to corporate commitment and development timing as well as economic risk related to capital and operating cost uncertainty due to limited horizontal development in proximity to interest lands, GLJ has estimated risked unclarified best estimate contingent resources at 3.3 mmboe and the risked estimated cost to bring these resources on commercial production is $26 MM. The expected timeline is 4 to 6 years. | |||
(19) |
In France, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 2.5 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $37 MM with an expected timeline of 7 to 8 years. | |||
Charmottes |
Based on contingencies related to corporate commitment and development timing, along with the project still being in the pre-development study/sourcing stage related to waterflood development, GLJ has estimated risked unclarified best estimate contingent resources at 1.3 mmboe and the risked estimated cost to bring these resources on commercial production is $29 MM. The expected timeline is 7 to 9 years. | |||
Chaunoy |
Based on contingencies related to corporate commitment and development timing, along with a CO2 pilot project still being in the conceptual study stage, GLJ has estimated risked unclarified best estimate contingent resources at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $8 MM. The expected timeline is 8 to 10 years. | |||
(20) |
In the Netherlands, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 3.1 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $51 MM with an expected timeline of 8 to 10 years. | |||
Netherlands East |
Based on contingencies related to corporate commitment and development timing along with proof-of-concept utilizing directional drilling and unknown deliverability from Zechstein carbonates, GLJ has estimated risked unclarified best estimate contingent resources at 1.5 mmboe and the risked estimated cost to bring these resources on commercial production is $25 MM. The expected timeline is 3 to 7 years. | |||
Netherlands West |
Based on contingencies related to corporate commitment and development timing along with further study required regarding the deliverability of the Bunter sands, GLJ has estimated risked unclarified best estimate contingent resources at 1.6 mmboe and the risked estimated cost to bring these resources on commercial production is $26 MM. The expected timeline is 3 to 5 years. |
PROSPECTIVE RESOURCES
Summary information regarding prospective resources and net present value of future net revenues from prospective resources are set forth below and are derived, in each case, from the GLJ Resources Assessment. The GLJ Resources Assessment was prepared in accordance with COGEH and NI-51-101 by GLJ, an independent qualified reserve evaluator. All prospective resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2017. Prospective resources are in addition to reserves estimated in the GLJ Report.
A range of prospective resources estimates (low, best and high) were prepared by GLJ. See notes 6 to 8 of the tables below for a description of low estimate, best estimate and high estimate.
The GLJ Resources Assessment estimated gross risked prospective resources of 51.5 million boe (low estimate) to 260.4 million boe (high estimate), with a best estimate of 153.4 million boe.
An estimate of risked net present value of future net revenue of prospective resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes prospective resources that are considered too uncertain with respect to the chance of development and chance of discovery to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
Summary of Risked Oil and Gas Prospective Resources as at December 31, 2017(1)(2) - Forecast Prices and Costs(3)(4)
Resources |
Light Crude Oil & |
Conventional |
Coal Bed |
Natural Gas |
BOE |
Unrisked | ||||||||||||||||||||||||||||||||
Project |
||||||||||||||||||||||||||||||||||||||
Maturity |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Chance of |
Gross |
Net | |||||||||||||||||||||||||
Sub-Class |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
% (9) |
(Mboe) |
(Mboe) | |||||||||||||||||||||||||
Prospective - Low Estimate |
||||||||||||||||||||||||||||||||||||||
Prospect (10) |
||||||||||||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Canada |
185 |
168 |
66,480 |
61,570 |
— |
— |
4,522 |
3,982 |
15,787 |
14,412 |
34.0 |
% |
46,435 |
42,388 |
||||||||||||||||||||||||
France |
5,528 |
4,977 |
— |
— |
— |
— |
— |
— |
5,528 |
4,977 |
21.3 |
% |
25,904 |
23,366 |
||||||||||||||||||||||||
Germany |
— |
— |
136,066 |
116,769 |
— |
— |
— |
— |
22,678 |
19,462 |
29.0 |
% |
78,200 |
67,110 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Netherlands |
— |
— |
44,603 |
41,372 |
— |
— |
50 |
46 |
7,484 |
6,941 |
10.1 |
% |
73,823 |
68,723 |
||||||||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Total |
5,713 |
5,145 |
247,149 |
219,711 |
— |
— |
4,572 |
4,028 |
51,477 |
45,792 |
22.9 |
% |
224,362 |
201,587 |
||||||||||||||||||||||||
Prospective - Best Estimate |
||||||||||||||||||||||||||||||||||||||
Prospect (10) |
||||||||||||||||||||||||||||||||||||||
Australia (11) |
579 |
579 |
— |
— |
— |
— |
— |
— |
579 |
579 |
48.0 |
% |
1,206 |
1,206 |
||||||||||||||||||||||||
Canada (12) |
2,090 |
1,871 |
162,093 |
147,542 |
112,623 |
106,205 |
24,876 |
22,098 |
72,752 |
66,260 |
23.5 |
% |
309,610 |
281,957 |
||||||||||||||||||||||||
France (13) |
16,335 |
14,636 |
— |
— |
— |
— |
— |
— |
16,335 |
14,636 |
21.4 |
% |
76,358 |
68,393 |
||||||||||||||||||||||||
Germany (14) |
— |
— |
292,725 |
251,987 |
— |
— |
— |
— |
48,788 |
41,998 |
29.0 |
% |
168,235 |
144,821 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Netherlands (15) |
— |
— |
89,366 |
82,029 |
— |
— |
96 |
89 |
14,990 |
13,761 |
10.2 |
% |
147,256 |
134,912 |
||||||||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Total |
19,004 |
17,086 |
544,184 |
481,558 |
112,623 |
106,205 |
24,972 |
22,187 |
153,444 |
137,234 |
21.8 |
% |
702,665 |
631,289 |
||||||||||||||||||||||||
Prospective - High Estimate |
||||||||||||||||||||||||||||||||||||||
Prospect (10) |
||||||||||||||||||||||||||||||||||||||
Australia |
1,462 |
1,462 |
— |
— |
— |
— |
— |
— |
1,462 |
1,462 |
48.0 |
% |
3,046 |
3,046 |
||||||||||||||||||||||||
Canada |
2,684 |
2,383 |
231,682 |
209,203 |
147,282 |
136,241 |
38,134 |
32,553 |
103,979 |
92,510 |
23.8 |
% |
436,843 |
388,697 |
||||||||||||||||||||||||
France |
35,640 |
32,301 |
— |
— |
— |
— |
— |
— |
35,640 |
32,301 |
22.8 |
% |
156,320 |
141,671 |
||||||||||||||||||||||||
Germany |
— |
— |
554,429 |
479,424 |
— |
— |
— |
— |
92,405 |
79,904 |
29.0 |
% |
318,638 |
275,531 |
||||||||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Netherlands |
— |
— |
160,271 |
148,815 |
— |
— |
171 |
159 |
26,883 |
24,962 |
10.6 |
% |
252,881 |
235,491 |
||||||||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
||||||||||||||||||||||||||
Total |
39,786 |
36,146 |
946,382 |
837,442 |
147,282 |
136,241 |
38,305 |
32,712 |
260,369 |
231,139 |
22.3 |
% |
1,167,728 |
1,044,436 |
Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2017 - Forecast Prices and Costs(3)
Resources Project |
|||||||||||||||||||||||||||||
Maturity Sub-Class |
Before Income Taxes, Discounted at (5) |
After Income Taxes, Discounted at (5) | |||||||||||||||||||||||||||
(M$) |
0% |
5% |
10% |
15% |
20% |
0% |
5% |
10% |
15% |
20% | |||||||||||||||||||
Prospective (Pr1) -Low Estimate (6) |
|||||||||||||||||||||||||||||
Prospect (10) |
|||||||||||||||||||||||||||||
Australia |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Canada |
207,770 |
95,938 |
44,659 |
19,798 |
7,252 |
169,908 |
75,170 |
32,207 |
11,777 |
1,780 |
|||||||||||||||||||
France |
238,004 |
131,320 |
76,140 |
46,216 |
29,224 |
187,762 |
102,964 |
59,117 |
35,418 |
22,032 |
|||||||||||||||||||
Germany |
368,323 |
169,166 |
74,634 |
29,008 |
6,565 |
252,131 |
112,397 |
44,221 |
11,701 |
(3,782) |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands |
274,447 |
125,347 |
68,782 |
42,725 |
28,862 |
145,575 |
61,601 |
29,728 |
15,701 |
8,716 |
|||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Total |
1,088,544 |
521,771 |
264,215 |
137,747 |
71,903 |
755,376 |
352,132 |
165,273 |
74,597 |
28,746 |
|||||||||||||||||||
Prospective (Pr2) -Best Estimate (7) |
|||||||||||||||||||||||||||||
Prospect (10) |
|||||||||||||||||||||||||||||
Australia (11) |
41,338 |
23,669 |
14,015 |
8,555 |
5,365 |
16,344 |
8,905 |
4,999 |
2,884 |
1,705 |
|||||||||||||||||||
Canada (12) |
1,491,712 |
623,324 |
281,364 |
133,988 |
65,665 |
1,065,129 |
430,068 |
182,436 |
78,310 |
31,913 |
|||||||||||||||||||
France (13) |
722,008 |
401,287 |
237,931 |
149,181 |
98,046 |
533,938 |
289,739 |
167,209 |
101,849 |
64,935 |
|||||||||||||||||||
Germany (14) |
1,259,830 |
556,044 |
260,954 |
126,408 |
60,705 |
883,031 |
385,237 |
174,225 |
78,544 |
32,534 |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands (15) |
664,124 |
319,700 |
187,996 |
124,429 |
88,794 |
358,130 |
165,622 |
92,188 |
57,620 |
38,865 |
|||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Total |
4,179,012 |
1,924,024 |
982,260 |
542,561 |
318,575 |
2,856,572 |
1,279,571 |
621,057 |
319,207 |
169,952 |
|||||||||||||||||||
Prospect (10) |
|||||||||||||||||||||||||||||
Australia |
136,670 |
74,308 |
43,028 |
26,126 |
16,460 |
57,049 |
30,416 |
17,274 |
10,298 |
6,378 |
|||||||||||||||||||
Canada |
2,681,315 |
1,109,012 |
521,064 |
267,963 |
146,940 |
1,909,850 |
772,257 |
349,756 |
171,101 |
87,888 |
|||||||||||||||||||
France |
1,937,405 |
1,011,329 |
573,475 |
347,956 |
223,097 |
1,458,826 |
749,093 |
417,797 |
249,512 |
157,614 |
|||||||||||||||||||
Germany |
2,751,890 |
1,219,651 |
585,356 |
295,653 |
153,056 |
1,969,884 |
858,139 |
400,902 |
194,089 |
93,693 |
|||||||||||||||||||
Ireland |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Netherlands |
1,355,100 |
675,317 |
411,776 |
281,254 |
206,125 |
738,129 |
360,566 |
214,793 |
143,533 |
103,140 |
|||||||||||||||||||
USA |
— |
— |
— |
— |
— |
— |
— |
— |
— |
— |
|||||||||||||||||||
Total |
8,862,380 |
4,089,617 |
2,134,699 |
1,218,952 |
745,678 |
6,133,738 |
2,770,471 |
1,400,522 |
768,533 |
448,713 |
Notes:
(1) |
Prospective resources are defined in the COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects. Prospective resources have both an associated chance of discovery (CoDis) and a chance of development (CoDev). There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. The estimates of prospective resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated, as at a given date, and that the resources can be profitably produced in the future. The risked net present value of the future net revenue from the prospective resources does not represent the fair market value of the prospective resources. Actual prospective resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein. | |
(2) |
GLJ prepared the estimates of prospective resources shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. | |
(3) |
The forecast price and cost assumptions utilized in the year-end 2017 reserves report were also utilized by GLJ in preparing the GLJ Resource Assessment. See "GLJ December 31, 2017 Forecast Prices" in this AIF. | |
(4) |
"Gross" prospective resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net" prospective resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in prospective resources. | |
(5) |
The risked net present value of future net revenue attributable to the prospective resources does not represent the fair market value of the prospective resources. Estimated abandonment and reclamation costs have been included in the evaluation. | |
(6) |
This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. | |
(7) |
This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. | |
(8) |
This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. | |
(9) |
The chance of commerciality is defined as the product of the CoDis and the CoDev. CoDis is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. CoDev is defined as the estimated probability that, once discovered, a known accumulation will be commercially developed. | |
CoDev is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows: | ||
• |
Ps is the probability of success | |
• |
Economic Factor – For reserves to be assessed, a project must be economic. With respect to prospective resources, this factor captures uncertainty in the assessment of economic status principally due to uncertainty in cost estimates and marketing options. Economic viability uncertainty due to technology is more aptly captured with the Technology Factor. The Economic Factor will be 1 for reserves and will often be 1 for development pending and for projects with a development study or pre-development study with a robust rate of return. A robust rate of return means that the project retains economic status with variation in costs and/or marketing plans over the expected range of outcomes for these variables. | |
• |
Technology Factor - For reserves to be assessed, a project must utilize established technology. With respect to prospective resources, this factor captures the uncertainty in the viability of the proposed technology for the subject reservoir, namely, the uncertainty associated with technology under development. By definition, technology under development is a recovery process or process improvement that has been determined to be technically viable via field test and is being field tested further to determine its economic viability in the subject reservoir. The Technology Factor will be 1 for reserves and for established technology. For technology under development, this factor will consider different risks associated with technologies being developed at the scale of the well versus the scale of a project and technologies which are being modified or extended for the subject reservoir versus new emerging technologies which have not previously been applied in any commercial application. The risk assessment will also consider the quality and sufficiency of the test data available, the ability to reliably scale such data and the ability to extrapolate results in time. | |
• |
Development Plan Factor – For reserves to be assessed, a project must have a detailed development plan. With respect to prospective resources, this factor captures the uncertainty in the project evaluation scenario. The Development Plan Factor will be 1 for reserves and high, approaching 1, for development pending projects. This factor will consider development plan detail variations including the degree of delineation, reservoir specific development and operating strategy detail (technology decision, well layouts (spacing and pad locations), completion strategy, start-up strategy, water source and disposal, other infrastructure, facility design, marketing plans etc.) and the quality of the cost estimates as provided by the developer. | |
• |
Development Timeframe Factor – In the case of major projects, for reserves to be assessed, first major capital spending must be initiated within 5 years of the effective date. The Development Timeframe Factor will be 1 for reserves and will often be 1 for development pending provided the project is planned on-stream based on the same criteria used in the assessment of reserves. With respect to prospective resources, the factor will approach 1 for projects planned on-stream with a timeframe slightly longer than the limiting reserves criteria. | |
• |
Other Contingency Factor – For reserves to be assessed, all contingencies must be eliminated. With respect to prospective resources, this factor captures major contingencies, usually beyond the control of the operator, other than those captured by economic status, technology status, project evaluation scenario status and the development timeframe. The Other Contingency Factor will be 1 for reserves and for development pending and less than 1 for on hold. Provided all contingencies have been identified and their resolution is reasonably certain, this factor would also be 1 for development unclarified. | |
• |
These factors may be inter-related (dependent) and care has been taken to ensure that risks are appropriately accounted. | |
CoDis is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Five factors have been considered in determining the CoDis as follows: | ||
• |
CoDis = Ps (Source) × Ps (Timing and Migration) × Ps (Trap) ×Ps (Seal) × Ps (Reservoir) wherein | |
• |
Ps is the probability of success | |
• |
Source – For a significant accumulation of potentially recoverable petroleum, a viable source rock capable of generating hydrocarbons must exist. The probability of a source rock investigates stratigraphic presence and location, volumetric adequacy and organic richness of the proposed source rock. In proven hydrocarbon systems, this factor will be a 1. This factor becomes critical when looking at frontier basins. | |
• |
Timing and Migration - For a significant accumulation of potentially recoverable petroleum, the source rock must reach thermal maturity to generate the hydrocarbons and have a conduit with which to fill the closures that existed at the time of migration. The probability of timing and migration investigates the movement of hydrocarbons from the source rock to the trap. This factor evaluates the pathways and/or carrier beds, including fault systems, which can transport buoyant hydrocarbons from the source kitchen to the prospect area at a time that the trap existed. This factor is often 1 in producing trends, but there is a possibility of migration shadows where the conduits do not fill a viable trap, which would decrease this factor. | |
• |
Trap - For a significant accumulation of potentially recoverable petroleum, a reservoir must be present in a structural or stratigraphic closure. The trap factor looks at the definition of the geometry of the accumulation, which is determined using seismic, gravity and/or magnetic techniques and surrounding well logs to determine the probability of a significant accumulation. The risking of this includes examining data quality (e.g. 2D vs 3D seismic coverage) and potential depth conversion possibilities which give confidence in the mapped trap. Stratigraphic trap definition is used for volumetric calculations, but it is given a 1 for this chance factor as the stratigraphic risk will be captured in seal. | |
• |
Seal - For a significant accumulation of potentially recoverable petroleum, a reservoir must be sealed both on the top and laterally by a lithology that contains the hydrocarbon accumulation within the reservoir. It is also necessary that these accumulated hydrocarbons have been preserved from flushing or leakage. Factors that affect top, seat and lateral seals are fluid viscosity, bed thickness, natural continuity of sealing facies, differential permeability, fault history and reservoir pressures needed to maintain a hydrocarbon column. The probability that the accumulation is not able to be contained by the surrounding rocks is captured in this chance factor. | |
• |
Reservoir - For a significant accumulation of potentially recoverable petroleum, a reservoir rock must be present and have sufficient porosity and permeability and be of a sufficient thickness to produce quantities of mobile hydrocarbon. Under this approach, encountering wet, commercial quality and quantity sandstones would not be a failure in the reservoir category, but rather in one of the other factors. It is the reservoir along with the trap which determine the volumetrics of the accumulation. | |
• |
Serial multiplication of these five decimal fractions representing the five geologic chance factors can be done as they are considered independent of each other. | |
(10) |
GLJ has sub-classified the best estimate prospective resources by maturity status, consistent with the requirements of the COGE Handbook. These prospective resources have been sub-classified as "Prospect" which the COGE Handbook defines as a potential accumulation within a play that is sufficiently well defined to present a viable drilling target. | |
(11) |
Prospective resources for Australia have been estimated based on development timing and reservoir risk, GLJ has estimated the CoDev at 80% and the CoDis at 60%. The corresponding chance of commerciality is 48%. Risked best estimate prospective resources have been estimated at .06 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is $17 MM. The expected development timeline is 8 years. | |
(12) |
Prospective resources for Canada have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 27% and the aggregate CoDis at 88%. The corresponding chance of commerciality is 23%. Risked best estimate prospective resources have been estimated at an aggregate of 72.8 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $1061 MM. The expected development timeline is 2 to 20 years. | |
Edson Duvernay |
Based on reservoir risk, development timing and economic risk related to capital and operating cost uncertainty, GLJ has estimated the CoDev at 19% and the CoDis at 90%. The corresponding chance of commerciality is 17%. Risked best estimate prospective resources have been estimated at 33.6 mmboe and the risked estimated cost to bring these resources on commercial production is $638 MM with an expected timeline of 7 to 14 years. | |
Wilrich Prospect: |
Based on reservoir risk, development timing and limited Wilrich development on the land base, GLJ has estimated the CoDev at 35% and the CoDis at 85%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 22.2 mmboe and the risked estimated cost to bring these resources on commercial production is $218 MM with an expected timeline of 2 to 9 years. | |
West Pembina Glauconite Prospect: |
Based on chance of discovery risk due to uncertainty regarding threshold for reservoir quality to support commercial development of resources with horizontal drilling, along with economic risk related to capital and operating cost uncertainty due to limited horizontal development in proximity to interest lands and chance of development risk related to corporate commitment and development timing. GLJ has estimated the CoDev at 34% and the CoDis at 90%. The corresponding chance of commerciality is 31%. Risked best estimate prospective resources have been estimated at 6.2 mmboe and the risked estimated cost to bring these resources on commercial production is $53 MM with an expected timeline of 6 to 12 years. | |
Drayton Valley Notikewin Prospect: |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 85%. The corresponding chance of commerciality is 60%. Risked best estimate prospective resources have been estimated at 4.6 mmboe and the risked estimated cost to bring these resources on commercial production is $66 MM. The expected development timeline is 9 to 11 years. | |
Saskatchewan Prospects |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 90% and the CoDis at 80%. The corresponding chance of commerciality is 72%. Risked best estimate prospective resources have been estimated at 3.3 mmboe and the risked estimated cost to bring these resources on commercial production is $60 MM with an expected timeline of 7 to 11 years. | |
Ferrier Falher Prospect |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 90%. The corresponding chance of commerciality is 54%. Risked best estimate prospective resources have been estimated at 2.7 mmboe and the risked estimated cost to bring these resources on commercial production is $23 MM with an expected timeline of 15 to 20 years. | |
Utikuma Gilwood Prospect |
Based on reservoir risk, development timing and limited Gilwood development in the area, GLJ has estimated the CoDev at 60% and the CoDis at 50%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 0.2 mmboe and the risked estimated cost to bring these resources on commercial production is $3 MM with an expected timeline of 3 to 9 years. | |
(13) |
Prospective resources for France have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 74% and the aggregate CoDis at 28%. The corresponding chance of commerciality is 21%. Risked best estimate prospective resources have been estimated at an aggregate of 16.3. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $380 MM. The expected development timeline is 1 to 13 years. | |
Seebach Prospect |
Based on risks associated with seal, trap, reservoir and charge along with development timing, GLJ has estimated the CoDev at 75% and the CoDis at 18%. The corresponding chance of commerciality is 14%. | |
Risked best estimate prospective resources have been estimated at 7.8 mmboe and the risked estimated cost to bring these resources on commercial production is $40 MM with an expected timeline of 5 to 7 years. | ||
Rachee Prospect |
Based on risk of closure and data quality along with development timing, GLJ has estimated the CoDev at 80% and the CoDis at 80%. The corresponding chance of commerciality is 64%. Risked best estimate prospective resources have been estimated at 3.4 mmboe and the risked estimated cost to bring these resources on commercial production is $233 MM with an expected timeline of 9 to 13 years. | |
Malnoue Prospect |
Based on reservoir, structure and trap risk along with development timing, GLJ has estimated the CoDev at 70% and the CoDis at 38%. The corresponding chance of commerciality is 27%. Risked best estimate prospective resources have been estimated at 1.4 mmboe and the risked estimated cost to bring these resources on commercial production is $35 MM with an expected timeline of 8 to 12 years. | |
West Lavergne Prospect |
Based on structure risk and development timing GLJ has estimated the CoDev at 80% and the CoDis at 70%. The corresponding chance of commerciality is 56%. Risked best estimate prospective resources have been estimated at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $7 MM with an expected timeline of 4 years. | |
Champotran Prospect |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 80% and the CoDis at 67%. The corresponding chance of commerciality is 54%. Risked best estimate prospective resources have been estimated at 0.9 mmboe and the risked estimated cost to bring these resources on commercial production is $21 MM with an expected timeline of 1 to 11 years. | |
Vulaines Prospect |
Based on reservoir and structure risk along with development timing, GLJ has estimated the CoDev at 80% and the CoDis at 40%. The corresponding chance of commerciality is 32%. Risked best estimate prospective resources have been estimated at 0.6 mmboe and the risked estimated cost to bring these resources on commercial production is $14 MM with an expected timeline of 7 to 9 years. | |
Charmottes Prospect |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 50%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 0.5 mmboe and the risked estimated cost to bring these resources on commercial production is $19 MM with an expected timeline of 10 to 12 years. | |
Bernet Prospect |
Based on risks associated with reservoir, seal and trap along with economic factors, and development timing, GLJ has estimated the CoDev at 50% and the CoDis at 65%. The corresponding chance of commerciality is 33%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $7 MM with an expected timeline of 4 to 5 years. | |
Vert Le Grand Prospect |
Based on reservoir and structure risk along with development timing, GLJ has estimated the CoDev at 70% and the CoDis at 28%. The corresponding chance of commerciality is 20%. Risked best estimate prospective resources have been estimated at 0.2 mmboe and the risked estimated cost to bring these resources on commercial production is $4 MM with an expected timeline of 4 to 5 years. | |
Les Genets Prospect |
Based on reservoir, seal and closure risk, along with economic factors and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 16%. The corresponding chance of commerciality is 10%. Risked best estimate prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $1 MM with an expected timeline of 8 years. | |
North Acacias Prospect |
Based on reservoir, seal and trap risk, along with economic factors and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 39%. The corresponding chance of commerciality is 27%. Risked best estimate prospective resources have been estimated at 0.07 mmboe and the risked estimated cost to bring these resources on commercial production is $1 MM with an expected timeline of 4 to 5 years. | |
(14) |
Prospective resources for Germany have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 70% and the aggregate CoDis at 42%. The corresponding chance of commerciality is 29%. Risked best estimate prospective resources have been estimated at an aggregate of 48.8 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of 313.4 MM. The expected development timeline is 1 to 13 years. | |
Wisselshorst A Prospect |
Based on seal and trap risk along with development timing , GLJ has estimated the CoDev at 90%, and the CoDisc at 58%. The corresponding chance of commerciality is 52%. Risked Best Estimate Prospective resources have been estimated at 13.5 mmboe and the risked estimated cost to bring these resources on commercial production is $85.5MM with an expected timeline of 2 to 9 years. | |
Ihlow Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 71%, and the CoDisc at 51%. The corresponding chance of commerciality is 36%. Risked Best Estimate Prospective resources have been estimated at 6.6 mmboe and the risked estimated cost to bring these resources on commercial production is $46.6MM with an expected timeline of 5 to 7 years. | |
Wisselshorst B Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 90%, and the CoDisc at 50%. The corresponding chance of commerciality is 45%. Risked Best Estimate Prospective resources have been estimated at 5.5 mmboe and the risked estimated cost to bring these resources on commercial production is $42.7MM with an expected timeline of 5 to 12 years. | |
Weissenmoor South |
Based on reservoir and trap risk along with development timing, GLJ has estimated the CoDev at 90%, and the CoDisc at 36%. The corresponding chance of commerciality is 32%. Risked Best Estimate Prospective resources have been estimated at 4.2 mmboe and the risked estimated cost to bring these resources on commercial production is $15.9MM with an expected timeline of 3 to 8 years. | |
Simonswolde South Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 71%, and the CoDisc at 48%. The corresponding chance of commerciality is 34%. Risked Best Estimate Prospective resources have been estimated at 4.1 mmboe and the risked estimated cost to bring these resources on commercial production is $16MM with an expected timeline of 8 to 9 years. | |
Fallingbostel |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 90%, and the CoDisc at 29%. The corresponding chance of commerciality is 26%. Risked Best Estimate Prospective resources have been estimated at 3.4 mmboe and the risked estimated cost to bring these resources on commercial production is $29.5MM with an expected timeline of 3 to 9 years. | |
Hellwege |
Based on reservoir and trap risk along with development timing, GLJ has estimated the CoDev at 90%, and the CoDisc at 40%. The corresponding chance of commerciality is 36%. Risked Best Estimate Prospective resources have been estimated at 2.9 mmboe and the risked estimated cost to bring these resources on commercial production is $16.1MM with an expected timeline of 3 to 8 years. | |
Jeddeloh Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 38%, and the CoDisc at 32%. The corresponding chance of commerciality is 12%. Risked Best Estimate Prospective resources have been estimated at 2.9 mmboe and the risked estimated cost to bring these resources on commercial production is $23.1MM with an expected timeline of 3 to 12 years. | |
Ohlendorf Prospect |
Based on source and trap risk along with development timing, GLJ has estimated the CoDev at 58%, and the CoDisc at 30%. The corresponding chance of commerciality is 17%. Risked Best Estimate Prospective resources have been estimated at 2.4 mmboe and the risked estimated cost to bring these resources on commercial production is $11.1MM with an expected timeline of 9 to 13 years. | |
Uphuser Meer Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 47%, and the CoDisc at 51%. The corresponding chance of commerciality is 24%. Risked Best Estimate Prospective resources have been estimated at 1.7 mmboe and the risked estimated cost to bring these resources on commercial production is $8.3MM with an expected timeline of 6 to 7 years. | |
Simonswolde North Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 62%, and the CoDisc at 45%. The corresponding chance of commerciality is 28%. Risked Best Estimate Prospective resources have been estimated at 1.4 mmboe and the risked estimated cost to bring these resources on commercial production is $6.1MM with an expected timeline of 6 to 7 years. | |
Burgmoor Z5 Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 63%, and the CoDisc at 52%. The corresponding chance of commerciality is 33%. Risked Best Estimate Prospective resources have been estimated at 0.7mmboe and the risked estimated cost to bring these resources on commercial production is $1.1MM with an expected timeline of 1 year. | |
Widdernhausen East Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 32%, and the CoDisc at 44%. The corresponding chance of commerciality is 14%. Risked Best Estimate Prospective resources have been estimated at 0.4 mmboe and the risked estimated cost to bring these resources on commercial production is $2.7MM with an expected timeline of 7 to 12 years. | |
Wellie Prospect |
Based on reservoir, seal and source risk along with development timing, GLJ has estimated the CoDev at 32%, and the CoDisc at 20%. The corresponding chance of commerciality is 6%. Risked Best Estimate Prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $3.3MM with an expected timeline of 10 years. | |
Otterstedt Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 46%, and the CoDisc at 34%. The corresponding chance of commerciality is 16%. Risked Best Estimate Prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $3.5MM with an expected timeline of 8 to 13 years. | |
Ostervesede Prospect |
Based on reservoir and seal risk along with development timing, GLJ has estimated the CoDev at 23%, and the CoDisc at 25%. The corresponding chance of commerciality is 6%. Risked Best Estimate Prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $0.7MM with an expected timeline of 7 to 10 years. |
(15) |
Prospective resources for Netherlands have been estimated based on the factors outlined below. GLJ has estimated the aggregate CoDev at 28% and the aggregate CoDis at 39%. The corresponding chance of commerciality is 11%. Risked best estimate prospective resources have been estimated at an aggregate of 15.0 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of 127 MM with an expected timeline of 2 to 15 years. | |
Prospective resources for Netherlands East have been estimated based on the individual areas outlined below. GLJ has estimated the aggregate CoDev at 25% and the aggregate CoDis at 41%. The corresponding chance of commerciality is 10%. Risked best estimate prospective resources have been estimated at an aggregate of 12.1 mmboe and the risked estimated cost to bring these resources on commercial production is an aggregate of 83 MM with an expected timeline of 2 to 15 years. | ||
• |
Chance of discovery provided for 109 prospective reservoir targets across 91 prospective locations. Risk primarily associated with presence of reservoir and seal as region proven to have adequate source, migration and timing to charge target reservoirs. | |
• |
Chance of development risked to account for company commitment and development timing, anticipated timing for permitting in respective licenses and distance to export (i.e. pipeline/facility requirements to transport gas to sales point). Chance of development is also a function of prospect size. | |
• |
65 prospects summed probabilistically across 13 development groups to appropriately allocate required infrastructure capital across multiple prospective targets within reasonable proximity. As probabilistic summation of the groups resulted in strong economic indicators, no further minimum economic field size calculations were applied as they were considered to have nominal impact. | |
Prospective resources for Netherlands West have been estimated based on the factors outlined below. GLJ has estimated the aggregate CoDev at 41% and the aggregate CoDis at 28%. The corresponding chance of commerciality is 12%. Risked best estimate prospective resources have been estimated at an aggregate of 2.9 mmboe and the risked estimated cost to bring these resources on commercial production is an aggregate of$ 43 MM with an expected timeline of 2 to 12 years. | ||
• |
Chance of discovery provided for 25 prospective reservoir targets across 21 prospective locations. Risk primarily associated with presence of reservoir and seal as region proven to have adequate source, migration and timing to charge target reservoirs. | |
• |
Chance of development risked to account for company commitment and development timing, anticipated timing for permitting in respective licenses and distance to export (i.e. pipeline/facility requirements to transport gas to sales point). Chance of development is also a function of prospect size. | |
• |
17 prospects summed probabilistically across 5 development groups to appropriately allocate required infrastructure capital across multiple prospective targets within reasonable proximity. As probabilistic summation of the groups resulted in strong economic indicators no further minimum economic field size calculations were applied as they were considered to have nominal impact. |
ABOUT VERMILION
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion currently pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel equivalent of oil. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Netbacks and Operating Recycle Ratio are measures that do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculations of similar measures for other entities. "Operating Recycle Ratio" is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). "Netbacks" are per boe and per Mcf measures used in operational and capital allocation decisions. "Operating Netback" is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. Management assesses Operating Netback as a measure of the profitability and efficiency of our field operations. F&D (finding and development) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital, by the change in the reserves, incorporating revisions and production, for the same period.
SOURCE Vermilion Energy Inc.
CALGARY, March 1, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and audited financial results for the three months and year ended December 31, 2017.
The audited financial statements and management discussion and analysis for the three months and year ended December 31, 2017, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
HIGHLIGHTS
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Mh-Ny-07 well tested gas at a rate of 5.8 mmcf/d over the final two hours of a 22 hour test period at a stabilized wellhead pressure of 1,065 psi on a 0.55 inch diameter choke and a shut-in wellhead pressure of 1,305 psi. No water production was observed during testing. The well logged 21 feet of net gas pay with an average porosity of 31% from an Upper Miocene Pannonian sandstone occurring within a gross measured depth interval of 3,438-3,465 feet. |
(3) |
Estimated proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2018 with an effective date of December 31, 2017 (the "2017 GLJ Reserves Evaluation") |
(4) |
F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period. |
(5) |
Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(6) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2018 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2017 (the "GLJ 2017 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 56%, 46% and 47%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
HIGHLIGHTS
Three Months Ended |
Year Ended | ||||||||||
($M except as indicated) |
Dec 31, 2017 |
Sep 30, 2017 |
Dec 31, 2016 |
Dec 31, 2017 |
Dec 31, 2016 | ||||||
Financial |
|||||||||||
Petroleum and natural gas sales |
317,341 |
248,505 |
259,891 |
1,098,838 |
882,791 | ||||||
Fund flows from operations |
181,253 |
130,755 |
149,582 |
602,565 |
510,791 | ||||||
Fund flows from operations ($/basic share) (1) |
1.49 |
1.08 |
1.27 |
5.00 |
4.41 | ||||||
Fund flows from operations ($/diluted share) (1) |
1.47 |
1.07 |
1.25 |
4.92 |
4.36 | ||||||
Net (loss) earnings |
8,645 |
(39,191) |
(4,032) |
62,258 |
(160,051) | ||||||
Net (loss) earnings ($/basic share) |
0.07 |
(0.32) |
(0.03) |
0.52 |
(1.38) | ||||||
Capital expenditures |
74,303 |
91,382 |
66,882 |
320,449 |
242,408 | ||||||
Acquisitions |
3,048 |
20,976 |
78,713 |
27,637 |
98,524 | ||||||
Asset retirement obligations settled |
3,216 |
1,749 |
3,327 |
9,334 |
9,617 | ||||||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 |
2.580 |
2.580 | ||||||
Dividends declared |
78,653 |
78,293 |
76,096 |
311,397 |
299,070 | ||||||
% of fund flows from operations |
43% |
60% |
51% |
52% |
59% | ||||||
Net dividends (1) |
56,836 |
54,364 |
32,516 |
200,904 |
106,072 | ||||||
% of fund flows from operations |
31% |
42% |
22% |
33% |
21% | ||||||
Payout (1) |
134,355 |
147,495 |
102,725 |
530,687 |
358,097 | ||||||
% of fund flows from operations |
74% |
113% |
69% |
88% |
70% | ||||||
Net debt |
1,371,790 |
1,370,995 |
1,427,148 |
1,371,790 |
1,427,148 | ||||||
Ratio of net debt to annualized fund flows from operations |
1.9 |
2.6 |
2.4 |
2.3 |
2.8 | ||||||
Operational |
|||||||||||
Production |
|||||||||||
Crude oil and condensate (bbls/d) |
27,830 |
27,687 |
25,972 |
27,721 |
27,852 | ||||||
NGLs (bbls/d) |
5,279 |
4,947 |
2,467 |
4,194 |
2,582 | ||||||
Natural gas (mmcf/d) |
238.27 |
208.63 |
194.54 |
216.64 |
198.55 | ||||||
Total (boe/d) |
72,821 |
67,403 |
60,863 |
68,021 |
63,526 | ||||||
Average realized prices |
|||||||||||
Crude oil and condensate ($/bbl) |
74.12 |
61.47 |
64.51 |
67.00 |
55.42 | ||||||
NGLs ($/bbl) |
29.28 |
23.96 |
18.13 |
25.00 |
11.70 | ||||||
Natural gas ($/mcf) |
5.23 |
4.01 |
5.47 |
4.91 |
4.18 | ||||||
Production mix (% of production) |
|||||||||||
% priced with reference to WTI |
21% |
22% |
18% |
20% |
19% | ||||||
% priced with reference to AECO |
25% |
26% |
20% |
25% |
22% | ||||||
% priced with reference to TTF and NBP |
30% |
26% |
33% |
29% |
30% | ||||||
% priced with reference to Dated Brent |
24% |
26% |
29% |
26% |
29% | ||||||
Netbacks ($/boe) |
|||||||||||
Operating netback (1) |
30.77 |
26.06 |
31.11 |
29.24 |
27.06 | ||||||
Fund flows from operations netback |
27.13 |
20.87 |
26.43 |
24.34 |
21.91 | ||||||
Operating expenses |
9.76 |
9.87 |
10.54 |
9.79 |
9.53 | ||||||
Average reference prices |
|||||||||||
WTI (US $/bbl) |
55.40 |
48.20 |
49.29 |
50.95 |
43.32 | ||||||
Edmonton Sweet index (US $/bbl) |
54.26 |
45.32 |
46.18 |
48.49 |
40.11 | ||||||
Dated Brent (US $/bbl) |
61.39 |
52.08 |
49.46 |
54.27 |
43.69 | ||||||
AECO ($/mmbtu) |
1.69 |
1.45 |
3.09 |
2.16 |
2.16 | ||||||
NBP ($/mmbtu) |
8.70 |
6.78 |
7.51 |
7.49 |
6.15 | ||||||
TTF ($/mmbtu) |
8.36 |
6.93 |
7.21 |
7.43 |
6.00 | ||||||
Average foreign currency exchange rates |
|||||||||||
CDN $/US $ |
1.27 |
1.25 |
1.33 |
1.30 |
1.33 | ||||||
CDN $/Euro |
1.50 |
1.47 |
1.44 |
1.46 |
1.47 | ||||||
Share information ('000s) |
|||||||||||
Shares outstanding - basic |
122,119 |
121,585 |
118,263 |
122,119 |
118,263 | ||||||
Shares outstanding - diluted (1) |
125,140 |
124,453 |
121,353 |
125,140 |
121,353 | ||||||
Weighted average shares outstanding - basic |
121,858 |
121,280 |
117,840 |
120,582 |
115,695 | ||||||
Weighted average shares outstanding - diluted (1) |
123,450 |
122,485 |
119,677 |
122,408 |
117,152 |
(1) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
MESSAGE TO SHAREHOLDERS
We delivered 7% annual production growth in 2017, coming in at the lower end of our revised guidance range of 68,000 - 69,000 boe/d. Production growth in Canada, the US, Ireland and Germany more than offset lower production in France, Netherlands and Australia. Permitting delays significantly reduced Netherlands production volumes in 2017, while an unplanned 31-day downtime period at Corrib late in Q3 2017 reduced annual corporate production by approximately 900 boe/d. Production at Corrib resumed on October 11th, while Netherlands production recovered to near record levels during the fourth quarter following the receipt of permits on several pools.
Despite the unplanned downtime at Corrib and the permitting delays in the Netherlands, we achieved our broader corporate goal of delivering self-funded growth and income to shareholders. We delivered this in a commodity price environment with WTI oil prices ranging from the low US$40's to a high of US$60/bbl at the end of the year, and AECO gas prices ranging from over $3/mcf at the beginning of the year to negative daily prices on several occasions over the summer months. Even with this volatility, fund flows from operations ("FFO") increased 18% year-over-year to $603 million in 2017, and free cash flow(1) (FCF) was up 5% year-over-year to $282 million. This FCF was more than sufficient to fund our dividend while enabling further debt reduction. As a result of this strong FFO and FCF profile, we achieved a total payout ratio(1) of 88% in 2017 and reduced our trailing net debt-to-FFO ratio to 2.3x in 2017, or 1.9x based on Q4 2017 annualized FFO, as compared to a trailing ratio of 2.8x in 2016.
Global commodity prices have recovered in recent months with underlying fundamentals stronger than they have been in a long time. Global oil supply and demand levels are moving back into a more balanced position, while European gas prices remain strong. Unfortunately, western Canadian natural gas and heavy oil prices continue to be pressured due to various egress issues, resulting in steeply discounted pricing relative to global prices. Fortunately for Vermilion, we do not have any exposure to Canadian heavy oil. The majority of our production of both oil and gas comes from outside of North America and benefits from higher global prices. Based on our current 2018 guidance, we project that 60% of our total oil production is referenced to Brent, while 57% of our total natural gas production is price referenced to European price benchmarks.
We are pleased to announce that our Board of Directors has approved a 7% increase to the monthly dividend to $0.23 per share from $0.215 per share, effective with the April 2018 dividend to be paid on May 15, 2018. This represents our fourth dividend increase since initiating a monthly dividend in 2003. We remain focused on and committed to our self-funded growth and income model. Based on the midpoint of our 2018 guidance, we are targeting 11% year-over-year production growth, or 8% on a per-share basis, which would translate to significant FFO and FCF growth based on the current commodity strip. FCF growth is our ultimate goal as we believe this is the true measure of value creation for any business. At current strip prices, we expect to fully fund our 2018 exploration and development ("E&D") capital expenditures and cash dividends from fund flows from operations.
Q4 2017 Review
Vermilion's Q4 2017 production increased 8% from the prior quarter to an average of 72,821 boe/d. This increase was primarily driven by continued growth in Canada and the Netherlands, and the resumption of operations at the Corrib plant in Ireland following unplanned downtime in late Q3 and early Q4 2017. Q4 2017 production growth was partially restrained by cold weather impacts in Canada, a force majeure event on a third-party gas gathering system in our Turner Sands play in Wyoming, and minor maintenance activities in Germany and Australia.
Fund flows from operations in Q4 2017 was $181 million ($1.49/basic share(1)), representing an increase of 38% from the previous quarter as a result of higher sales volumes and commodity pricing. FFO was more than sufficient to cover our Q4 2017 capital expenditures of $74 million and cash dividends of $57 million, resulting in a payout ratio of 74% (including Asset Retirement Obligations Settled) and surplus cash of approximately $50 million during the quarter.
Europe
Production in the Netherlands increased to 9,381 boe/d in Q4 2017, following the amendment of permit restrictions on two key pools and an inline test on the Eesveen-02 well drilled in the prior quarter. This represents a 59% increase over the prior quarter. The test rate from the Eesveen-2 well (60% working interest) was limited to approximately 10 mmcf/d net during the test period. In addition to the strong production performance, we also completed a 315 square kilometre 3D seismic survey in the Akkrum exploration licence and the South Friesland III production licence, our first new data acquisition since entering the Netherlands in 2004.
In France, Q4 2017 production averaged 11,215 boe/d, an increase of 3% from the prior quarter. The increase was primarily due to better well uptime compared to the prior period and ongoing well optimization. Activity during Q4 2017 was focused on well workovers and preparing for our 2018 drilling campaign. We accelerated part of our 2018 program, commencing the drilling on two (2.0 net) of the four (4.0 net) planned Neocomian wells. All remaining Neocomian wells are expected to be drilled in Q1 2018, along with the drilling of our planned three (3.0 net) Champotran wells. In December 2017, the French parliament approved the proposed Climate Plan which prohibits the issuance of new oil and gas exploration concessions and limiting the renewal of existing production concessions beyond 2040. Upon review of the final details included in the new legislation, we conclude that we do not expect these new laws to have a material impact on our future production profile.
In Ireland, production from Corrib averaged 56 mmcf/d (9,372 boe/d) in Q4 2017, a 15% increase from Q3 2017. As reported in our Q3 2017 release, Corrib had an unplanned 31-day downtime period following a plant turnaround during September and October 2017. This downtime reduced Vermilion's Q4 2017 production by approximately 1,200 boe/d and annual production by approximately 900 boe/d. We continue to work closely with Canada Pension Plan Investment Board ("CPPIB") and Shell on the transition of ownership and operations from Shell to CPPIB and Vermilion, and anticipate closing the transaction in the first half of 2018.
In Germany, production in Q4 2017 averaged 4,180 boe/d, a decrease of 5% from the previous quarter. The decrease was primarily due to a temporary shut-in of one well in December for a SCADA installation. The well is expected to be brought back on production in Q1 2018. Our activity in Germany continues to focus on well workover and optimization projects on our operated assets and planning activities related to the Burgmoor Z5 well to be drilled in early 2019.
In Hungary, we were awarded a license in December 2017 for the Békéssámson concession for a 4-year term. Located adjacent to our existing South Battonya concession in southeast Hungary, the Békéssámson concession covers 330,700 net acres (100% working interest) and more than doubles the size of our total land position in the country. Subsequent to year-end, we drilled and tested our first exploratory well (100% working interest) in the South Battonya concession. The Mh-Ny-07 natural gas well tested at a rate of 5.8 mmcf/d(2) and is expected to be brought on production mid-2018. This marks the drilling of our first well in the Central and Eastern Europe Business Unit.
North America
In Canada, we drilled or participated in six (4.0 net) Mannville wells in Q4 2017, successfully concluding our 2017 program. Production averaged 32,923 boe/d in Q4 2017, representing a 5% increase from the previous quarter and another quarterly record for the business unit. Subsequent to the end of the year, we announced and closed an acquisition of a private southeast Saskatchewan producer. The acquisition added over 1,000 bbl/d of high netback 40° API oil and 42,600 net acres of land straddling the Saskatchewan and Manitoba border, near Vermilion's existing operations in southeast Saskatchewan. Total consideration of $90.8 million, which includes both cash paid to the shareholders of the acquired company and the assumption of long-term debt, was funded through our revolving credit facility. The acquisition resulted in an increase to our 2018 capital guidance to $325 million (from $315 million previously), along with a corresponding increase to our full-year 2018 production guidance to a range of between 75,000 - 77,500 boe/d (from 74,500 - 76,500 boe/d previously). The acquisition closed on February 15th.
In the United States, Q4 2017 production averaged 758 boe/d, a decrease of 27% from the prior quarter in part due to a force majeure event on a third-party gas gathering system, which is returned to service mid-Q1 2018. Capital activity in Q4 2017 was focused on the construction of three well pads in preparation for our five (5.0 net) well 2018 drilling program. One of these well pads was built for the Initial Obligation Well in the 25,500 acre Rex Unit in the northern region of the East Finn Project, which was approved by the Bureau of Land Management in October 2017.
Australia
In Australia, Q4 2017 production averaged 4,993 bbl/d, a 9% decrease quarter-over-quarter, primarily due to planned maintenance during the quarter which resulted in eight days of downtime. We continue to focus on maintenance and debottlenecking activities and planning for our 2019 drilling campaign, which we expect will restore production volumes to our targeted level of approximately 6,000 bbl/d.
Environmental, Social and Governance ("ESG")
In February 2018, Vermilion received the Finance and Sustainability Initiative's ("FSI") award for Best Sustainability Report in the Non-Renewable Resources - Oil and Gas category for 2018, relating to our 2016 Sustainability Report. Based in Montreal, the FSI is a non-profit organization dedicated to promoting sustainable finance and, more specifically, responsible investment to financial institutions, companies, and universities. Sustainability reports were graded on a number of criteria, including transparency and balance, reliability and completeness, and the use of ESG materiality. We firmly believe in the importance of measuring and understanding our current environmental impact. Furthermore, we believe the integration of sustainability principles into our business strategy increases shareholder returns and reduces long-term risks to our business model. Our 2017 Sustainability Report is available on our corporate website at: http://sustainability.vermilionenergy.com. In addition, Vermilion ranked fourth within the oil and gas sector, and among the top quartile of companies in the S&P/TSX Composite Index in the Globe and Mail Board Games for 2017. Both of these external recognition's reflects Vermilion's strong corporate culture and staff engagement in ESG.
2017 Reserves and Resources
We continued to grow our reserves and resources in 2017. Based on an independent report by GLJ as at December 31, 2017, our 1P reserves increased modestly to 176.6(3) mmboe in 2017, while 2P reserves increased 3% to 298.5(3) mmboe. Proved developed producing ("PDP") reserves increased 1.3% to 123.8 mmboe at an average F&D cost (including FDC) of $12.41/boe resulting in a PDP Operating Recycle Ratio(4) (including FDC) of 2.4x. Our PDP reserves represent 70% of 1P reserves. We replaced 103% and 134% of production at the 1P and 2P levels respectively in 2017.
Our operating recycle ratio(4) (including FDC) decreased to 2.8x in 2017, compared to 4.9x in 2016 and 3.6x in 2015, with F&D cost (including FDC) increasing to $10.57/boe in 2017. The largest driver of the increase in F&D cost was the strengthening of the Euro relative to the Canadian dollar in GLJ's foreign exchange rate forecast as compared to the previous year, which increased FDC for our European properties. Despite the increase in reported F&D costs and the reduced recycle ratio as compared to 2016, these metrics remain strong relative to the oil and gas sector, and reflect the significant improvement in capital efficiencies we have achieved over the last several years.
In addition to growing our reserve base, we pursued various initiatives to expand our resource base to support our longer-term growth profile. According to the independent report by GLJ as at December 31, 2017, our 2017 Resource Assessment(4) indicates risked low, best, and high estimates for contingent resources in the Development Pending category of 107.3(5) mmboe, 176.7(5) mmboe, and 253.6(5) mmboe, respectively. The GLJ 2017 Resource Assessment also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 7.5(5) mmboe, 32.8(5) mmboe, and 46.1(5) mmboe. Over 80% of our risked contingent resources reside in the Development Pending category, reflecting the high quality nature of our contingent resource base. Prospective resources were assessed at risked low, best and high estimates of 51.5(5) mmboe, 153.4(5) mmboe, and 231.1(5) mmboe. Our contingent and prospective resource bases remain a source of reserve additions, with 20.5 mmboe of contingent resources and 1.7 mmboe of prospective resources converted to 2P reserves during 2017.
Additional information about our 2017 GLJ Reserves Evaluation and GLJ 2017 Resource Assessment can be found in our Annual Information Form and 2017 Year-end Summary Reserves and Resources news release on our website at www.vermilionenergy.com.
Outlook
In October 2017, we announced a 2018 capital budget of $315 million with corresponding production guidance of 74,500 to 76,500 boe/d. In conjunction with our acquisition of a private southeast Saskatchewan light oil producer, we increased our 2018 capital budget to $325 million and increased our full-year production guidance to a range of 75,000 to 77,500 boe/d. Our budget funds the development of a number of high-return projects, including investment in all three key condensate and light oil projects in Canada, continued development in both the Neocomian and Champotran fields in France, a return to production growth in the Netherlands where we continue to benefit from favourably-priced European natural gas, continued development of our Turner Sands play in the United States, and inaugural drilling in our CEE business unit in the South Battonya license in Hungary.
At current strip prices, Vermilion expects to fully fund 2018 exploration and development ("E&D") capital expenditures and cash dividends from fund flows from operations, representing the third consecutive year of delivering per share production growth at a payout ratio of less than 100%. Any surplus of cash generated will be initially directed to debt reduction.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of cash flows, providing additional certainty with regards to the execution of our dividend and capital programs. In aggregate, we currently have 43% of our expected net-of-royalty production hedged for 2018. Our diversified commodity mix, including more than a one-third cash flow contribution from relatively high-priced European natural gas, gives us unusual flexibility in managing our individual commodity exposures. Based on the current level and term structures in the oil, North American gas and European gas forward curves, we have elected to lock down a greater percentage of our gas exposures, particularly for European gas. We have currently hedged 54% of anticipated European natural gas volumes for 2018. In view of the compelling longer-term forward market for European gas we have also hedged 41% and 16% of our anticipated 2019 and 2020 volumes at prices which provide for strong project economics and free cash flows. In addition, we have hedged 39% of anticipated North American gas volumes for 2018. In view of steep backwardation in the oil forward markets, we are keeping oil hedges shorter-term, with 50% hedged for the first half of 2018, and 27% in the second half of this year. At present, our philosophy is to maintain greater torque to longer-term oil prices, with only 1% of our expected oil production hedged for 2019. We will continue to add to our hedge positions in all products as suitable opportunities arise.
Organizational Update
Vermilion has a philosophy of staff development and internal promotion. In line with this approach, we have placed a great deal of emphasis in preparing for transition of our Chief Financial Officer position, as we have for other C-suite positions in the past. Curtis Hicks, currently Executive Vice President and Chief Financial Officer, is retiring effective in April 2018 after 15 very successful years with our company. Mr. Hicks has been a key member of the executive team, helping to guide Vermilion as we have expanded from two countries in 2003 to ten countries today. We thank Mr. Hicks for his numerous contributions, and wish him the best in his retirement.
Lars Glemser, currently our Director of Finance, will succeed Mr. Hicks as Vice President and Chief Financial Officer. Mr. Glemser joined Vermilion in 2015 as Operations Controller, and progressed through a developmental assignment in Investor Relations before becoming Vermilion's Director of Finance. Prior to joining Vermilion, he had management experience in audit, financial reporting, treasury and corporate planning. Mr. Glemser is a member of the Chartered Professional Accountants of Alberta and received a Bachelor of Commerce degree from the University of Saskatchewan.
We regularly rotate and refresh leadership in our operating units, and maintain a mix of expatriate and national management in our overseas businesses. Consequently, we are proud to announce a series of interlocking Managing Director appointments.
Scott Seatter, currently Managing Director of the Netherlands Business Unit, will take over as Managing Director of the United States Business Unit effective April 1, 2018. Mr. Seatter joined Vermilion in 2004, progressing through a number of successful engineering and management positions in Canada, France and most recently in the Netherlands. He earned a Bachelor of Science degree in Petroleum Engineering from the University of Alberta. Mr. Seatter replaces Dan Anderson, our current Managing Director of the United States Business Unit, who will be retiring in April 2018. Mr. Anderson's 33 years of industry experience in the Rocky Mountain region has been instrumental in establishing Vermilion's presence in the United States, setting the stage for sustainable future growth. We thank Mr. Anderson for his contributions to Vermilion and wish him the best in his retirement.
Sven Tummers, previously Commercial Manager for the Netherlands Business Unit, has been promoted to Managing Director of the Netherlands Business Unit, replacing Mr. Seatter. Since joining Vermilion in 2012, Mr. Tummers has held various engineering and management roles, utilizing his extensive and well-rounded background in HSE, asset and business development, and public and government relations. He earned a Master of Science degree in Chemical and Biochemical Engineering from Delft University of Technology in the Netherlands. Mr. Tummers is the first Dutch national to assume the Managing Director role for our Netherlands unit, and we look forward to his leadership on commercial, regulatory and political issues in that jurisdiction.
Darcy Kerwin, previously Managing Director for our France Business Unit, has been appointed to the newly-created role of Managing Director of the Ireland Business Unit. Since joining Vermilion in 2005, Mr. Kerwin has held several managerial positions across our global operations, working in Australia, France and Canada prior to assuming his most recent role as Managing Director in France in 2014. He earned a Bachelor of Science degree in Civil Engineering (Distinction) from the Technical University of Nova Scotia. Mr. Kerwin will lead the integration of Vermilion's vision, strategy and culture into our Ireland Business Unit as we assume operatorship of the Corrib field later this year.
Sylvain Nothhelfer, previously Technical Services Manager for the France Business Unit, has been promoted to Managing Director of the France Business Unit, replacing Mr. Kerwin. Mr. Nothhelfer has 30 years of international oil and gas experience including project management, production operations, and HSE management with Elf Aquitaine and Total SA. In his previous industry roles, Mr. Nothhelfer was involved in several major projects in Nigeria, the United Kingdom, the United Arab Emirates, Indonesia, France and Italy. He has Masters of Sciences and Doctoral degrees from the Universite de Toulon et du Var and the Centre National Recherches Scientifiques in France and the Cranfield Institute of Technology in the United Kingdom. We look forward to Mr. Nothhelfer's leadership in further advancing Vermilion's record of sustainability and value creation in France.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
February 28, 2018
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Mh-Ny-07 well tested gas at a rate of 5.8 mmcf/d over the final two hours of a 22 hour test period at a stabilized wellhead pressure of 1,065 psi on a 0.55 inch diameter choke and a shut-in wellhead pressure of 1,305 psi. No water production was observed during testing. The well logged 21 feet of net gas pay with an average porosity of 31% from an Upper Miocene Pannonian sandstone occurring within a gross measured depth interval of 3,438-3,465 feet. |
(3) |
Estimated proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2018 with an effective date of December 31, 2017 (the "2017 GLJ Reserves Evaluation") |
(4) |
Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(5) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2018 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2017 (the "GLJ 2017 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 23%, 22% and 22%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
2017 REVIEW AND 2018 GUIDANCE
On October 31, 2016, we released our 2017 capital expenditure guidance of $295 million and associated production guidance of between 69,000-70,000 boe/d. On July 26, 2017 we announced an increase in our capital expenditure guidance from $295 million to $315 million following the acceleration of 2018 activities in our Canadian business unit. We also adjusted our 2017 annual production guidance on October 30, 2017 to 68,000-69,000 boe/d to reflect an extended downtime period following a plant turnaround at our Corrib asset in Ireland. Actual 2017 capital spending of $320 million was within 2% of our guidance and 2017 production of 68,021 boe/d modestly exceeded the bottom end of our guidance range.
On October 30, 2017, we released our 2018 capital expenditure guidance of $315 million and associated production guidance of between 74,500-76,500 boe/d. On January 15, 2018, we increased our capital expenditure guidance to $325 million and production guidance to between 75,000-77,500 boe/d to reflect the post-closing impact of the acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer.
The following table summarizes our guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | |||||
2017 Guidance |
|||||||
2017 Guidance |
October 31, 2016 |
295 |
69,000 to 70,000 | ||||
2017 Guidance |
July 26, 2017 |
315 |
69,000 to 70,000 | ||||
2017 Guidance |
October 30, 2017 |
315 |
68,000 to 69,000 | ||||
2017 Actual Results |
320 |
68,021 | |||||
2018 Guidance |
|||||||
2018 Guidance |
October 30, 2017 |
315 |
74,500 to 76,500 | ||||
2018 Guidance |
January 15, 2018 |
325 |
75,000 to 77,500 |
CONFERENCE CALL AND AUDIO WEBCAST DETAILS
Vermilion will discuss these results in a conference call on Thursday, March 1, 2018 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will be available on replay until Thursday, March 15, 2018 at 9:59 PM MST by calling 1-855-859-2056 and using conference ID number 9997318.
To listen to the audio webcast, click http://event.on24.com/r.htm?e=1594411&s=1&k=1B901A2833707D33B4008329F5A0E9A8 or visit Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion currently pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
SOURCE Vermilion Energy Inc.
CALGARY, Feb. 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on March 15, 2018 to all shareholders of record on February 28, 2018. The ex-dividend date for this payment is February 27, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
DENVER, Feb. 15, 2018 /PRNewswire/ -- EnerCom's Texas-based oil and gas investment conference—EnerCom Dallas—will feature presentations from C-level executives at publicly traded and private oil and natural gas companies, as well as energy economists and other experts who will discuss global energy trends and projected economics for the industry in 2018 and 2019.
EnerCom has posted the work-in-progress agenda of presenters on the EnerCom Dallas website, subject to change.
Wednesday, 2/21/2018 |
|
EnerCom, Inc. |
|
Vermilion Energy |
|
Earthstone Energy |
|
Panhandle Oil & Gas |
|
Goodrich Petroleum |
|
Surge Energy |
|
Alta Mesa Resources |
|
Evolution Petroleum |
|
Federal Reserve Bank of Dallas – Mine Yücel |
|
Lunch Presentation |
|
Emerson |
|
Lonestar Resources |
|
BetaZi LLC |
|
Lilis Energy |
|
PetroShare Corp |
|
Razor Energy Corp |
|
EcoStim Energy Solutions, Inc. |
|
Tamarack Valley Energy |
|
Cocktail Reception and Networking Sponsored by Preng & Associates |
5:45pm |
Thursday, 2/22/2018 |
|
RS Energy |
|
Raging River Exploration |
|
GeoPark Limited |
|
Core Laboratories |
|
Flotek Industries |
|
PetroQuest Energy |
|
Comstock Resources |
|
Northern Oil & Gas |
|
Consulate General of Canada in Dallas – Delon Chan |
|
Lunch Presentation |
|
EIA – Industry Economist Jeffrey Barron |
|
Elk Petroleum |
|
Superior Drilling Products, Inc. |
|
Rosehill Resources |
EnerCom Dallas Conference Dates and Location: The EnerCom Dallas oil and gas investment conference is being held at the Tower Club in downtown Dallas on February 21-22, 2018.
Conference Registration: EnerCom is taking online registrations to attend EnerCom Dallas from the professional buyside investment community at the conference website.
EnerCom Dallas Presenting Companies
The EnerCom Dallas daily agenda of speakers has been posted on the conference website. The agenda of presenters is subject to change. Please refer to the conference website frequently for updates.
EnerCom Dallas conference presenters include, but are not limited to:
Publicly traded companies: |
|
NASDAQ: AMR |
Alta Mesa Resources |
NYSE: CLB |
Core Laboratories |
NYSE: CRK |
Comstock Resources, Inc. |
ASX: ELK |
Elk Petroleum |
NYSE: EMR |
Emerson Process Management |
NYSE: EPM |
Evolution Petroleum Corporation, Inc. |
NASDAQ: ESES |
EcoStim Energy Solutions, Inc. |
NYSE: ESTE |
Earthstone Energy, Inc. |
NYSE: FTK |
Flotek Industries |
NYSE: GDP |
Goodrich Petroleum Corporation |
NYSE: GPRK |
GeoPark Limited |
NYSE: LLEX |
Lilis Energy, Inc. |
NASDAQ: LONE |
Lonestar Resources |
NYSE: NOG |
Northern Oil & Gas, Inc. |
NYSE: PHX |
Panhandle Oil and Gas Inc. |
NYSE: PQ |
PetroQuest Energy, Inc. |
OTCMKTS: PRHR |
PetroShare Corp. |
NASDAQ: ROSE |
Rosehill Resources Inc. |
TSE: RRX |
Raging River Exploration Inc. |
TSX-V: RZE |
Razor Energy Corporation |
NYSE: SDPI |
Superior Drilling Products |
TSE: SGY |
Surge Energy, Inc. |
TSE: TVE |
Tamarack Valley Energy Ltd |
NYSE: VET |
Vermilion Energy Inc. |
Private companies: |
|
BetaZi, LLC |
|
RS Energy Group |
Institutional buyside investors who attend EnerCom Dallas will be able to hear and meet with senior management teams from leading independent E&Ps, including U.S., Canadian and international producers and the oilfield service companies supporting them.
Online Registration for EnerCom Dallas is Open
Institutional investors, portfolio managers, financial analysts, CIOs and other investment community professionals who invest in the energy space should register now for the EnerCom Dallas investment conference.
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists.
EnerCom Dallas is in its second year. Last year's EnerCom Dallas conference featured over 600 investment community and oil and gas industry attendees.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2018.
The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. The conference offers healthy dialogue and informal networking opportunities for attendees and presenters.
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History and Sponsors: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2018 marks EnerCom's 23rd annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 40 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
Global sponsors of EnerCom's Conferences are Netherland, Sewell & Associates; Preng & Associates; Moss Adams LLP; and RS Energy Group. Sponsors of EnerCom Dallas also include: DNB Bank ASA; Haynes and Boone; Fifth Third Bancorp, CIBC and AssuredPartners.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is a nationally recognized management consultancy advising and serving energy-centric clients on corporate strategy, asset valuations, investor relations, media and corporate communications and visual communications design. EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success. Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Dallas – Feb. 21-22, 2018
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA
joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Assured Partners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
View original content:http://www.prnewswire.com/news-releases/presenter-agenda-posted-for-enercom-dallas-oil--gas-investment-conference-feb-21-22-2018-300599233.html
SOURCE EnerCom, Inc.
DENVER, Jan. 31, 2018 /PRNewswire/ -- EnerCom's Texas-based oil and gas investment conference—EnerCom Dallas—will feature presentations from C-level executives at publicly traded and private oil and natural gas companies, as well as energy economists and other experts who will discuss global energy trends and projected economics for the industry in 2018 and 2019.
EnerCom Dallas Conference Dates and Location: The EnerCom Dallas oil and gas investment conference is being held at the Tower Club in downtown Dallas on February 21-22, 2018.
Conference Registration: EnerCom is taking online registrations to attend EnerCom Dallas from the professional buyside investment community at the conference website.
EnerCom Dallas Presenting Companies - Agenda of Speakers is Posted to Conference Website
The EnerCom Dallas daily agenda of speakers has been posted on the conference website. The agenda of presenters is subject to change. Please refer to the conference website frequently for updates.
EnerCom Dallas conference presenters include, but are not limited to:
Publicly traded companies: |
||
NYSE: CLB |
Core Laboratories |
|
NYSE: CRK |
Comstock Resources, Inc. |
|
ASX: ELK |
Elk Petroleum |
|
NYSE: EMR |
Emerson Process Management |
|
NYSE: EPM |
Evolution Petroleum Corporation, Inc. |
|
NASDAQ: ESES |
EcoStim Energy Solutions, Inc. |
|
NYSE: ESTE |
Earthstone Energy, Inc. |
|
NYSE: FTK |
Flotek Industries |
|
NYSE: GDP |
Goodrich Petroleum Corporation |
|
NYSE: GPRK |
GeoPark Limited |
|
TSE: GXO |
Granite Oil Corp. |
|
NYSE: LLEX |
Lilis Energy, Inc. |
|
NASDAQ: LONE |
Lonestar Resources |
|
NYSE: NOG |
Northern Oil & Gas, Inc. |
|
NYSE: PHX |
Panhandle Oil and Gas Inc. |
|
NYSE: PQ |
PetroQuest Energy, Inc. |
|
OTCMKTS: PRHR |
PetroShare Corp. |
|
NASDAQ: ROSE |
Rosehill Resources Inc. |
|
TSE: RRX |
Raging River Exploration Inc. |
|
TSX-V: RZE |
Razor Energy Corporation |
|
NYSE: SDPI |
Superior Drilling Products |
|
TSE: SGY |
Surge Energy, Inc. |
|
TSE: TVE |
Tamarack Valley Energy Ltd |
|
NYSE: VET |
Vermilion Energy Inc. |
|
Private companies: |
||
Alta Mesa Holdings, LP |
||
BetaZi, LLC |
||
RS Energy Group |
EnerCom Dallas presenting companies, experts will discuss plans, expectations for 2018
Executives from approximately 40 public and private energy companies and related oilfield service and technology organizations with operations spanning six continents will present their unique strategies for creating value in 2018 and beyond.
Energy economists and other experts representing the U.S. Energy Information Administration, the Federal Reserve Bank of Dallas and the Canadian Consulate in Dallas will provide their insights on a wide range of oil and gas financial topics including U.S. and Canadian petroleum and natural gas exports, global oil and gas supply/demand metrics and economic expectations for the oil and gas sector in 2018-2019.
Institutional buyside investors who attend EnerCom Dallas will be able to hear and meet with senior management teams from leading independent E&Ps, including U.S., Canadian and international producers and the oilfield service companies supporting them.
Online Registration for EnerCom Dallas is Open
Institutional investors, portfolio managers, financial analysts, CIOs and other investment community professionals who invest in the energy space should register now for the EnerCom Dallas investment conference.
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists.
EnerCom Dallas is in its second year. Last year's EnerCom Dallas conference featured over 600 investment community and oil and gas industry attendees.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2018.
The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. The conference offers healthy dialogue and informal networking opportunities for attendees and presenters.
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History and Sponsors: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2018 marks EnerCom's 23rd annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 40 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
Global sponsors of EnerCom's Conferences are Netherland, Sewell & Associates; Preng & Associates; Moss Adams LLP; and RS Energy Group. Sponsors of EnerCom Dallas also include: DNB Bank ASA; Haynes and Boone; Fifth Third Bancorp, CIBC and AssuredPartners.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is a nationally recognized management consultancy advising and serving energy-centric clients on corporate strategy, asset valuations, investor relations, media and corporate communications and visual communications design. EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success. Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors -- upstream, midstream, downstream and service -- as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on AssuredPartners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
View original content:http://www.prnewswire.com/news-releases/conference-agenda-has-been-posted-for-2018-enercom-dallas-oil--gas-investment-conference-300591406.html
SOURCE EnerCom, Inc.
DENVER, Jan. 24, 2018 /PRNewswire/ -- EnerCom's Texas-based oil and gas investment conference—EnerCom Dallas—will feature presentations from C-level executives at publicly traded and private oil and natural gas companies, as well as energy economists and other experts who will discuss global energy trends and projected economics for the industry in 2018 and 2019.
EnerCom Dallas Conference Dates and Location: The EnerCom Dallas oil and gas investment conference is being held at the Tower Club in downtown Dallas on February 21-22, 2018.
Conference Registration: EnerCom is taking online registrations to attend EnerCom Dallas from the professional buyside investment community at the conference website.
Presenting companies, experts will discuss plans, expectations for 2018
Executives from approximately 40 public and private energy companies and related organizations with operations spanning six continents will present their unique strategies for creating shareholder value in 2018 and beyond.
Energy economists and other experts representing the U.S. Energy Information Administration, the Federal Reserve Bank of Dallas and the Canadian Consul will provide their insights on a wide range of oil and gas financial topics including U.S. and Canadian petroleum and natural gas exports, global oil and gas supply/demand metrics and economic expectations for the oil and gas sector in 2018-2019.
EnerCom Dallas is a financial conference that allows institutional investors an early 2018 opportunity to hear and meet CEOs from leading independent E&Ps, including U.S., Canadian and international producers and the oilfield service companies supporting them.
EnerCom Dallas Presenting Companies
EnerCom Dallas conference presenters include, but are not limited to:
Publicly traded companies:
|
|
NYSE: CLB |
Core Laboratories |
NYSE: CRK |
Comstock Resources, Inc. |
ASX: ELK |
Elk Petroleum |
NYSE: EMR |
Emerson Process Management |
NYSE: EPM |
Evolution Petroleum Corporation, Inc. |
NASDAQ: ESES |
EcoStim Energy Solutions, Inc. |
NYSE: ESTE |
Earthstone Energy, Inc. |
NYSE: FTK |
Flotek Industries |
NYSE: GDP |
Goodrich Petroleum Corporation |
NYSE: GPRK |
GeoPark Limited |
TSE: IBR |
Iron Bridge Resources, Inc. |
NYSE: LLEX |
Lilis Energy, Inc. |
NASDAQ: LONE |
Lonestar Resources |
NYSE: NOG |
Northern Oil & Gas, Inc. |
NYSE: PHX |
Panhandle Oil and Gas Inc. |
NYSE: PQ |
PetroQuest Energy, Inc. |
OTCMKTS: PRHR |
PetroShare Corp. |
NASDAQ: ROSE |
Rosehill Resources Inc. |
TSE: RRX |
Raging River Exploration Inc. |
TSX-V: RZE |
Razor Energy Corporation |
NYSE: SDPI |
Superior Drilling Products |
TSE: SGY |
Surge Energy, Inc. |
TSE: TVE |
Tamarack Valley Energy Ltd |
NYSE: VET |
Vermilion Energy Inc. |
Private companies:
| |
Alta Mesa Holdings, LP | |
BetaZi, LLC | |
RS Energy Group |
The EnerCom Dallas presenter list will be updated on the conference website.
Online Registration for EnerCom Dallas is Open
Institutional investors, portfolio managers, financial analysts, CIOs and other investment community professionals who invest in the energy space should register now for the EnerCom Dallas investment conference.
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists.
EnerCom Dallas is in its second year. Last year's EnerCom Dallas conference featured over 600 investment community and oil and gas industry attendees.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2018.
The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. The conference offers healthy dialogue and informal networking opportunities for attendees and presenters.
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History and Sponsors: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2018 marks EnerCom's 23rd annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 40 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
Global sponsors of EnerCom's Conferences are Netherland, Sewell & Associates; Preng & Associates; Moss Adams LLP; and RS Energy Group. Sponsors of EnerCom Dallas also include: DNB Bank ASA; Haynes and Boone; and CIBC.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is a nationally recognized management consultancy advising and serving energy-centric clients on corporate strategy, asset valuations, investor relations, media and corporate communications and visual communications design. EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success. Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors -- upstream, midstream, downstream and service -- as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
View original content:http://www.prnewswire.com/news-releases/enercom-updates-2018-enercom-dallas-oil--gas-conference-presenters-speakers-300587747.html
SOURCE EnerCom, Inc.
DENVER, Jan. 18, 2018 /PRNewswire/ -- EnerCom's Texas-based oil and gas investment conference—EnerCom Dallas—will kick off on Feb. 21, 2018.
EnerCom Dallas will feature presentations from C-level executives at publicly traded and private oil and natural gas companies, as well as energy experts and analysts who will discuss global energy trends and projected economics of the industry in 2018 and 2019.
EnerCom Dallas Conference Dates and Location: The EnerCom Dallas oil and gas investment conference is being held at the Tower Club in downtown Dallas on February 21-22, 2018.
Conference Registration: EnerCom is taking registrations to attend EnerCom Dallas from the professional buyside investment community at the conference website.
Presenting companies, experts will discuss plans, expectations for 2018
Executives from approximately 40 public and private energy companies and related organizations with operations spanning six continents will present their unique strategies for creating shareholder value in 2018 and beyond.
In addition to company management teams, energy economists from the U.S. Energy Information Administration and the Federal Reserve Bank of Dallas will provide their insights on global supply/demand, market forces affecting the oil and gas industry and expectations for the oil and gas sector in 2018-2019.
EnerCom Dallas is a financial conference that allows institutional investors an early 2018 opportunity to hear and meet CEOs from leading independent E&Ps, including U.S., Canadian and international producers and the oilfield service companies supporting them.
EnerCom Dallas Presenting Companies
EnerCom Dallas conference presenters include, but are not limited to:
Publicly traded companies:
NYSE: CLB |
Core Laboratories |
NYSE: CRK |
Comstock Resources, Inc. |
ASX: ELK |
Elk Petroleum |
NYSE: EPM |
Evolution Petroleum Corporation, Inc. |
NASDAQ: ESES |
EcoStim Energy Solutions, Inc. |
NYSE: ESTE |
Earthstone Energy, Inc. |
NYSE: FTK |
Flotek Industries |
NYSE: GDP |
Goodrich Petroleum Corporation |
NYSE: GPRK |
GeoPark Limited |
NYSE: LLEX |
Lilis Energy, Inc. |
NASDAQ: LONE |
Lonestar Resources |
NYSE: PHX |
Panhandle Oil and Gas Inc. |
NYSE: PQ |
PetroQuest Energy, Inc. |
OTCMKTS: PRHR |
PetroShare Corp. |
NASDAQ: ROSE |
Rosehill Resources Inc. |
TSE: RRX |
Raging River Exploration Inc. |
TSX-V: RZE |
Razor Energy Corporation |
NYSE: SDPI |
Superior Drilling Products |
TSE: SGY |
Surge Energy, Inc. |
TSE: TVE |
Tamarack Valley Energy Ltd |
NYSE: VET |
Vermilion Energy Inc. |
Private companies:
Alta Mesa Holdings, LP | |
BetaZi, LLC | |
RS Energy Group |
The EnerCom Dallas presenter list will be updated on the conference website.
Institutional investors, portfolio managers, financial analysts, CIOs and other investment community professionals who invest in the energy space should register now for the EnerCom Dallas investment conference.
Online Registration for EnerCom Dallas is Open
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists.
EnerCom Dallas is in its second year. Last year's EnerCom Dallas conference featured over 600 investment community and oil and gas industry attendees.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2018.
The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. The conference offers healthy dialogue and informal networking opportunities for attendees and presenters.
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History and Sponsors: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2018 marks EnerCom's 23rd annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 40 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
Global sponsors of EnerCom's Conferences are Netherland, Sewell & Associates; Credit Agricole Corporate & Investment Bank; Preng & Associates; Moss Adams LLP; and RS Energy Group. Sponsors of EnerCom Dallas also include: DNB Bank ASA; Haynes and Boone; and CIBC.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is a nationally recognized management consultancy advising and serving energy-centric clients on corporate strategy, asset valuations, investor relations, media and corporate communications and visual communications design. EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success. Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Credit Agricole Corporate and Investment Bank
Credit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Credit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Credit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors -- upstream, midstream, downstream and service -- as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
View original content:http://www.prnewswire.com/news-releases/enercom-dallas-announces-2018-conference-presenters-300585023.html
SOURCE EnerCom, Inc.
CALGARY, Jan. 16, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on February 15, 2018 to all shareholders of record on January 31, 2018. The ex-dividend date for this payment is January 30, 2018. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Jan. 15, 2018 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce that we have entered into an arrangement agreement (the "Arrangement") to acquire a private southeast Saskatchewan producer ("Privateco") for total cash consideration of $90.8 million (the "Purchase Price").
Under the terms of the Arrangement, Vermilion has agreed to acquire (the "Acquisition") all of the issued and outstanding common shares ("Privateco Shares") in the capital of Privateco, including all Privateco Shares issuable, in accordance with the terms of existing grants of options or warrants, prior to the effective time of the Arrangement, and assume all outstanding debt of the Privateco. The Purchase Price will be funded from Vermilion's existing credit facilities.
The Board of Directors of Privateco has unanimously approved the Arrangement and recommended that Privateco shareholders vote in favour of the Arrangement. The Arrangement remains subject to customary closing conditions, including receipt of applicable court, Privateco shareholder and regulatory approvals, and is expected to close on or about February 15th, 2018.
The Acquisition is comprised of high netback, low base decline, light oil producing fields in the Sinclair and Fertile areas, straddling the Saskatchewan/Manitoba border, approximately 55 km northeast of Vermilion's existing operations in southeast Saskatchewan (the "Assets"). The Assets include approximately 42,600 net acres of land (approximately 100% W.I.), three oil batteries, and associated pipelines, along with the necessary water infrastructure to facilitate the existing seven waterflood projects and initiate up to eight additional waterflood projects. The Assets produced approximately 1,150 bbl/d of 40° API oil during Q4 2017, sourced from the Bakken/Three Forks formation. All of the current production and infrastructure will be 100% owned and operated by Vermilion.
Total proved plus probable ("2P") reserves attributed to the Assets at December 31, 2017 are 6.7(1) mmboe (100% crude oil), based on an independent evaluation by GLJ Petroleum Consultants Ltd. The Assets demonstrate a low base decline rate of approximately 15% at present, and are expected to have even lower decline rates over time. Areas under waterflood have decline rates of less than 10% with certain areas of flat or increasing production. Approximately 45% of the production comes from active waterflood projects, leaving significant opportunity to expand the waterflood.
The Acquisition is accretive on a fully-diluted per share basis for all pertinent metrics including production, fund flows from operations(2), reserves and net asset value. Making no deduction for undeveloped land value, transaction metrics equate to $13.55 per boe of 2P reserves, and $79,000 per flowing barrel of production. Based on 2018 WTI strip pricing of US$61.83/bbl, the operating netback for the Assets is estimated at approximately $51.80 (2) per boe. Using the 2P finding, development and acquisition cost (based on the reserves in the GLJ report) of $19.02 per boe (including future development capital), the Assets are expected to deliver a 2P after-tax fund flows recycle ratio of 2.7 times.
Using the same strip pricing assumption, the total Acquisition cost (including assumed debt) is approximately 5.1 times estimated annualized 2018 fund flows from operations ("FFO"), after deducting incremental interest expense. Calculated on a debt-adjusted cash flow basis, the total Acquisition cost (including assumed debt) is approximately 4.6 times. Pro-forma the acquisition, our year end 2018 debt-to-FFO ratio is forecast to be 2.0 times based on January 11, 2018 strip pricing, as compared to 1.9 times prior to the acquisition.
The Acquisition complements our current southeast Saskatchewan operations and will be managed out of our existing field office in the area. Furthermore, the Acquisition aligns with our sustainable growth-and-income model by targeting low risk assets with high netbacks, strong free cash flow generation, low base decline rates and strong capital efficiencies on future development.
As a result of the Acquisition, and based on a mid-February closing date, we are revising our 2018 production guidance to between 75,000 and 77,500 boe/d (from 74,500 to 76,500 boe/d previously). We are also increasing our 2018 capital budget to $325 million (from $315 million previously) to reflect additional capital activity on these assets planned for the second half of the year.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Natural gas volumes have been converted on the basis of six thousand cubic feet ("mcf") of natural gas to one barrel equivalent of oil. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(1) |
Estimated total proved and proved plus probable reserves attributable to the Assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated January 12, 2018 with an effective date of December 31, 2017, in accordance with National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities of the Canadian Securities Administrators, using the GLJ (2018-01) price forecast (the "GLJ Report") |
(2) |
Non-GAAP Financial Measures: Netbacks, fund flows from operations, and free cash flow are non-GAAP (as defined herein) or additional GAAP financial measures that do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") and therefore may not be comparable with the calculations of similar measures for other entities. "Netbacks" are per boe and per mcf measures used in operational and capital allocation decisions. "Fund flows from operations" represents cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management considers fund flows from operations and fund flows from operations per share to be key measures as they demonstrate Vermilion's ability to generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a useful measure of Vermilion's ability to generate cash that is not subject to short-term movements in non-cash operating working capital. For relevant operating netback related disclosures please refer to the reconciliation in management's discussion and analysis contained in Vermilion's 2016 Annual Report for the year ended December 31, 2016 available on SEDAR or at the company's website (www.vermilionenergy.com). |
DISCLAIMER
Certain statements included or incorporated by reference in this press release may constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this press release may include, but are not limited to:
Statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
SOURCE Vermilion Energy Inc.
DENVER, Jan. 10, 2018 /PRNewswire/ -- Institutional investors, portfolio managers, financial analysts, CIOs and other investment community professionals who invest in the energy space should register now for the EnerCom Dallas investment conference, which is coming to The Tower Club Feb. 21-22, in the Thanksgiving Tower in the downtown Dallas.
EnerCom Dallas is a financial conference that allows institutional investors an early 2018 opportunity to hear and meet CEOs from leading independent E&Ps, including some of the industry's leading Permian, Eagle Ford, Marcellus, Utica and Canadian producers and the oilfield service companies supporting them, discuss plans to drive development, fund operations and return value to shareholders in 2018.
EnerCom Dallas Presenting Companies: North American and International Oil Plays
Presenting companies scheduled for the second EnerCom Dallas oil and gas investment conference, which runs Wed. Feb. 21 and Thurs. Feb. 22, 2018, include prominent North American shale operators as well as oil and gas companies operating globally. A sample of the presenting companies scheduled for EnerCom Dallas follows. Dallas presenters include but are not limited to:
Vermilion Energy (NYSE: VET) has producing properties in North America, Europe and Australia and is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion targeted production of approximately 70,000 BOEPD for 2017. Vermilion pays a monthly cash dividend to shareholders.
GeoPark Limited (NYSE: GPRK) is an independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Brazil, Argentina, Chile and Peru. GeoPark is currently ranked the third-largest private oil and gas operator in Colombia and the first private oil and gas producer in Chile. GeoPark reported record 2017 exit production of 31,977 BOEPD. Its consolidated oil and gas production rose 30% to 30,654 BOEPD in 2017, with oil production at 25,341 BOPD and gas production at 31.9 MMcf/day.
Earthstone Energy, Inc. (NYSE: ESTE) is focused on developing and operating oil and gas properties in the Midland basin of West Texas and the Eagle Ford trend of south Texas. Earthstone's position in the Midland basin includes approximately 27,000 net acres and approximately 7,000 BOEPD. Earthstone said it has identified 500 drilling locations in three benches in the Wolfcamp. Earthstone reported Q3 2017 net production of 5,357 BOEPD (63% oil, 84% liquids), with average daily production of 9,671 BOEPD for Q3, 2017.
Online Registration for EnerCom Dallas is Open
Buyside professionals and oil and gas company executives are encouraged to register now for the event through the conference website.
The EnerCom Dallas conference follows EnerCom's familiar 25-minute CEO presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meeting opportunities for buyside investors to meet company management teams, networking opportunities and global insight delivered by leading energy economists and strategists.
EnerCom Dallas is in its second year. Last year's EnerCom Dallas conference featured over 600 investment community and oil and gas industry attendees.
Conference Details: Modeled after EnerCom's The Oil & Gas Conference® in Denver, EnerCom Dallas offers investment professionals a unique opportunity to listen to oil and gas company senior management teams update investors on their operational and financial strategies and learn how the leading energy companies are building value in 2018.
The event also provides energy industry professionals a venue to learn about important energy topics affecting the global oil and gas industry. The conference offers healthy dialogue and informal networking opportunities for attendees and presenters.
Conference Dates: Feb. 21, 22 2018
Conference Location: Tower Club Dallas, 1601 Elm Street, Thanksgiving Tower, 48th Floor, Dallas, Texas 75201
Public and Private Company Presenters: EnerCom Dallas will feature both public and private companies headquartered in Canada and the U.S. with operations across the most active and prolific oil and gas regions and the globe. A work-in-progress list of the presenting companies will be posted and updated on the conference website.
Who Attends the Conference: Institutional and hedge fund investors, private equity investors, energy research analysts, broker/dealers, trust officers, high net worth investors, commercial energy bankers and other energy industry professionals will gather in Dallas for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue.
History and Sponsors: EnerCom, Inc. hosted its original energy-focused investment conference, The Oil & Gas Conference®, in 1996 in Denver. 2018 marks EnerCom's 23rd annual Denver oil and gas financial conference. Since its founding, EnerCom has hosted more than 40 successful oil and gas investment conferences in Denver, London, Dallas, Boston and San Francisco.
Global sponsors of EnerCom's Conferences are Netherland, Sewell & Associates; Credit Agricole Corporate & Investment Bank; Preng & Associates; Moss Adams LLP; and RS Energy Group. Sponsors of EnerCom Dallas also include: DNB Bank ASA; Haynes and Boone; and CIBC.
About EnerCom, Inc.
Founded in 1994, EnerCom, Inc. is a nationally recognized management consultancy advising and serving energy-centric clients on corporate strategy, asset valuations, investor relations, media and corporate communications and visual communications design. EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success. Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Credit Agricole Corporate and Investment Bank
Credit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Credit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Credit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors -- upstream, midstream, downstream and service -- as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
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SOURCE EnerCom, Inc.
CALGARY, Dec. 15, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on January 16, 2018 to all shareholders of record on December 29, 2017. The ex-dividend date for this payment is December 28, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Nov. 15, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on December 15, 2017 to all shareholders of record on November 30, 2017. The ex-dividend date for this payment is November 29, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Oct. 30, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and nine months ended September 30, 2017.
The unaudited financial statements and management discussion and analysis for the three and nine months ended September 30, 2017, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
HIGHLIGHTS
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Eesveen-02 Zechstein 2 carbonate flow test was performed over a two hour period at a wellhead pressure of 1,290 psi with flow rates of 8.3 mmcf/d net and the Eesveen-02 Rotliegend sandstone flow test was performed over a 10 day period at a wellhead pressure of 2,360 psi with flow rates of 10 mmcf/d net resulting in combined production in excess of 18 mmcf/d net to Vermilion. These test results are not necessarily indicative of long-term performance of ultimate recovery. |
HIGHLIGHTS |
|||||||
Three Months Ended |
Nine Months Ended | ||||||
($M except as indicated) |
Sep 30, |
Jun 30, |
Sep 30, |
Sep 30, |
Sep 30, | ||
Financial |
2017 |
2017 |
2016 |
2017 |
2016 | ||
Petroleum and natural gas sales |
248,505 |
271,391 |
232,660 |
781,497 |
622,900 | ||
Fund flows from operations |
130,755 |
147,123 |
140,974 |
421,312 |
361,209 | ||
Fund flows from operations ($/basic share) (1) |
1.08 |
1.22 |
1.21 |
3.51 |
3.14 | ||
Fund flows from operations ($/diluted share) (1) |
1.07 |
1.20 |
1.19 |
3.45 |
3.11 | ||
Net (loss) earnings |
(39,191) |
48,264 |
(14,475) |
53,613 |
(156,019) | ||
Net (loss) earnings ($/basic share) |
(0.32) |
0.40 |
(0.12) |
0.45 |
(1.36) | ||
Capital expenditures |
91,382 |
58,875 |
41,039 |
246,146 |
175,526 | ||
Acquisitions |
20,976 |
993 |
10,391 |
24,589 |
19,811 | ||
Asset retirement obligations settled |
1,749 |
2,120 |
2,066 |
6,118 |
6,290 | ||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 |
1.935 |
1.935 | ||
Dividends declared |
78,293 |
77,858 |
75,465 |
232,744 |
222,974 | ||
% of fund flows from operations |
60% |
53% |
54% |
55% |
62% | ||
Net dividends (1) |
54,364 |
48,617 |
24,553 |
144,068 |
73,556 | ||
% of fund flows from operations |
42% |
33% |
17% |
34% |
20% | ||
Payout (1) |
147,495 |
109,612 |
67,658 |
396,332 |
255,372 | ||
% of fund flows from operations |
113% |
75% |
48% |
94% |
71% | ||
Net debt |
1,370,995 |
1,314,766 |
1,343,923 |
1,370,995 |
1,343,923 | ||
Ratio of net debt to annualized fund flows from operations |
2.6 |
2.2 |
2.4 |
2.4 |
2.8 | ||
Operational | |||||||
Production |
|||||||
Crude oil and condensate (bbls/d) |
27,687 |
28,525 |
27,842 |
27,684 |
28,483 | ||
NGLs (bbls/d) |
4,947 |
3,821 |
2,478 |
3,828 |
2,621 | ||
Natural gas (mmcf/d) |
208.63 |
209.36 |
199.66 |
209.35 |
199.90 | ||
Total (boe/d) |
67,403 |
67,240 |
63,596 |
66,404 |
64,421 | ||
Average realized prices |
|||||||
Crude oil and condensate ($/bbl) |
61.47 |
64.35 |
56.60 |
64.58 |
52.57 | ||
NGLs ($/bbl) |
23.96 |
20.98 |
12.40 |
23.01 |
9.67 | ||
Natural gas ($/mcf) |
4.01 |
4.75 |
3.98 |
4.79 |
3.76 | ||
Production mix (% of production) |
|||||||
% priced with reference to WTI |
22% |
20% |
19% |
20% |
20% | ||
% priced with reference to AECO |
26% |
24% |
20% |
24% |
22% | ||
% priced with reference to TTF and NBP |
26% |
28% |
32% |
29% |
29% | ||
% priced with reference to Dated Brent |
26% |
28% |
29% |
27% |
29% | ||
Netbacks ($/boe) |
|||||||
Operating netback (1) |
26.06 |
28.72 |
27.88 |
28.69 |
25.75 | ||
Fund flows from operations netback |
20.87 |
23.66 |
23.25 |
23.34 |
20.46 | ||
Operating expenses |
9.87 |
10.14 |
9.05 |
9.80 |
9.21 | ||
Average reference prices |
|||||||
WTI (US $/bbl) |
48.20 |
48.28 |
44.94 |
49.47 |
41.33 | ||
Edmonton Sweet index (US $/bbl) |
45.32 |
46.03 |
42.06 |
46.57 |
38.11 | ||
Dated Brent (US $/bbl) |
52.08 |
49.83 |
45.85 |
51.90 |
41.77 | ||
AECO ($/mmbtu) |
1.45 |
2.78 |
2.32 |
2.31 |
1.85 | ||
NBP ($/mmbtu) |
6.78 |
6.52 |
5.29 |
7.10 |
5.69 | ||
TTF ($/mmbtu) |
6.93 |
6.74 |
5.43 |
7.12 |
5.58 | ||
Average foreign currency exchange rates |
|||||||
CDN $/US $ |
1.25 |
1.34 |
1.31 |
1.31 |
1.32 | ||
CDN $/Euro |
1.47 |
1.48 |
1.46 |
1.45 |
1.48 | ||
Share information ('000s) | |||||||
Shares outstanding - basic |
121,585 |
120,947 |
117,386 |
121,585 |
117,386 | ||
Shares outstanding - diluted (1) |
124,453 |
123,794 |
120,183 |
124,453 |
120,183 | ||
Weighted average shares outstanding - basic |
121,280 |
120,514 |
116,814 |
120,152 |
114,975 | ||
Weighted average shares outstanding - diluted (1) |
122,485 |
122,660 |
118,177 |
121,963 |
116,221 |
(1 ) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
MESSAGE TO SHAREHOLDERS
We have now set our 2018 budget and have reaffirmed our long-term targets of delivering 5 to 7% production per share growth at a payout ratio of less than 100% under the prevailing commodity strip. Our 2018 budget projects production of 74,500 to 76,500 boe/d on capital investment of $315 million. Production growth for 2018 is projected to be 10% on an absolute basis and 7% on a per share basis.
Achieving our guidance targets is very important to us. Early in 2017, we encountered unexpected permitting difficulties in the Netherlands, and accordingly constructed and implemented a revised investment and production plan that called on other jurisdictions to make up this difference. While the revised plan was successful in generating expected production volumes in our operated business units, we encountered an additional problem in our non-operated Irish unit towards the end of Q3. Downtime at Corrib, following a plant turnaround in September, reduced production by approximately 2,400 boe/d in Q3, and will cost us approximately 900 boe/d on an annualized basis in 2017. This foregone production is impossible to make up by the end of 2017. As a result, we have reduced our 2017 production guidance from a range of 69,000 to 70,000 boe/d to a range of 68,000 to 69,000 boe/d. Nonetheless, we still expect to achieve 2017 year-over-year production growth of approximately 8% in absolute terms, and approximately 3% on a per-share basis. Incorporating our 2018 production guidance implies a compound annual growth rate of approximately 9% for the two-year period from 2017-2018 with a forecasted payout(1) ratio below 100% in both years, based on current strip pricing.
In early September, the French government announced further details on its proposed Climate Plan, and enabling legislation is currently being debated in the French Parliament. The plan contains a number of elements broadly affecting the French economy, including reductions in nuclear power generation and future restrictions on internal combustion engines and hydrocarbon-based fuels for cars. Two previously-announced elements affect the French oil production industry. First, the proposed legislation prohibits the issuance of new exploration concessions in France, although existing exploration concessions may be converted to production concessions in the event of hydrocarbon discoveries. Vermilion is largely unaffected by this change. Our French investment activities are overwhelmingly concentrated in development projects on existing fields in existing production concessions. In a limited set of existing exploration concessions, we do intend to conduct seismic and drilling operations, and in these cases, the proposed legislation allows conversion to production concessions if exploration is successful. Second, the proposed legislation puts a limit on renewals of existing production concessions at 2040, with certain exceptions which may allow for a longer production term. Again, if the time limit on production concession renewals is enacted, we expect an immaterial effect on Vermilion's production and reserve profile. With respect to the advisability of the proposed changes to French oil production policy, we first point out that Vermilion was designated as a Climate "A" List company by CDP (formerly the Carbon Disclosure Project) in 2016, one of only five energy companies in the world to receive such a designation. In addition, we have several sustainability projects ongoing in France that reduce carbon emissions while simultaneously promoting new industries and economic inclusivity, and intend to implement more sustainability projects over time. Finally, domestic oil production in France has a lower carbon footprint than imported oil. While Vermilion supports and is a part of the long-term energy transition, we believe that the transition is best realized by turning to best-in-class companies such as Vermilion to produce the oil and gas that will still be consumed in the French and world economies.
While operating in Europe has always been more challenging as compared to North America, we have demonstrated throughout our history that the superior return we achieve from our European assets is well worth the additional effort. We have a long track record of profitably increasing our oil and gas production in Europe and we have the appropriate personnel and business practices in place to continue to succeed in this exacting but high return jurisdiction. We believe that the operating and business development franchise that we have established in Europe would be difficult to replicate, and therefore provides us with a significant competitive advantage, which we believe will continue to drive strong growth and high returns for Vermilion and our shareholders in the future. Our European franchise and skill set may in fact become more valuable over time as other companies may elect to exit this demanding region, potentially creating a greater pace of business development opportunity. In the nearer term, we look very much forward to resuming growth in the Netherlands, beginning drilling activities in Central and Eastern Europe ("CEE"), and assuming operatorship of our Corrib project in Ireland.
Q3 2017 Review
Vermilion's Q3 2017 production of 67,403 boe/d was up slightly compared to the prior quarter. Higher production in Canada and the US was achieved through successful drilling programs in the first nine months of the year, while Netherlands production benefited from receipt of permits and reduced turnaround work. Downtime at Corrib significantly offset production growth in other jurisdictions, reducing expected Q3 production by approximately 2,400 boe/d.
Fund flows from operations ("FFO") for Q3 2017 was $131 million ($1.08/basic share(1)) as compared to $147 million ($1.22/basic share(1)) in Q2 2017. FFO decreased 11% quarter-over-quarter primarily due to unplanned downtime in Ireland, lower Australian sales and a decline in realized commodity prices. Despite this decrease in FFO, our payout(1) ratio for the first nine months of 2017 was 94%.
Europe
We had an active quarter in the Netherlands, which included the completion of our two (1.0 net) well drilling campaign. The Eesveen-02 well (60% working interest) encountered 24 metres of net pay in two separate intervals targeting the Zechstein-2 carbonate and the Rotliegend sandstone. The second well, Nieuwehorne-02 (42% working interest), also targeted two separate intervals, the Zechstein-2 carbonate and the Vlieland sandstone, encountering 10 metres of net pay. The two zones in the Eesveen-02 well were flow tested at a combined rate in excess of 18 mmcf/d(2) net and the well is expected to be brought on production in mid-2018. The Nieuwehorne-02 well is currently being prepared for a flow test. During the quarter, the Ministry of Economic Affairs published its approval for a production rate increase on one of our pools, which became effective in early September. As a result, production in the Netherlands is currently back up to more than 8,000 boe/d and should continue to grow through the balance of the year. We also received additional permits for our 3D seismic survey in the Akkrum and South Friesland III exploration licenses, and have increased the size of the program from 220 square kilometres to 315 square kilometres, with completion of the program expected prior to the end of the year.
In Ireland, production from Corrib averaged 49 mmcf/d (8,173 boe/d) in Q3 2017, a 23% reduction from Q2 2017 due to an extended downtime period following a plant turnaround. Although turnaround tasks were completed successfully, unodorized gas was detected in the distribution network following restart. This resulted in an extended period of downtime to remove the unodorized gas and to implement process changes to ensure that odorant would be continuously injected and monitored in future plant operation. Production at Corrib resumed on October 11th after 21 days of downtime in Q3 and just over 10 days of downtime in Q4. The annualized impact from this downtime, net to Vermilion, is estimated at approximately 900 boe/d.
In Germany, we continue to execute workover and artificial lift optimization operations on the assets acquired from Engie E&P Deutschland GmbH in December 2016. For the second consecutive quarter, production from the acquired assets represented a 10% increase from pre-acquisition levels and contributed to a slight increase in overall business unit production from the previous quarter despite no new drilling activity. Compared to Q3 2016, production has increased by 82% through our acquisition and organic growth activities, and has contributed to a much stronger free cash flow profile for the German Business Unit. Based on current strip pricing, we are forecasting the German business to deliver free cash flow(1) of approximately 65% in 2017.
North America
In Canada, we continued successful execution of our 2017 capital program. During Q3 2017, we drilled or participated in 10 (8.0 net) Mannville wells, two (2.0 net) Cardium wells and three (2.8 net) Midale wells and brought on production seven (5.6 net) Mannville wells, two (2.0 net) Cardium wells and three (2.8 net) Midale wells. All three projects continue to deliver predicable results, driving a 29% increase in year-over-year quarterly production to approximately 31,500 boe/d for the Canadian Business Unit. There was significant third-party maintenance by TCPL in west-central Alberta in the third quarter, with planned and unplanned disruptions restricting available gas capacity on multiple systems. Despite these restrictions, our Canadian Business Unit was able to deliver its growth targets. In addition, during the quarter we executed on $20 million of tuck-in acquisitions, mainly focused on enhancing our Mannville land base in the Drayton Valley and Ferrier areas.
In the United States, production grew 16% quarter-over-quarter as a result of the three (3.0 net) Turner Sand wells drilled in the first quarter, setting the stage for an increased drilling program in 2018. Our 25,500 acre Rex Federal Unit in the northern region of the Turner Sand project was approved by the Bureau of Land Management ("BLM") in early October, and we received a paying well determination from the BLM for the 24,400 acre Three Horn Federal Unit. This determination eliminates a 180 day continuous drilling obligation and holds the leases within the Three Horn Unit for a minimum of five years, with many of the federal leases within the unit having even longer tenure. These federal units cover the majority of our Turner Sand project, giving us an even lower expiry profile and greater control over the pace and focus of development activities.
Sustainability
Vermilion received a top quartile ranking for 2017 for our industry sector in RobecoSAM's annual Corporate Sustainability Assessment ("CSA"). The CSA analyzes sustainability performance across economic, environmental, governance and social criteria, and is the basis of the Dow Jones Sustainability Indices. The RobecoSAM assessment follows earlier recognition of Vermilion's Sustainability performance, including placement on the CDP Climate "A" List as a global leader in environmental stewardship, top oil and gas company performance in Corporate Knights Future 40 Responsible Corporate Leaders in Canada ranking, and receipt of the French government's Circular Economy Award for Industrial and Regional Ecology for our geothermal energy partnership in Parentis. We believe the integration of sustainability principles into our business is the right thing to do, increases shareholder returns, enhances our business development opportunities and reduces long-term risks to our business model.
2018 Budget
Our Board of Directors have formally approved an E&D capital budget of $315 million for 2018, with associated production guidance of 74,500 to 76,500 boe/d. The midpoint of our 2018 production guidance is unchanged compared to our previous target, while the projected total E&D capital spend for 2017 and 2018 combined is lower than our previous targets. The 2018 production target results in compound annual growth of 9% for the 2017-2018 two-year period, with a forecasted payout(1) ratio below 100% in both years, based on current strip pricing.
This budget funds development of a number of high-return projects, including investment in all three core areas of Canada, continued development in both the Neocomian and Champotran fields in France, a return to production growth in the Netherlands where we continue to benefit from favorably-priced European natural gas, continued development of our Turner Sands play in the United States, and inaugural drilling in our CEE business unit in the South Battonya license in Hungary.
Our 2018 E&D budget represents the fourth consecutive year of significantly lower capital expenditures and our third consecutive year where E&D capital will be less than 50% of 2014 levels, even though 2018 production rates are expected to be 50% higher than in 2014. Absolute production growth of 10% for 2018 is estimated to translate to per share growth of 7%, based on the midpoint of our production guidance range. Our geographic and commodity diversification allow for a high return capital program even in tempered commodity price environments, and provide the flexibility to respond to changes in individual commodity markets as prices recover.
At current strip prices, Vermilion expects to fully fund 2018 E&D capital expenditures and cash dividends from fund flows from operations. This would represent the third consecutive year of delivering per share production growth at a payout ratio of less than 100%.
Europe
Our 2018 E&D budget for France of $73 million is relatively consistent with 2017 investment. Following our successful inaugural 2017 drilling campaign in the Neocomian field, we plan to drill an additional four (4.0 net) wells in the Neocomian fields in the Paris Basin in 2018, with the potential to initiate the drilling program in late 2017. In addition, we expect to drill three (3.0 net) Champotran wells, which includes one (1.0 net) sidetrack step-out well, and continue our ongoing program of workovers and optimizations.
In the Netherlands, our 2018 E&D budget of $35 million represents a 6% increase from 2017. We expect to drill three (1.5 net) exploration wells after completing our successful 2017 two-well (1.0 net) exploration program. We also expect to execute the second phase of our seismic acquisition program.
In Germany, our 2018 E&D capital budget of $14 million represents a 40% increase from our 2017 program. We will continue to invest in optimization projects and other well work on the oil and gas assets acquired at the end of 2016. We expect to commence pre-drilling operations on the operated Burgmoor Z5 development well in 2018, with plans to drill in 2019. We will also continue to advance our permitting, studies and other activities associated with the farm-in agreement we signed in mid-2015.
Our 2018 Central and Eastern Europe capital program of $11 million builds on $8 million of planned 2017 investment. In 2018, we plan to drill our first well (1.0 net) in the South Battonya license in Hungary. We were issued licenses in Ebes and South Battonya in 2014 and 2015 covering 334,000 acres, and we focused our 2017 activities on interpreting 3D seismic in the South Battonya license. In 2018, in addition to drilling in Hungary, we expect to continue pre-drilling investment in our Slovakian and Croatian prospects.
Ireland will continue to be a strong free cash flow contributor in 2018, with a low level of capital investment expected in 2018. We expect to become operator of the Corrib gas field in mid-2018, subject to partner and regulatory approvals and completion of our acquisition, with Canada Pension Plan Investment Board, of Shell E&P Ireland Limited.
North America
We plan to invest approximately $136 million in E&D activities in Canada in 2018, representing a decrease of 5% from the $143 million forecasted for 2017. Because permitting approvals are generally routine and producing infrastructure is generally accessible in western Canada, our Canadian business unit has the ability to ramp capital activity levels up or down in response to corporate needs and capital availability. Our 2017 capital investment program of $143 million represented a 32% increase from initial budget levels as capital activity was increased throughout 2017 to take advantage of this ability to ramp up in a short period of time.
Our Canadian investment program continues to be significantly oil-weighted with all three of our core plays in Canada generating robust economics in the prevailing commodity price environment. In 2018, we expect to drill or participate in 17 (13.8 net) Mannville wells, five (4.2 net) Cardium oil wells in west central Alberta and 16 (15.5 net) Midale light oil wells in southeast Saskatchewan.
In the United States, we expect to drill and complete five (5.0 net) wells targeting the light oil Turner Sand in the Powder River Basin of Wyoming.
Australia
Our 2018 E&D budget of $22 million for Australia will focus on facility maintenance and pre-spending for the 2019 drill campaign.
E&D Capital Investment by Country
Country |
2018 Budget* ($MM) |
2017 Estimate ($MM) |
2018 vs. 2017 % Change |
2018 Net Wells |
2017 Net Wells |
Canada |
136 |
143 |
(5%) |
33.5 |
34.7 |
France |
73 |
71 |
3% |
7.0 |
5.0 |
Netherlands |
35 |
33 |
6% |
1.5 |
1.0 |
Germany |
14 |
10 |
40% |
- |
- |
Ireland |
1 |
1 |
- |
- |
- |
Australia |
22 |
30 |
(27%) |
- |
- |
USA |
23 |
19 |
21% |
5.0 |
3.0 |
Central and Eastern Europe |
11 |
8 |
38% |
1.0 |
- |
Total E&D Capital Expenditures |
315 |
315 |
- |
48.0 |
43.7 |
E&D Capital Investment by Category
Category |
2018 Budget* ($MM) |
2017 Estimate ($MM) |
2018 vs. 2017 % Change |
Drilling, completion, new well equipment and tie-in, workovers and recompletions |
210 |
195 |
8% |
Production equipment and facilities |
60 |
70 |
(14%) |
Seismic, studies, land and other |
45 |
50 |
(10%) |
Total E&D Capital Expenditures |
315 |
315 |
- |
* 2018 Budget reflects foreign exchange assumptions of USD/CAD 1.25, CAD/EUR 1.49 and CAD/AUD 0.97. |
Our revised production plan by business unit can be found in our November 2017 investor presentation on our website.
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of cash flows, providing additional certainty with regards to the execution of our dividend and capital programs. We currently have 37% of our expected net-of-royalty production hedged for 2018, including 45% of anticipated European natural gas volumes and 38% of anticipated North American gas volumes. At present, we maintain greater torque to oil prices, with 29% of our oil production hedged. We will continue to hedge the 2018 and 2019 periods as suitable opportunities arise.
Organizational Update
Mr. Jenson Tan, currently Director of Business Development, has been promoted to the position of Vice President of Business Development. Mr. Tan joined Vermilion in 2010 and has over 15 years of technical and management experience in international oil and gas. Business development has been a particular strength of Vermilion, and Mr. Tan has played a key role in a number of our important transactions in France, Netherlands, Germany, Canada, Central and Eastern Europe and, most recently, in Ireland. Mr. Tan has a Bachelor of Science degree in Petroleum Engineering from the University of Texas.
(signed "Anthony Marino")
Anthony Marino
President & Chief Executive Officer
October 26, 2017
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Eesveen-02 Zechstein 2 carbonate flow test was performed over a two hour period at a wellhead pressure of 1,290 psi with flow rates of 8.3 mmcf/d net and the Eesveen-02 Rotliegend sandstone flow test was performed over a 10 day period at a wellhead pressure of 2,360 psi with flow rates of 10 mmcf/d net resulting in combined production in excess of 18 mmcf/d net to Vermilion. These test results are not necessarily indicative of long-term performance of ultimate recovery. |
GUIDANCE
On October 31, 2016, we released our 2017 capital expenditure guidance of $295 million and associated production guidance of between 69,000-70,000 boe/d. On July 26, 2017 we announced an increase in our capital expenditure guidance from $295 million to $315 million following the acceleration of 2018 activities in our Canadian business unit. We also adjusted our 2017 annual production guidance on October 30, 2017 to 68,000-69,000 boe/d to reflect an extended downtime period following a plant turnaround at our Corrib asset in Ireland.
We released our 2018 capital budget and related guidance concurrent with the release of our Q3 2017 results.
The following table summarizes our guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | ||
2017 Guidance |
||||
2017 Guidance |
October 31, 2016 |
295 |
69,000 to 70,000 | |
2017 Guidance |
July 26, 2017 |
315 |
69,000 to 70,000 | |
2017 Guidance |
October 30, 2017 |
315 |
68,000 to 69,000 | |
2018 Guidance |
||||
2018 Guidance |
October 30, 2017 |
315 |
74,500 to 76,500 |
CONFERENCE CALL AND AUDIO WEBCAST DETAILS
Vermilion will discuss these results in a conference call to be held on Monday October 30, 2017 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 83587949 . The replay will be available until midnight mountain time on November 13, 2017.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=1504689&s=1&k=ED9536745788B34E97020409EBE1B0A2 or visit Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated
SOURCE Vermilion Energy Inc.
CALGARY, Oct. 16, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on November 15, 2017 to all shareholders of record on October 31, 2017. The ex-dividend date for this payment is October 30, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Sept. 15, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on October 16, 2017 to all shareholders of record on September 29, 2017. The ex-dividend date for this payment is September 28, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.0%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Aug. 15, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on September 15, 2017 to all shareholders of record on August 31, 2017. The ex-dividend date for this payment is August 29, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, July 17, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on August 15, 2017 to all shareholders of record on July 28, 2017. The ex-dividend date for this payment is July 26, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
TORONTO and CALGARY, July 12, 2017 /PRNewswire/ - Canada Pension Plan Investment Board ("CPPIB") and Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) are pleased to announce a strategic partnership in the Corrib Natural Gas Field in Ireland ("Corrib"), whereby CPPIB will acquire Shell Exploration Company B.V.'s ("Shell") 45% interest in the project, with Vermilion operating the assets after completion of the acquisition. Through its wholly owned subsidiary, CPP Investment Board Europe S.a.r.l., CPPIB has entered into a definitive purchase and sale agreement with Shell, to acquire 100% of Shell E&P Ireland Limited ("SEPIL"), which holds Shell's 45% interest in Corrib (the "Acquisition") for total cash consideration of €830 million, subject to customary closing adjustments and future contingent value payments based on performance and realized pricing. The Acquisition, which remains subject to customary conditions and receipt of all necessary government consents, has an effective date of January 1, 2017 with closing anticipated in the first half of 2018.
At closing, Vermilion will assume operatorship, and CPPIB plans to transfer SEPIL along with a 1.5% working interest to Vermilion for €19.4 million (before closing adjustments).
Following the transfer to Vermilion, ownership in Corrib would be as follows:
The transaction also contemplates two contingent payments; one linked to price and one linked to produced volumes:
Corrib is located 83 kilometers off the northwest coast of Ireland. The field has a gross plant capacity of approximately 350 million cubic feet of natural gas per day, provides approximately 60% of Ireland's natural gas consumption and constitutes approximately 95% of Ireland's gas production.
Avik Dey, Managing Director and Head of Natural Resources at CPPIB said, "Ireland is an attractive destination for a long-term investor like CPPIB, and through this investment in the Corrib gas field, we are able to further our strategy of investing in high-quality natural resources assets alongside highly regarded and experienced operating partners such as Vermilion. Vermilion has a strong operational track record in both onshore and offshore projects and we look forward to working with them and are confident that this investment will benefit the CPP Fund by delivering strong risk-adjusted returns over the long-term horizon of the Fund."
Anthony Marino, President and CEO of Vermilion said, "We welcome CPPIB as a strategic partner in this world-class gas field, and we look forward to a productive long-term relationship. Our ownership in Corrib and investment in Ireland date back to 2009, and we are proud to be a part of the energy industry in this stable jurisdiction. Our extensive experience in Europe, North America and Australia over our 23-year history will serve us well in Corrib. We look forward to working with SEPIL employees and Corrib stakeholders to implement our best-in-class approach to safety, environmental protection and strategic community investment."
Pro forma for the transfer of SEPIL from CPPIB, Vermilion's incremental 1.5% ownership of Corrib would represent approximately 850 boe/d at current production rates and approximately 2.0 million boe of 2P reserves(1) based on an independent evaluation by GLJ Petroleum Consultants Ltd. with an effective date of December 31, 2016. Assuming a purchase price of €19.4 million ($28.4 million at current exchange rates), before closing adjustments, the transaction metrics are estimated at approximately $33,400 per boe per day, $15.40 per boe of proved plus probable reserves(1) including future development capital (generating a 2P recycle ratio of 1.9 times based on projected 2017 netbacks), and 3.3 times estimated 2017 operating cash flow(2) using the current forward commodity strip. Vermilion expects the acquisition to be accretive for all pertinent per share metrics including production, fund flows from operations(2), reserves and net asset value. Vermilion intends to fund this acquisition with existing credit facilities.
The acquisition would significantly increase Vermilion's degree of operating control of its asset base. Following the assumption of operatorship of Corrib, Vermilion estimates that it will operate 87% of its production base as compared to 72% currently.
About Canada Pension Plan Investment Board
Canada Pension Plan Investment Board (CPPIB) is a professional investment management organization that invests the funds not needed by the Canada Pension Plan (CPP) to pay current benefits on behalf of 20 million contributors and beneficiaries. In order to build a diversified portfolio of CPP assets, CPPIB invests in public equities, private equities, real estate, infrastructure and fixed income instruments. Headquartered in Toronto, with offices in Hong Kong, London, Luxembourg, Mumbai, New York City, São Paulo and Sydney, CPPIB is governed and managed independently of the Canada Pension Plan and at arm's length from governments. At March 31, 2017, the CPP Fund totalled $316.7 billion.
CPPIB's Natural Resources group focuses on direct private investments in the oil and gas, energy midstream, power and renewables, and metals and mining industries. The team invests directly in companies, strategic partnerships and direct resource interests with an investment size of $500 million or more. At March 31, 2017, the Natural Resources portfolio consisted of nine direct investments valued at $4.3 billion.
For more information about CPPIB, please visit www.cppib.com or follow us on LinkedIn or Twitter.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion currently holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, and the Netherlands. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
(1) Estimated proved plus probable and proved developed producing reserves attributable to the Assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated February 27, 2017 with an effective date of December 31, 2016.
(2) Non-standardized and non-GAAP financial measures: This news release includes references to certain financial measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). Fund flows from operations is a non-standardized financial measure that is calculated as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit and our ability to generate cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Free cash flow and operating cash flow are non-GAAP financial measures. Free cash flow is calculated as fund flows from operations less capital expenditures. Operating cash flow is calculated as fund flows from operations before general and administration expense, interest and income taxes. We consider free cash flow and operating cash flow to be key measures as they are used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures. For additional information on non-standardized and non-GAAP financial measures, please refer to the Management's Discussion and Analysis contained in Vermilion's 2016 Annual Report for the year ended December 31, 2016 available on SEDAR or at the Company's website (www.vermilionenergy.com).
DISCLAIMER
Certain statements included or incorporated by reference in this press release may constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this press release may include, but are not limited to:
Statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
SOURCE Vermilion Energy Inc.
CALGARY, June 15, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on July 17, 2017 to all shareholders of record on June 30, 2017. The ex-dividend date for this payment is June 28, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
We have discontinued the Premium DividendTM component of the Dividend Reinvestment Plan effective with the July 2017 dividend payment. Eligible shareholders who were previously enrolled in the Premium DividendTM component will receive the regular cash dividend on 100% of their shares.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of the fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, June 14, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce that our Board of Directors has approved the appointment of Mr. Stephen Larke to our Board of Directors.
Mr. Larke brings over 20 years of experience in energy capital markets, including research, sales, trading and equity finance. He is currently an Operating Partner and Advisory Board member with Azimuth Capital Management, an energy-focused private equity fund based in Calgary, Alberta. Prior to joining Azimuth, Mr. Larke was Managing Director and Executive Committee member with Peters & Co., an independent energy investment firm based in Calgary. Before Peters & Co., he was Vice-President and Director with TD Newcrest, serving in the role of energy equity analyst. Both at Peters & Co. and TD Newcrest, Mr. Larke received leading rankings in the Brendan Wood International survey of institutional investors. He holds a Bachelor of Commerce (Distinction) degree from the University of Calgary and the Chartered Financial Analyst designation.
During his career, Mr. Larke has worked closely with institutional investors to understand their objectives and generate outcomes that met their investment criteria. We look forward to adding his valuable experience to our Board of Directors.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors hold approximately 6.5% of the fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, May 12, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on June 15, 2017 to all shareholders of record on May 23, 2017. The ex-dividend date for this payment is May 18, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
We commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016, and announced a further 25% proration starting with the dividend paid on January 17, 2017. We have increased the proration factor by a further 25% beginning with the April 17, 2017 dividend payment. Eligible shareholders who have elected to participate in the Premium DividendTM component will receive a 1.5% premium on 25% of their participating shares, and the regular cash dividend on the remaining 75% of their shares. We plan to discontinue the Premium DividendTM component beginning with the July 2017 dividend payment, such that there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Employees and directors of Vermilion hold approximately 6.5% of the fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, April 28, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion" or "Company") (TSX, NYSE: VET) is pleased to report that at its annual meeting of shareholders held on April 28, 2017 each of the ten nominees were elected as directors of the Company. The detailed results of the vote by ballot are as follows:
Votes for |
Votes Withheld | |||
Number |
Percent (%) |
Number |
Percent (%) | |
Larry J. Macdonald |
74,469,081 |
95.88 |
3,200,484 |
4.12 |
Lorenzo Donadeo |
74,897,422 |
96.43 |
2,772,143 |
3.57 |
Loren M. Leiker |
77,615,385 |
99.93 |
54,180 |
0.07 |
William F. Madison |
76,693,423 |
98.74 |
976,142 |
1.26 |
Dr. Timothy R. Marchant |
77,619,656 |
99.94 |
49,909 |
0.06 |
Anthony Marino |
76,843,016 |
98.94 |
826,549 |
1.06 |
Robert Michaleski |
77,620,230 |
99.94 |
49,335 |
0.06 |
Sarah E. Raiss |
77,306,160 |
99.53 |
363,405 |
0.47 |
William Roby |
77,669,565 |
100.00 |
0 |
0.00 |
Catherine L. Williams |
76,776,548 |
98.85 |
893,017 |
1.15 |
For complete voting results, please see our Report of Voting Results available through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, April 28, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three months ended March 31, 2017.
The unaudited financial statements and management discussion and analysis for the three months ended March 31, 2017, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
HIGHLIGHTS
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Well A (Ellerslie) production test was performed over a 2-day period. The maximum choke size during the production test was 24.7mm. Well A achieved a peak burnable gas production rate of 9.1 mmcf/d with a stabilized rate of 8.0 mmcf/d. Well A also achieved a peak liquids production rate of 375 bbls/d with a stabilized rate of 190 bbls/d. Well B (Ellerslie) production test was performed over a 2-day period. The maximum choke size during the production test was 21.3mm. Well B achieved a peak burnable gas production rate of 3.3 mmcf/d with a stabilized rate of 2.8 mmcf/d. Well B also achieved a peak liquids production rate of 690 bbls/d with a stabilized rate of 535 bbls/d. These test results are not necessarily indicative of long-term performance or of ultimate recovery. |
TM |
Denotes trademark of Canaccord Genuity Capital Corporation |
HIGHLIGHTS |
|||||
Three Months Ended |
|||||
($M except as indicated) |
Mar 31, |
Dec 31, |
Mar 31, |
||
Financial |
2017 |
2016 |
2016 |
||
Petroleum and natural gas sales |
261,601 |
259,891 |
177,385 |
||
Fund flows from operations |
143,434 |
149,582 |
93,667 |
||
Fund flows from operations ($/basic share) (1) |
1.21 |
1.27 |
0.83 |
||
Fund flows from operations ($/diluted share) (1) |
1.19 |
1.25 |
0.82 |
||
Net earnings (loss) |
44,540 |
(4,032) |
(85,848) |
||
Net earnings (loss) ($/basic share) |
0.38 |
(0.03) |
(0.76) |
||
Capital expenditures |
95,889 |
66,882 |
62,773 |
||
Acquisitions |
2,620 |
78,713 |
870 |
||
Asset retirement obligations settled |
2,249 |
3,327 |
2,024 |
||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 |
||
Dividends declared |
76,593 |
76,096 |
72,847 |
||
% of fund flows from operations |
53% |
51% |
78% |
||
Net dividends (1) |
41,087 |
32,516 |
24,857 |
||
% of fund flows from operations |
29% |
22% |
27% |
||
Payout (1) |
139,225 |
102,725 |
89,654 |
||
% of fund flows from operations |
97% |
69% |
96% |
||
Net debt |
1,377,636 |
1,427,148 |
1,367,063 |
||
Ratio of net debt to annualized fund flows from operations |
2.4 |
2.4 |
3.6 |
||
Operational |
|||||
Production |
|||||
Crude oil and condensate (bbls/d) |
26,832 |
25,972 |
29,199 |
||
NGLs (bbls/d) |
2,694 |
2,467 |
2,672 |
||
Natural gas (mmcf/d) |
210.07 |
194.54 |
201.11 |
||
Total (boe/d) |
64,537 |
60,863 |
65,389 |
||
Average realized prices |
|||||
Crude oil, condensate and NGLs ($/bbl) |
64.14 |
60.58 |
39.35 |
||
Natural gas ($/mcf) |
5.62 |
5.47 |
3.76 |
||
Production mix (% of production) |
|||||
% priced with reference to WTI |
17% |
18% |
20% |
||
% priced with reference to AECO |
22% |
20% |
25% |
||
% priced with reference to TTF and NBP |
32% |
33% |
26% |
||
% priced with reference to Dated Brent |
29% |
29% |
29% |
||
Netbacks ($/boe) |
|||||
Operating netback (1) |
31.62 |
31.11 |
21.63 |
||
Fund flows from operations netback |
25.75 |
26.43 |
16.12 |
||
Operating expenses |
9.35 |
10.54 |
9.58 |
||
Average reference prices |
|||||
WTI (US $/bbl) |
51.92 |
49.29 |
33.45 |
||
Edmonton Sweet index (US $/bbl) |
48.37 |
46.18 |
29.76 |
||
Dated Brent (US $/bbl) |
53.78 |
49.46 |
33.89 |
||
AECO ($/mmbtu) |
2.69 |
3.09 |
1.83 |
||
NBP ($/mmbtu) |
7.96 |
7.51 |
5.97 |
||
TTF ($/mmbtu) |
7.65 |
7.21 |
5.70 |
||
Average foreign currency exchange rates |
|||||
CDN $/US $ |
1.32 |
1.33 |
1.37 |
||
CDN $/Euro |
1.41 |
1.44 |
1.52 |
||
Share information ('000s) |
|||||
Shares outstanding - basic |
119,046 |
118,263 |
113,451 |
||
Shares outstanding - diluted (1) |
122,135 |
121,353 |
116,491 |
||
Weighted average shares outstanding - basic |
118,632 |
117,840 |
112,725 |
||
Weighted average shares outstanding - diluted (1) |
120,722 |
119,677 |
114,110 |
(1) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
MESSAGE TO SHAREHOLDERS
In early April, Vermilion held an investor day in Paris, France to provide investors and analysts with an opportunity to learn more about our company's strategy and global asset portfolio. The event featured presentations from members of our executive team and senior leaders from each of Vermilion's business units. Our Investor Day was designed to achieve three main objectives: provide a more detailed description of our assets and projects; demonstrate the technical and management capabilities of Vermilion's global operations leadership team; and emphasize the similarity of our overseas operations to North American operations through a field tour of our Paris Basin assets. A copy of the Investor Day presentation and a replay of the webcast is available on our website at http://www.vermilionenergy.com/ir/eventspresentations.cfm.
It was fitting that Vermilion's first Investor Day event in nearly seven years coincided with the 20th anniversary of our first international acquisition. It was in 1997 that Vermilion took the innovative step of expanding internationally by acquiring producing properties in France. Since then, we have continued to strengthen and diversify our global asset portfolio, maintaining a disciplined focus on our three core regions of North America, Europe and Australia. As was demonstrated throughout our Investor Day event, Vermilion's diversification has played a key role in our historical success and remains instrumental to our growth-and-income model in the future.
Project Inventory Diversity
Vermilion's diversified inventory of conventional and semi-conventional projects provides several competitive advantages for our company. Diversification in commodity and price exposures allows us to select and invest in those projects that will generate the highest return for a given commodity price environment. In addition, our focus on conventional and semi-conventional projects results in lower production decline rates as compared to our North American competitors that focus on shales or other ultra-tight reservoirs. These lower decline rates significantly reduce our ongoing capital requirements and directly support the sustainability of our growth-and-income model. At the same time, we continue to apply the best worldwide drilling and completion technologies to our conventional and semi-conventional assets to further enhance our rates of return. While we are focused on conventional and semi-conventional projects, our inventory depth is more typical of an unconventional producer. We have greatly expanded our project inventory over the past five years and it is stronger now than at any point in Vermilion's history.
After more than two years of depressed industry activity, we are starting to see a modest recovery in activity levels as global oil markets begin to rebalance. While this increased activity will lead to service cost reflation, we expect this to have less impact on Vermillion than our competitors. A majority of our capital is directed to assets outside of North America where the services sector has not been exposed to severe boom-and-bust cycles. As such, cost escalation pressures on our international operations are expected to be less significant. Further, our semi-conventional asset base in North America requires significantly less sand, water and horsepower intensity in completions as compared to our shale and ultra-tight focused competitors. As a result, we have relatively less exposure to the pressure pumping services segment, where services price reflation is expected to be most significant.
Capital Investment and Production Source Flexibility
Our diversification provides significant flexibility to reallocate capital and production amongst business units as required to meet corporate targets. This flexibility was recently demonstrated through the reallocation of 2017 capital and production targets due to the permitting delays in the Netherlands noted in our year-end 2016 release and Investor Day materials. As discussed in the European Review section below, we now project that these permitting delays will result in the deferral of nearly 3,000 boe/d of Netherlands production for 2017 versus our original plan. In response, we have reallocated a modest amount of additional capital from the Netherlands to Canada and intend to offset this current-year permitting-related production shortfall through increased production in other jurisdictions, primarily Canada and Australia. Our expectation to maintain our 2017 production guidance of 69,000 – 70,000 boe/d despite the impact of these permitting delays, and without increasing consolidated exploration and development ("E&D") capital, demonstrates a key advantage of our diversification as well as the operational strength of our company.
Risk Reduction and Premium Pricing
Our global asset portfolio provides commodity diversification and premium pricing. Commodity diversification reduces risk for our shareholders by increasing the stability of our cash flows and providing additional hedging options. Approximately 55% of our oil-equivalent 2017 estimated production is priced with reference to Dated Brent and European natural gas benchmarks. These commodities continue to trade at significant premiums as compared to their North American counterparts, improving our margins. Our commodity exposure advantages, coupled with our focus on cost management, have allowed Vermilion to consistently deliver top quartile netbacks within our peer group.
Summary
Vermilion's diversification has been a key element of our historical success and consistent record of market outperformance. Our global asset portfolio generates significant free cash flow(1), while at the same time delivering consistent production growth, allowing us to sustainably deliver our growth-and-income model for our shareholders. Our focus on three core regions, managed within a decentralized business unit structure with a highly capable leadership team, allows us to focus our efforts and effectively manage our global asset base. In each region, we are a very technically-focused company that continues to add real value through high quality technical work and careful execution of our projects.
Q1 2017 Review
Vermilion's first quarter production increased by 6% to 64,537 boe/d from 60,863 boe/d in the prior quarter. This increase was primarily attributable to higher volumes in Canada related to the resumption of voluntarily curtailed production and organic growth from development activities, as well as incremental volumes from our German acquisition which closed near the end of last year. We expect production volumes to continue increasing throughout 2017 with production volumes averaging between 69,000 to 70,000 boe/d for the year.
Fund flows from operations ("FFO") for Q1 2017 was $143.4 million ($1.21/basic share(1)) as compared to $149.6 million ($1.27/basic share) in Q4 2016. This 4% decrease in FFO quarter-over-quarter is primarily attributable to a significant inventory build in France and Australia related to shipment timing. The pre-tax FFO impact of the quarter-over-quarter change in inventory levels was approximately $15.5 million. Based on anticipated shipment schedules, we expect that this inventory build will reverse over the course of the year, unwinding the FFO impact. Year-over-year, FFO increased by 53% as compared to Q1 2016 as a result of significantly higher commodity prices. Vermilion generated net earnings of $44.5 million ($0.38/basic share) during the first quarter, representing a return to positive net income for the first time since Q2 2015.
While commodity prices have increased from the lows experienced in 2016, we continue to maintain our strict focus on cost management. Per-unit operating expense of $9.35 per boe decreased by 11% during Q1 2017 as compared to the prior quarter and by 2% as compared to the year-earlier quarter.
During the quarter, we issued US$300 million of eight-year senior unsecured notes at a coupon of 5.625% per annum. This issuance was completed by way of a private offering and represented Vermilion's first issuance in the US debt markets. Despite Vermilion's first-time issuer status, we were able to secure a very attractive interest rate, reflecting our track record of prudent fiscal management. The issuance of US dollar denominated debt provides a natural hedge against our largely US dollar denominated revenue streams. Subsequent to the quarter, we negotiated an extension of our credit facility with our banking syndicate to May 2021. As a result of our projected liquidity requirements and the proceeds from this debt issuance, we elected to reduce our bank facility to $1.4 billion from $2.0 billion.
Effective with the April 2017 dividend payment, the allowable participation in the Premium DividendTM Component of our Premium DividendTM and Dividend Reinvestment Plan is now being prorated by 75%. As such, eligible shareholders who have elected to participate in the Premium DividendTM Component now receive a 1.5% premium on 25% of their participating shares, and the regular cash dividend on the remaining 75% of their shares. We plan to discontinue the Premium DividendTM Component of our Premium DividendTM and Dividend Reinvestment Plan beginning with the July 2017 dividend payment, such that there would be no further equity issuance under this program. We also reduced the discount associated with the traditional component of our Premium DividendTM and Dividend Reinvestment Plan from 3% to 2% beginning with the January 2017 dividend.
Europe
Production from Corrib averaged 64.8 mmcf/d (10,803 boe/d) in Q1 2017, representing 100% of rated plant capacity. The project has continued to outperform expectations for well deliverability and downtime. Due to expected higher recovery efficiency resulting from better well-to-well communication, we have adjusted our field and well performance estimates, and now expect to maintain peak production plateau through Q1 2018 and potentially into Q2 2018. Corrib is a highly efficient generator of free cash flow as a result of its highly-valued European gas product, absence of royalties, low operating expense, and low maintenance capital requirements.
In France, we drilled and completed our first wells in the Neocomian fields during Q1 2017. Initial results from this four (4.0 net) horizontal well program are highly encouraging. The first well was placed on production in early March and delivered an IP30 rate of 250 bbls/d versus our type curve expectations of 110 bbls/d. The second well, which only has a completed horizontal section of 40% of the anticipated length due to drilling problems, was placed on production in late March at a rate of approximately 50 bbls/d at low drawdown during the initial production phase. The production rate from this well is expected to increase as pump displacement and drawdown are turned up over time. The remaining two wells have now been successfully drilled and cased with slotted liner through the full horizontal section targeted. Reservoir quality indications from these two wells were positive, and we expect to have them on production during the second quarter. During the first quarter, we also completed and placed on production the four (4.0 net) Champotran wells we drilled in France in Q4 2016. All wells are productive, with two exceeding expectations, and two below. The combined IP30 oil rate from the four wells was 550 bbls/d. Lastly, we drilled and placed a Vulaines horizontal sidetrack well on production during the quarter. The well delivered an IP30 rate of 90 bbls/d prior to finishing the completion by acidizing the horizontal lateral. Our ability to successfully execute a sidetracked horizontal lateral in Vulaines creates the opportunity for higher productivity multi-lateral horizontal development from existing wellbores.
As noted previously, permitting delays in the Netherlands have resulted in a reallocation of capital and production targets amongst business units. Due to the delays in receiving final production permits for three of our wells, two wells are now producing at significantly restricted rates and a third well has been shut-in. While we believe the final production permits for one of the wells will be received in 2017, we do not currently expect to receive the permits for the other two wells until 2018. As such, we have reduced our full year 2017 average production forecast for the Netherlands to approximately 6,500 boe/d. This compares to our initial 2017 Netherlands production plan of 9,400 boe/d which reflected our prior permitting timeline assumptions. We intend to offset lower Netherlands volumes through increased production in other jurisdictions, primarily Canada and Australia, and have made no changes to our 2017 guidance targets for consolidated production or E&D capital. In the Netherlands, two (1.0 net) wells that were in our original budget have been postponed and we have deferred the completion activities for the remaining two (1.0 net) exploration wells that we intend to drill this year to 2018. In addition, we have reduced the scope of our planned seismic program in the Akkrum exploration concession. Further information on these changes is included in our May 2017 investor presentation available on our website. We expect the curtailed Netherlands volumes to be available for production during 2018.
In Germany, Vermilion assumed operatorship of the assets acquired near the end of 2016 from Engie E&P Deutschland GmbH. Production from the acquired assets averaged approximately 2,000 boe/d during the quarter. Vermilion commenced service rig operations on the acquired assets in February, and we have developed a work plan to implement identified optimization and workover projects. In March 2017, we were awarded an exploration license in Lower Saxony comprising 150,000 gross acres (50,000 acres net to Vermilion) surrounding the acquired oil fields. The Engie acquisition, our assumption of production operatorship and the additional exploration acreage further advance our objective of developing a material business unit in Germany.
North America
In Canada, capital activity increased significantly during the first quarter as compared to Q1 of the prior year. During Q1 2017, we drilled or participated in seven (5.1 net) Mannville wells, five (5.0 net) Cardium wells and 10 (8.3 net) Midale wells. Eleven (7.1 net) Mannville wells, two (2.0 net) Cardium wells and eight (7.0 net) Midale wells were brought on production. Individual well results from our Q1 2017 Mannville program exceeded our expectations with the majority displaying test productivity significantly above our average well performance to-date. Lower Mannville wells tested during the quarter(2) include one well that tested at 8.0 mmcf/d with 190 bbls/d of free liquids, and a second well at 2.8 mmcf/d with 535 bbls/d of free liquids. Based on early stage production results, oil rates from our Cardium and Midale wells are in-line with expectations while cost efficiencies continue to improve. Cardium Drill, Complete, Equip and Tie-in (DCET) well costs averaged $2.3 million on a per-section basis for Q1 2017 as compared to $3.2 million during our last program in 2014. Per well costs for our Midale play decreased to $1.7 million during Q1 2017 from $3.0 million in 2014. These improvements largely resulted from an approximately 30% decrease in required drilling days achieved during the quarter as compared to the start in the Midale play in 2014. The last five wells at the end of the Q1 2017 program achieved a further 25% reduction in drilling days. During Q1, we also continued to advance an infrastructure project supporting the continued growth of our Upper Mannville development in the Ferrier area. We plan to start the construction of a 14 mmcf/d compressor station in Q4 2017 with start-up scheduled for Q2 2018.
In the United States, we drilled three (3.0 net) wells in our early stage Turner Sand play during the quarter. The Q1 2017 program was designed to establish consistent drilling and completion procedures while reducing drilling times and overall capital costs. Drilling times were reduced to 12 days from the previous 18 day average despite an approximately 20% increase in average lateral length. Based on currently available data, while recognizing that some additional completion costs may still be incurred on the new wells, we project that the per well drilling and completion capital cost was reduced by approximately 25% from the previous program. Two of the three wells have been completed and were placed on production in late March, while the third well is expected to be on production by late April. The first two wells have been produced intermittently so far, with initial production performance that is comparable to the better wells drilled thus far in our East Finn project area. During Q1 2017, we purchased overriding royalty interests on our lands (ranging from 0.83% to 5%) for US$1.5 million, further consolidating our position and enhancing our play economics.
Australia
Activities in Australia were largely centered around our debottlenecking project to further improve fluid handling capability on the Wandoo B platform. Once completed, we expect that this infrastructure enhancement will allow us to increase oil production on the platform by 600 to 700 bbls/d later in 2017. The two sidetrack wells we drilled in Q2 2016 continue to exhibit strong productive capability. When utilized, combined oil production from these wells was approximately 4,000 bbls/d during Q1 2017. These wells are produced intermittently to achieve business unit targets and meet oil sales contract commitments. We do not expect to drill additional wells in Australia until 2019.
Environmental, Social & Governance
Vermilion was recently ranked 13th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list. This marks the fourth year in a row that Vermilion has been recognized by Corporate Knights as one of Canada's top sustainability performers. Vermilion continues to be the highest rated oil and gas company on the list. This recognition reflects our strong focus on sustainability, transparency and performance regarding environmental, social and governance issues.
Board of Directors
Vermilion recently announced that Mr. William Roby will be appointed to the Board of Directors effective April 26, 2017. Mr. Roby brings 33 years of experience in various senior management and executive positions primarily from a number of US and international management positions with Occidental Petroleum Corporation from 1997 to 2013, most recently as Senior Vice President, Worldwide Operations and Production/Facility Engineering. From 2013 to 2014, he acted as Chief Operating Officer of Sheridan Production Company, LLC, a Houston based oil and gas company. Mr. Roby holds a Bachelor of Mechanical Engineering degree from Louisiana State University.
In addition, Mr. Claudio Ghersinich has advised that he will not be standing for re-election to Vermilion's Board in 2017. Mr. Ghersinich has been a director of Vermilion since 1994. He was one of the three co-founders of Vermilion and served most recently as Executive Vice President, Business Development from 2005 to 2008. Mr. Ghersinich was a key contributor to Vermilion's success, and on behalf of Vermilion's management and Board of Directors, we wish to thank him for his contributions to Vermilion, the Board, Audit and Independent Reserves Committees. We wish Claudio the very best in his future endeavours.
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Well A (Ellerslie) production test was performed over a 2-day period. The maximum choke size during the production test was 24.7mm. Well A achieved a peak burnable gas production rate of 9.1 mmcf/d with a stabilized rate of 8.0 mmcf/d. Well A also achieved a peak liquids production rate of 375 bbls/d with a stabilized rate of 190 bbls/d. Well B (Ellerslie) production test was performed over a 2-day period. The maximum choke size during the production test was 21.3mm. Well B achieved a peak burnable gas production rate of 3.3 mmcf/d with a stabilized rate of 2.8 mmcf/d. Well B also achieved a peak liquids production rate of 690 bbls/d with a stabilized rate of 535 bbls/d. These test results are not necessarily indicative of long-term performance or of ultimate recovery. |
TM |
Denotes trademark of Canaccord Genuity Capital Corporation |
2017 GUIDANCE
On October 31, 2016, we released our 2017 capital expenditure guidance of $295 million and associated production guidance of between 69,000-70,000 boe/d.
The following table summarizes our guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | ||
2017 Guidance |
||||
2017 Guidance |
October 31, 2016 |
295 |
69,000 to 70,000 |
ANNUAL GENERAL MEETING WEBCAST
As Vermilion's Annual General Shareholders Meeting is being held today, April 28th, 2017 at 10:00 AM MST at the Metropolitan Centre, 333 – 4th Avenue S.W., Calgary, Alberta, there will not be a first quarter conference call. In lieu of the conference call, a presentation will be given by Mr. Anthony Marino, President & Chief Executive Officer at the end of the meeting. Questions from the public can be submitted via the webcast.
Please visit http://event.on24.com/r.htm?e=1408430&s=1&k=69B66BC77507314039EFD37F8972FC98 or Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm and click on webcast under the upcoming events to view the webcast which will commence at approximately 10:15 AM MST.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
SOURCE Vermilion Energy Inc.
CALGARY, April 13, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on May 15, 2017 to all shareholders of record on April 24, 2017. The ex-dividend date for this payment is April 20, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
We commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016, and announced a further 25% proration starting with the dividend paid on January 17, 2017. We have increased the proration factor by a further 25% beginning with the April 17, 2017 dividend payment. Eligible shareholders who have elected to participate in the Premium DividendTM component will receive a 1.5% premium on 25% of their participating shares, and the regular cash dividend on the remaining 75% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to discontinue the Premium DividendTM component beginning with the July 2017 dividend payment, such that there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
DIRECTOR APPOINTMENT
Vermilion is pleased to announce that Mr. William Roby will be appointed to the Board of Directors effective April 26, 2017.
Mr. Roby brings 33 years of experience in various senior management and executive positions primarily from a number of U.S. and international management positions with Occidental Petroleum Corporation from 1997 to 2013, most recently as Senior Vice President, Worldwide Operations and Production/Facility Engineering. From 2013 to 2014, he acted as Chief Operating Officer of Sheridan Production Company, LLC, a Houston based oil and gas company with production in excess of 50,000 boe/d. Mr. Roby holds a Bachelor of Mechanical Engineering degree from Louisiana State University.
Mr. Roby will be included as a nominee for election as a director of Vermilion at our upcoming annual general meeting of shareholders to be held on Friday, April 28, 2017 at 10:00 am MDT (the "Meeting"). As the appointment of Mr. Roby was not determined as of the mailing of Vermilion's notice of meeting, proxy statement and information circular dated March 22, 2017 (the "Circular"), the Circular included fixing the number of directors to be elected as nine and set forth nine nominees for election as directors. At the Meeting shareholders will be asked to approve a resolution fixing the number of directors to be elected at ten, and a resolution to elect each of the nominees set forth in the Circular and Mr. Roby as directors of Vermilion. Vermilion recommends to fix the number of directors to be elected at the Meeting at ten, and that shareholders elect the nominees named in the Circular and Mr. Roby as directors of Vermilion. Mr. Roby does not currently own any common shares of Vermilion.
We look forward to the contributions that Mr. Roby will make to our Board of Directors and to the ongoing success of Vermilion.
In addition, Mr. Claudio Ghersinich has advised that he will not be standing for re-election to Vermilion's Board in 2017. Mr. Ghersinich has been a director of Vermilion since 1994. He was one of the three co-founders of Vermilion and served most recently as Executive Vice President, Business Development from 2005 to 2008. Mr. Ghersinich was a key contributor to Vermilion's success and we wish to thank him for his contributions to Vermilion, the Board, Audit and Independent Reserves Committees. On behalf of the entire management and board of directors of Vermilion, we would like to thank Mr. Ghersinich for his significant contributions to Vermilion's success over the years, and we wish him the best in his future endeavours.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, March 30, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) will hold an Investor Day in Paris, France on Thursday, April 6, 2017 starting at 8:30AM CET (12:30AM MST). The event will feature presentations by senior management and leaders from all of Vermilion's business units, providing an overview of our corporate strategy and global asset portfolio.
This event will be webcast live and an archived version of the webcast will be available beginning on Friday, April 7, 2017 for approximately 90 days. To access the audio webcast and presentation slides please visit Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, March 13, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion" or the "Company") (TSX, NYSE: VET) announces the closing of its previously announced private offering of US$300 million senior unsecured notes due 2025 (New Notes). The New Notes have a fixed coupon of 5.625% per annum, to be paid semi-annually on March 15 and September 15, commencing September 15, 2017. The company intends to use the net proceeds from the New Notes to repay a portion of the debt outstanding on its revolving credit facility.
The New Notes have not been and will not be registered under the Securities Act of 1933, as amended ("U.S. Securities Act"), or applicable state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the U.S. Securities Act and applicable state securities laws. The New Notes have not been and will not be qualified for sale to the public under applicable Canadian securities laws and, accordingly, any offer and sale of the New Notes in Canada will be made on a basis which is exempt from the prospectus requirements of such securities laws. Pursuant to the terms of the offering, the New Notes will be offered and sold only on a prospectus-exempt basis to institutional "accredited investors" in certain provinces in Canada and, in the United States, will be offered and sold only to "qualified institutional buyers" in reliance on Rule 144A under the U.S. Securities Act and to certain non-U.S. persons in transactions outside the United States in reliance on Regulation S under the U.S. Securities Act.
This press release does not constitute an offer to sell or the solicitation of an offer to buy any security in any jurisdiction and shall not constitute an offer, solicitation or sale of any securities in any jurisdiction in which such offering, solicitation or sale would be unlawful.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland.
SOURCE Vermilion Energy Inc.
CALGARY, March 10, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on April 17, 2017 to all shareholders of record on March 22, 2017. The ex-dividend date for this payment is March 20, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
We commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016, and announced a further 25% proration starting with the dividend paid on January 17, 2017. We have increased the proration factor by a further 25% beginning with the April 17, 2017 dividend payment. Eligible shareholders who have elected to participate in the Premium DividendTM component will receive a 1.5% premium on 25% of their participating shares, and the regular cash dividend on the remaining 75% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to discontinue the Premium DividendTM component beginning with the July 2017 dividend payment, such that there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
™denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, March 1, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) announces its intention to issue up to US$300 million aggregate principal amount of 8 year senior unsecured notes (New Notes) in a private offering, subject to market and other conditions. The company intends to use the net proceeds from the New Notes to repay a portion of the debt outstanding on its revolving credit facility.
The New Notes have not been and will not be registered under the Securities Act of 1933, as amended ("U.S. Securities Act"), or applicable state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the U.S. Securities Act and applicable state securities laws. The New Notes have not been and will not be qualified for sale to the public under applicable Canadian securities laws and, accordingly, any offer and sale of the New Notes in Canada will be made on a basis which is exempt from the prospectus requirements of such securities laws. Pursuant to the terms of the offering, the New Notes will be offered and sold only on a prospectus-exempt basis to institutional "accredited investors" in certain provinces in Canada and, in the United States, will be offered and sold only to "qualified institutional investors" in reliance on Rule 144A under the U.S. Securities Act and to certain non-U.S. persons in transactions outside the United States in reliance on Regulation S under the U.S. Securities Act.
This press release does not constitute an offer to sell or the solicitation of an offer to buy any security in any jurisdiction and shall not constitute an offer, solicitation or sale of any securities in any jurisdiction in which such offering, solicitation or sale would be unlawful.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland.
Forward-looking statements
Certain statements included in this press release may constitute forward-looking statements or financial outlooks under applicable securities legislation, including but not limited to the potential for an offering and issuance of New Notes by Vermilion and the use of proceeds therefrom. Such forward-looking statements are based on a number of assumptions, all or any of which may prove to be incorrect. Although Vermilion believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements. The forward-looking statements contained in this press release are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
SOURCE Vermilion Energy Inc.
CALGARY, Feb. 27, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and audited financial results for the year ended December 31, 2016.
The audited financial statements and management discussion and analysis for the three months and year ended December 31, 2016, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
HIGHLIGHTS
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Estimated proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2017 with an effective date of December 31, 2016 (the "2016 GLJ Reserves Evaluation") |
(3) |
F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period. |
(4) |
Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(5) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2017 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2016 (the "GLJ 2016 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 25%, 26% and 26%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
(6) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ 2015 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 82% and 81%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
TM |
Denotes trademark of Canaccord Genuity Capital Corporation |
HIGHLIGHTS |
|||||||
Three Months Ended |
Year Ended | ||||||
($M except as indicated) |
Dec 31, |
Sep 30, |
Dec 31, |
Dec 31, |
Dec 31, | ||
Financial |
2016 |
2016 |
2015 |
2016 |
2015 | ||
Petroleum and natural gas sales |
259,891 |
232,660 |
234,319 |
882,791 |
939,586 | ||
Fund flows from operations |
149,582 |
140,974 |
136,441 |
510,791 |
516,167 | ||
Fund flows from operations ($/basic share) (1) |
1.27 |
1.21 |
1.22 |
4.41 |
4.71 | ||
Fund flows from operations ($/diluted share) (1) |
1.25 |
1.19 |
1.21 |
4.36 |
4.65 | ||
Net loss |
(4,032) |
(14,475) |
(142,080) |
(160,051) |
(217,302) | ||
Net loss ($/basic share) |
(0.03) |
(0.12) |
(1.28) |
(1.38) |
(1.98) | ||
Capital expenditures |
66,882 |
41,039 |
128,996 |
242,408 |
486,861 | ||
Acquisitions |
78,713 |
10,391 |
6,227 |
98,524 |
28,897 | ||
Asset retirement obligations settled |
3,327 |
2,066 |
4,921 |
9,617 |
11,369 | ||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 |
2.580 |
2.580 | ||
Dividends declared |
76,096 |
75,465 |
71,965 |
299,070 |
283,575 | ||
% of fund flows from operations |
51% |
54% |
53% |
59% |
55% | ||
Net dividends (1) |
32,516 |
24,553 |
25,201 |
106,072 |
128,542 | ||
% of fund flows from operations |
22% |
17% |
18% |
21% |
25% | ||
Payout (1) |
102,725 |
67,658 |
159,118 |
358,097 |
626,772 | ||
% of fund flows from operations |
69% |
48% |
117% |
70% |
121% | ||
Net debt |
1,427,148 |
1,343,923 |
1,381,951 |
1,427,148 |
1,381,951 | ||
Ratio of net debt to annualized fund flows from operations |
2.4 |
2.4 |
2.5 |
2.8 |
2.7 | ||
Operational |
|||||||
Production |
|||||||
Crude oil and condensate (bbls/d) |
25,972 |
27,842 |
31,304 |
27,852 |
30,408 | ||
NGLs (bbls/d) |
2,467 |
2,478 |
2,739 |
2,582 |
2,308 | ||
Natural gas (mmcf/d) |
194.54 |
199.66 |
162.09 |
198.55 |
133.24 | ||
Total (boe/d) |
60,863 |
63,596 |
61,058 |
63,526 |
54,922 | ||
Average realized prices |
|||||||
Crude oil, condensate and NGLs ($/bbl) |
60.58 |
53.24 |
51.64 |
51.73 |
58.80 | ||
Natural gas ($/mcf) |
5.47 |
3.98 |
4.55 |
4.18 |
4.98 | ||
Production mix (% of production) |
|||||||
% priced with reference to WTI |
18% |
19% |
22% |
19% |
25% | ||
% priced with reference to AECO |
20% |
20% |
24% |
22% |
22% | ||
% priced with reference to TTF and NBP |
33% |
32% |
20% |
30% |
19% | ||
% priced with reference to Dated Brent |
29% |
29% |
34% |
29% |
34% | ||
Netbacks ($/boe) |
|||||||
Operating netback(1) |
31.11 |
27.88 |
28.44 |
27.06 |
32.09 | ||
Fund flows from operations netback |
26.43 |
23.25 |
23.91 |
21.91 |
25.86 | ||
Operating expenses |
10.54 |
9.05 |
11.50 |
9.53 |
11.32 | ||
Average reference prices |
|||||||
WTI (US $/bbl) |
49.29 |
44.94 |
42.18 |
43.32 |
48.80 | ||
Edmonton Sweet index (US $/bbl) |
46.18 |
42.06 |
39.72 |
40.11 |
44.91 | ||
Dated Brent (US $/bbl) |
49.46 |
45.85 |
43.69 |
43.69 |
52.46 | ||
AECO ($/mmbtu) |
3.09 |
2.32 |
2.46 |
2.16 |
2.69 | ||
NBP ($/mmbtu) |
7.51 |
5.29 |
7.41 |
6.15 |
8.33 | ||
TTF ($/mmbtu) |
7.21 |
5.43 |
7.28 |
6.00 |
8.23 | ||
Average foreign currency exchange rates |
|||||||
CDN $/US $ |
1.33 |
1.31 |
1.34 |
1.33 |
1.28 | ||
CDN $/Euro |
1.44 |
1.46 |
1.46 |
1.47 |
1.42 | ||
Share information ('000s) |
|||||||
Shares outstanding - basic |
118,263 |
117,386 |
111,991 |
118,263 |
111,991 | ||
Shares outstanding - diluted (1) |
121,353 |
120,183 |
115,025 |
121,353 |
115,025 | ||
Weighted average shares outstanding - basic |
117,840 |
116,814 |
111,393 |
115,695 |
109,642 | ||
Weighted average shares outstanding - diluted (1) |
119,677 |
118,177 |
112,543 |
117,152 |
111,051 |
(1) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
MESSAGE TO SHAREHOLDERS
The past three years have been a challenging time for the oil and gas industry, with oil and gas prices both hitting multi-year lows in 2016. As a result, we took a very cautious approach last year, adjusting our capital program on several occasions to ensure that capital expenditures and cash dividends were fully funded by fund flows from operations. We achieved this while maintaining our dividend, and also delivered strong production and 2P reserves(1) growth of 16% (10% on a per share basis) and 11% (5% on a per share basis), respectively. We delivered these results while investing half the amount of capital compared to the prior year, and approximately one-third of the amount from two years ago. We believe that this successful adaptation to a "lower-for-longer" world illustrates both the quality of our asset base and the competence of our personnel. Our diversified asset base and global commodity exposure are two risk-reducing qualities that set Vermilion apart from many of our peers during the downturn.
Vermilion has always been disciplined in the management of its balance sheet, typically operating with leverage ratios below the industry average. We entered the commodity price downturn in a position of relative financial strength, and proactively took a number of actions in 2015 and 2016 to preserve our balance sheet. In 2016, our payout ratio for E&D capital and cash dividends was 70% of fund flows from operations. We have designed our 2017 and 2018 capital programs to provide for continued self-funded growth. At the current commodity strip price, we expect fund flows from operations to exceed the combined cost of E&D expenditures and cash dividends. In line with our conservative approach to managing our balance sheet, we have the flexibility to direct the resulting surplus cash to further debt reduction.
In early 2015 we amended our existing Dividend Reinvestment Plan ("DRIP") to include a Premium Dividend™ Component. The Premium Dividend™ Component expanded our access to the lowest cost source of equity capital available during a period of commodity price weakness and uncertainty. During Q4 2016, we began prorating the Premium DividendTM Component of our Premium DividendTM and Dividend Reinvestment Plan by 25%, and announced a further 25% proration starting with the January 2017 dividend payment. We plan to increase the proration factor by a further 25% beginning with the April 2017 dividend payment, so that eligible shareholders who have elected to participate in the Premium DividendTM Component will receive the 1.5% premium on 25% of their participating shares and the regular cash dividend on the remaining 75% of their shares. Subject to unexpected changes in the commodity price outlook, we plan to discontinue the Premium DividendTM Component beginning with the July 2017 dividend payment, such that there would be no further equity issuance under this program. We also reduced the discount associated with the traditional component of our Premium DividendTM and Dividend Reinvestment Plan from 3% to 2% beginning with the January 2017 payment. Our strategy aims to deliver consistent growth-and-income to our shareholders. These measures will reduce dilution, ensuring that value from future growth in production and cash flow more efficiently flows to our owners on a per-share-basis.
On a per unit basis, annual operating and G&A expenses decreased by 16% and 15% respectively, year-over-year, and are down 27% and 29% respectively over the past five years. Since implementing our Profitability Enhancement Plan ("PEP") in November 2014, we have realized over $160 million in cost savings across our business, including over $70 million achieved in 2016. It is our intent to embed these PEP cost reductions in our ongoing operations. As a result, we are discontinuing our formal PEP tracking, but will continue to identify new cost saving initiatives as part of our everyday business.
As a result of these ongoing cost reductions and capital efficiency improvements, we have been able to significantly reduce our planned capital investment program over the past several years while still growing production. The diversity of our asset base and commodity price exposures allows us to select and fund projects that will generate the highest return in a given commodity environment. These cost and capital efficiency improvements, combined with our expanding drilling inventory, provides greater visibility to growing our free cash flow(2) (FFO less E&D Capital). Based on current commodity strip prices, we project our 2017 and 2018 free cash flow(2) levels to be nearly three-to-four-times what they were during the 2012-to-2014 timeframe, when commodity prices were much higher. We are now in a stronger position than we have ever been before, with a deep inventory of high return projects to underpin our self-funded growth-and-income model over the long-term.
2016 Review
We delivered 16% year-over-year production growth in 2016, above the upper-end of our guidance range of 62,500-63,500 boe/d. This production performance was achieved while reducing our E&D capital program by 50% as compared to 2015. In addition, despite the commodity price weakness seen in 2016, we continued to deliver strong performance across all segments of our business.
Our latest independent reserve and resource evaluations illustrate the strong organic inventory in each of our business units. Total 1P reserves increased 9% to 175.8(1) mmboe in 2016, while total 2P reserves increased 11% to 290.1(1) mmboe. This represents year-over-year 1P and 2P per share reserves growth of 4% and 5%, respectively. Operating recycle ratio(3) (including FDC) increased to 4.9x in 2016, compared to 3.6x in 2015 and 3.2x in 2014. Despite a further deterioration in commodity prices, these increases in reserves and recycle ratio further demonstrate the improvement of our project inventory and execution over the past few years.
In addition to growing our reserve base, we also focus on activities that will expand our resource base to support our longer-term growth profile in production and reserves. Our independent GLJ 2016 Resource Assessment(4) indicates risked low, best, and high estimates for contingent resources in the Development Pending category of 120.4(4) mmboe, 198.5(4) mmboe, and 309.4(4) mmboe, representing increases of 27%, 24% and 21%, respectively, compared to our GLJ 2015 Resource Assessment(5). The GLJ 2016 Resource Assessment also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 9.9(4) mmboe, 19.5(4) mmboe, and 28.7(4) mmboe. Over 90% of our risked contingent resources reside in the Development Pending category, reflecting the high quality nature of our contingent resource base. Prospective resources were assessed at risked low, best and high estimates of 45.2(4) mmboe, 89.5(4) mmboe, and 147.9(4) mmboe.
Europe
Production from Corrib averaged 62.9 mmcf/d (10,486 boe/d), net to Vermilion, in Q4 2016, representing 97% of rated plant capacity. All six wells are now available for production. The Corrib project has demonstrated lower-than-expected downtime and better-than-expected well deliverability thus far. Going forward, we expect Corrib to be a significant source of fund flows for Vermilion, stemming from its relatively high-priced gas product, absence of royalties, low operating expense, low maintenance capital requirements, and lack of cash income tax for the foreseeable future.
In France, we completed a four (4.0 net) well drilling program at Champotran and commenced drilling of a horizontal sidetrack well in the Vulaines field during Q4 2016, with completion and tie-in activities planned for the latter part of Q1 2017. This was our fourth successive drilling campaign at Champotran since 2013. In 2017, in addition to continuing our workover and optimization activities in France, we plan to drill our first four (4.0 net) wells in the Neocomian fields in the Paris Basin. After acquiring the Neocomian fields in 2012, we have increased production by approximately 50% through workovers and artificial lift optimizations.
In the Netherlands, we drilled two (0.9 net) wells in 2016. The Langezwaag-3 well (42% working interest) was completed and brought on production during Q4 2016 at a restricted rate of 7.5 mmcf/d. The Andel-6ST well (45% working interest) encountered a gas column of inadequate reservoir quality to justify completion. The Andel-6ST well is suspended while we evaluate the potential for another sidetrack to a location where higher quality gas zones may be encountered. During Q4 2016, we also acquired an incremental 30% working interest in the Drenthe VI production license for $28.3 million. This acquisition further consolidates our interest in the Drenthe VI production license, adding 30,000 net acres of land, including 26,000 net acres of undeveloped land and a 30% after payout interest in one well. In 2017, we plan to drill two (1.0 net) exploration wells and acquire 230 square kilometres of 3D seismic, representing a 50% increase in E&D capital investment compared to 2016.
On December 19, 2016, Vermilion closed the acquisition of operated and non-operated interests in five crude oil and three natural gas producing fields from Engie E&P Deutschland GmbH, for total consideration of €32.5 million ($45.6 million), net of acquired product inventory and after closing adjustments. The closing price was higher than the €28.3 million ($39.6 million) we estimated on December 19, 2016, primarily due to capital costs for a compression project that was installed before closing. Vermilion has assumed operatorship of six of the eight producing fields, representing our first operated producing properties in Germany. The acquisition advances our objective of developing a material business unit in the country, and is complementary to the assets in our existing European portfolio.
A portion of our 2017 capital program in Germany will be directed to investment in optimizations and other well work on the acquired Engie assets. In addition, further bolstering our operating presence in Germany, we have assumed the drilling operatorship for the Burgmoor Z5 well (25% working interest) in our Dümmersee-Uchte producing concession, which is expected to be drilled in 2018. Lastly, we will continue to advance our permitting, studies and other activities associated with the farm-in agreement we signed in mid-2015.
Vermilion added to its position in central and eastern Europe during Q4 2016 through a farm-in agreement in Slovakia with NAFTA, Slovakia's dominant exploration and production company. The farm-in agreement grants Vermilion a 50% working interest to jointly explore 183,000 acres on an existing license. The Slovakia farm-in offers access to a promising land position through modest seismic and well commitments over a five-year primary agreement term.
North America
During 2016, we drilled or participated in two (0.2 net) Cardium wells, 20 (12.0 net) Mannville wells, and seven (5.5 net) Midale wells. Our 2016 capital activities in Canada were focused on operated expiry wells and capital commitments on non-operated wells. Our Canadian assets provide significant flexibility to ramp activity levels up or down, with a diversified project inventory that provides exposure to oil, condensate and natural gas opportunities. Reflecting high project rates-of-return at current commodity prices, we are increasing our planned capital activity in Canada in 2017, targeting oil- and liquids-weighted projects. We plan to drill or participate in nine (6.0 net) Cardium wells, drill 23 (15.0 net) Mannville new wells and tie-in six (5.0 net) wells drilled in 2016, and drill 13 (11.3 net) new Midale wells and tie-in the four operated Midale wells we drilled in 2016.
In the United States, we continued development of the light oil Turner Sand in the Powder River Basin of Wyoming. In 2016, we completed two (2.0 net) wells drilled in 2015, and completed the Seedy Draw East Federal well drilled late in the year. In the Seedy Draw East Federal well, we drilled an approximately 1,400 metre horizontal lateral, and fracture stimulated 23 out of 32 planned frac stages before screening out. We plan to clean sand out of this well and put it on production during Q1 2017, leaving the remaining nine stages for potential stimulation at a later date. During 2017, we plan to drill and complete three (3.0 net) additional Turner Sand wells. Subsequent to year-end 2016, we purchased overriding royalty interests on our lands (ranging from 0.83% to 5%) for US$1.5 million, further consolidating our position in this play.
Australia
In Q2 2016, we drilled two horizontal sidetrack wells from our Wandoo B platform. Under restricted drawdown, these wells exhibit continued strong productive capability of a combined rate of approximately 4,300 bbls/d. The new sidetrack wells are produced intermittently to manage production levels and meet oil sales contract commitments. Given the strong results from our 2015 and 2016 drilling programs, we do not expect to drill additional wells in Australia until 2019.
Environmental, Social & Governance
During 2016, we were named to the CDP Climate "A" List, which recognizes companies for their actions in mitigating climate change. We were one of only five oil and gas companies in the world, and the only energy company in North America, to be awarded this distinction. CDP (formerly Carbon Disclosure Project), is a global, not-for-profit organization that manages the world's only global environmental disclosure system. Vermilion was the leading energy company on the Canadian Climate Disclosure Leadership Index (CLDI) for 2015, and the first Canadian energy company to achieve the top score of 100. To be named to the CDLI, a company must have a disclosure score within the top 10% of surveyed companies. We have voluntarily reported to CDP since 2012. We believe that by measuring and understanding our current environmental profile, we can direct our business strategy to operate in an even more environmentally and socially sustainable manner in the future.
During 2016, we were ranked 9th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list (the highest ranking for an oil and gas company, and our second consecutive year of improved rankings). Between 2013 and 2016, Vermilion's MSCI ESG (environment, social and governance) rating increased from BB to BBB, and our score on MSCI's Governance Metrics Report ranks Vermilion in the 90th percentile globally. These recognitions reflect our continued focus on achieving robust shareholder returns combined with environmental, social and governance performance.
We released our third annual Sustainability Report in 2016 which details our efforts to generate environmental, social, and economic benefits for all stakeholders. The report describes our approach to sustainability in our operations, and details our progress and challenges in this regard. We are committed to providing increasingly complete information and objective assessment of our performance in this area on an annual basis. We firmly believe in the importance of measuring and understanding our current environmental impact. Furthermore, we believe the integration of sustainability principles into our business strategy increases shareholder returns and reduces long-term risks to our business model. Our 2016 Sustainability Report is available on our corporate website at www.vermilionenergy.com/sustainability.
Vermilion ranked third within the oil and gas sector, and among the top quartile of companies in the S&P/TSX Composite Index in the Globe and Mail Board Games. Additionally, Vermilion was listed in the 2016 Best Practices report by the Canadian Coalition for Good Governance for our Proxy Circular disclosure on director and board independence, and benefits and perquisites, demonstrating our best-in-class governance disclosure.
Since 2010, we have been recognized by the Great Place to Work® Institute as one of the Top 30 Best Workplaces in Canada and France. We were also recognized in 2016 as a Top 20 Best Workplace in the Netherlands, and a Top 5 Best Workplace in the Berlin-Brandenburg region of Germany. These rankings demonstrate our strong corporate culture and highly engaged staff.
Outlook
Prior to the end of 2016, we announced a $295 million E&D capital budget for 2017 with associated production guidance of 69,000 to 70,000 boe/d. Our budget funds development of high-return projects including our condensate-rich Mannville play in Canada, continued drilling in France, favorably-priced European natural gas projects in the Netherlands, and our emerging Turner Sands play in the United States. Due to permitting delays on certain projects in the Netherlands, we have reallocated modest amounts of capital from the Netherlands to Canada, with no impact on our 2017 corporate capital or production guidance. Please refer to our March 2017 corporate presentation for the new capital levels by business unit.
We also previously announced preliminary 2018 targets, with anticipated E&D capital of $335 million and production of 75,000 to 76,000 boe/d. Production at the top end of these ranges for 2017 and 2018 would deliver per share growth of approximately 6% for each year. In recognition of the addition of our new Slovakian project to our capital project portfolio, we are increasing our 2018 capital investment target by $5 million to $340 million.
(1) |
Estimated proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2017 with an effective date of December 31, 2016 (the "2016 GLJ Reserves Evaluation") |
(2) |
The above discussion includes non-GAAP measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
(3) |
Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(4) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2017 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2016 (the "GLJ 2016 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 25%, 26% and 26%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
(5) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ 2015 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 82% and 81%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
TM |
Denotes trademark of Canaccord Genuity Capital Corporation |
2016 REVIEW AND 2017 GUIDANCE
On November 9, 2015, we announced preliminary 2016 capital expenditure guidance of $350 million and production guidance of between 63,000-65,000 boe/d. On January 5, 2016, in response to the continued weakness in commodity prices we reduced our 2016 capital expenditure guidance to $285 million with corresponding production guidance of 62,500-63,500 boe/d. On February 29, 2016, we further revised our 2016 capital expenditure guidance to $235 million as a result of continued commodity price deterioration. We maintained our production guidance of 62,500-63,500 boe/d. The February 29, 2016 reduction primarily reflected lower expected non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands pipeline twinning program. On August 8, 2016, we modestly increased our 2016 capital expenditure guidance to $240 million with the reinstatement of a four-well drilling program in the Champotran field in France and added drilling activity in Canada, partially offset by capital cost savings achieved to date. Actual 2016 capital spending of $242.4 million was within 1% of our guidance and 2016 production of 63,526 boe/d modestly exceeded the top end of our guidance range.
On October 31, 2016, we released our 2017 capital expenditure guidance of $295 million and associated production guidance of between 69,000-70,000 boe/d.
The following table summarizes our guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | |
2016 Guidance |
|||
2016 Guidance |
November 9, 2015 |
350 |
63,000 to 65,000 |
2016 Guidance |
January 5, 2016 |
285 |
62,500 to 63,500 |
2016 Guidance |
February 29, 2016 |
235 |
62,500 to 63,500 |
2016 Guidance |
August 8, 2016 |
240 |
62,500 to 63,500 |
2017 Guidance |
|||
2017 Guidance |
October 31, 2016 |
295 |
69,000 to 70,000 |
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on Monday, February 27, 2017 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 57763801. The replay will be available until midnight eastern time on March 10, 2017.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=1352942&s=1&k=773445F3555DFE9ED4F35C5E42104642 or visit Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
(1) Fund flows from operations is a financial measure that does not have a standardized meaning prescribed by International Financial Reporting Standards (IFRS). Fund flows from operations is a measure of profit or loss in accordance with IFRS 8 "Operating Segments", calculated as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit and our ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments.
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of crude oil and natural gas reserves does not represent the fair market value of these reserves.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
SOURCE Vermilion Energy Inc.
CALGARY, Feb. 27, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2016 year-end reserves and resource information. The estimates of reserves and resources and other oil and gas information contained in this news release have been estimated by GLJ Petroleum Consultants Ltd. ("GLJ") effective as at December 31, 2016 and prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGEH"). For additional information about Vermilion, including Vermilion's statement of reserves data and other information in Form 51-101F1, report on reserves data by independent qualified reserves evaluator or auditor in Form 51-101F2 and report of management and directors on oil and gas disclosure in Form 51-101F3, please review the Company's Annual Information Form for the year ended December 31, 2016, to be filed on February 27, 2017 and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov.
HIGHLIGHTS
(1) |
As evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 1, 2017 with an effective date of December 31, 2016. |
(2) |
F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period. |
(3) |
"Operating Recycle Ratio" is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). "Operating Netback" is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. |
(4) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 1, 2017 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2016 (the "GLJ 2016 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 84%, 83% and 82%, respectively. The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Unclarified category are 55%, 54% and 55%, respectively. The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 25%, 26% and 26%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
(5) |
Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ 2015 Resource Assessment"). The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 82% and 81%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. For further information, see the "Contingent Resources" section of this news release. |
DISCLAIMER
Certain statements included or incorporated by reference in this news release may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this news release may include, but are not limited to:
Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding the Company's financial strength and business objectives and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
RESERVES, FUTURE NET REVENUE AND OTHER OIL AND GAS INFORMATION
The following is a summary of the oil and natural gas reserves and the value of future net revenue of Vermilion as evaluated by GLJ, independent petroleum engineering consultants in Calgary in a report dated February 1, 2017 with an effective date of December 31, 2016 (the "GLJ 2016 Reserves Evaluation"). The GLJ 2016 Reserves Evaluation was prepared in accordance with National Instrument 51-101 and COGEH.
Reserves and other oil and gas information in this news release is effective December 31, 2016 unless otherwise stated.
All evaluations of future net production revenue set forth in the tables below are stated after overriding and lessor royalties, Crown royalties, freehold royalties, mineral taxes, direct lifting costs, normal allocated overhead and future capital investments, including abandonment and reclamation obligations. Future net production revenues estimated by the GLJ 2016 Reserves Evaluation do not represent the fair market value of the reserves. Other assumptions relating to the costs, prices for future production and other matters are included in the GLJ 2016 Reserve Evaluation. There is no assurance that the future price and cost assumptions used in the GLJ 2016 Reserves Evaluation will prove accurate and variances could be material.
Reserves for Australia, Canada, France, Germany, Ireland, the Netherlands and the United States are established using deterministic methodology. Total proved reserves are established at the 90 percent probability (P90) level. There is a 90 percent probability that the actual reserves recovered will be equal to or greater than the P90 reserves. Total proved plus probable reserves are established at the 50 percent probability (P50) level. There is a 50 percent probability that the actual reserves recovered will be equal to or greater than the P50 reserves.
Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development.
With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
Pricing used in the forecast price estimates is set forth in the table below and referenced in the notes to subsequent tables.
Table 1: Forecast Prices used in Estimates (1)
Light Crude Oil and & Medium Crude Oil |
Crude Oil |
Conventional Natural Gas Canada |
Conventional Natural Gas Europe |
Natural Gas Liquids |
Inflation Rate |
Exchange |
Exchange | |||
WTI |
Edmonton |
Cromer |
Brent Blend |
National Balancing |
||||||
Cushing |
Par Price |
Medium |
FOB |
AECO |
Point |
FOB |
||||
Oklahoma |
40˚ API |
29.3˚ API |
North Sea |
Gas Price |
(UK) |
Field Gate |
Percent |
|||
Year |
($US/bbl) |
($Cdn/bbl) |
($Cdn/bbl) |
($US/bbl) |
($Cdn/MMBtu) |
($US/MMBtu) |
($Cdn/bbl) |
Per Year |
($US/$Cdn) |
($CdnEUR) |
2016 |
43.30 |
52.95 |
48.71 |
45.01 |
2.19 |
4.65 |
34.50 |
1.50 |
0.76 |
1.47 |
Forecast |
||||||||||
2017 |
55.00 |
69.33 |
64.48 |
57.00 |
3.46 |
5.75 |
40.40 |
2.00 |
0.75 |
1.40 |
2018 |
59.00 |
72.26 |
67.20 |
61.00 |
3.10 |
6.00 |
41.41 |
2.00 |
0.78 |
1.35 |
2019 |
64.00 |
75.00 |
69.75 |
66.00 |
3.27 |
6.25 |
42.94 |
2.00 |
0.80 |
1.31 |
2020 |
67.00 |
76.36 |
71.02 |
70.00 |
3.49 |
6.50 |
43.77 |
2.00 |
0.83 |
1.27 |
2021 |
71.00 |
78.82 |
73.31 |
74.00 |
3.67 |
6.75 |
45.24 |
2.00 |
0.85 |
1.24 |
2022 |
74.00 |
82.35 |
76.59 |
77.00 |
3.86 |
6.89 |
47.30 |
2.00 |
0.85 |
1.24 |
2023 |
77.00 |
85.88 |
79.87 |
80.00 |
4.05 |
7.02 |
49.25 |
2.00 |
0.85 |
1.24 |
2024 |
80.00 |
89.41 |
83.15 |
83.00 |
4.16 |
7.16 |
51.23 |
2.00 |
0.85 |
1.24 |
2025 |
83.00 |
92.94 |
86.44 |
86.00 |
4.24 |
7.31 |
53.42 |
2.00 |
0.85 |
1.24 |
2026 |
86.05 |
95.61 |
88.92 |
89.64 |
4.32 |
7.45 |
54.80 |
2.00 |
0.85 |
1.24 |
Thereafter |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
2.0% |
0.850 |
1.235 |
Note: | |
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
All forecast prices in the tables above are provided by GLJ. For 2016, the price of crude oil in the United States is based on WTI. The benchmark price for Canadian crude oil is Edmonton Par and Canadian natural gas is priced against AECO. The benchmark price for Australia and France crude oil is Dated Brent. The price of our natural gas in Ireland is based on the NBP index. The price of Vermilion's natural gas in the Netherlands is based on the TTF day-ahead index, as determined on the Title Transfer Facility Virtual Trading Point. The price of Vermilion's natural gas in Germany is based on the TTF, as determined on the Title Transfer Facility Virtual Trading Point. For the year ended December 31, 2016, the average realized sales prices before hedging were $46.89 per bbl (United States) for WTI, $43.58 per bbl for Canadian-based crude oil, condensate and NGLs and $2.14 per Mcf for Canadian natural gas, $60.33 per bbl (Australia), $55.42 per bbl (France) for Brent-based crude oil, $5.86 per Mcf (Ireland), $5.67 per Mcf (Netherlands), and $5.33 per Mcf (Germany).
The following table summarizes the capital expenditures made by Vermilion on oil and natural gas properties for the year ended December 31, 2016:
Table 2: Capital Costs Incurred
Acquisition Costs |
|||||
Proved |
Unproved |
Exploration |
Development |
Total | |
(M$) |
Properties |
Properties |
Costs |
Costs |
Costs |
Australia |
- |
- |
- |
59,910 |
59,910 |
Canada |
13,309 |
- |
- |
62,706 |
76,015 |
Croatia |
- |
- |
2,968 |
- |
2,968 |
France |
- |
- |
- |
68,472 |
68,472 |
Germany |
48,377 |
- |
- |
3,803 |
52,180 |
Hungary |
- |
- |
338 |
- |
338 |
Ireland |
- |
- |
- |
9,375 |
9,375 |
Netherlands |
28,259 |
- |
- |
23,740 |
51,999 |
United States |
5,935 |
- |
- |
13,539 |
19,474 |
Total |
95,880 |
- |
3,306 |
241,545 |
340,731 |
The following table sets forth the reserve life index based on total proved and proved plus probable reserve and fourth quarter 2016 production of 60,863 boe/d.
Table 3: Reserve Life Index
Commodity |
Production |
Reserve Life Index (years) | |||
Fourth Quarter 2016 |
Total Proved |
Proved Plus Probable | |||
Crude oil, condensate and natural gas liquids (bbl/d) |
28,439 |
9.9 |
15.9 | ||
Natural gas (mmcf/d) |
194.54 |
6.2 |
10.6 | ||
Oil Equivalent (boe/d) |
60,863 |
7.9 |
13.1 |
The following tables provide reserves data and a breakdown of future net revenue by component and production group using forecast prices and costs. For Canada, the tables following include Alberta gas cost allowance.
The following tables may not total due to rounding.
Table 4: Oil and Gas Reserves - Based on Forecast Prices and Costs (1)
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |
Proved Developed Producing (3) (5) (6) |
||||||||
Australia |
10,718 |
10,718 |
- |
- |
- |
- |
- |
- |
Canada |
12,277 |
10,990 |
- |
- |
12 |
8 |
112,918 |
101,728 |
France |
36,481 |
33,478 |
- |
- |
- |
- |
5,412 |
5,024 |
Germany |
4,805 |
4,706 |
- |
- |
- |
- |
30,892 |
27,510 |
Ireland |
- |
- |
- |
- |
- |
- |
95,861 |
95,861 |
Netherlands |
- |
- |
- |
- |
- |
- |
41,494 |
29,860 |
United States |
699 |
551 |
- |
- |
- |
- |
696 |
552 |
Total Proved Developed Producing |
64,980 |
60,443 |
- |
- |
12 |
8 |
287,273 |
260,535 |
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross |
Net | |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |
Proved Developed Producing (3) (5) (6) |
||||||||
Australia |
- |
- |
- |
- |
- |
- |
10,718 |
10,718 |
Canada |
1,371 |
1,291 |
2,482 |
2,275 |
8,484 |
6,395 |
40,235 |
34,942 |
France |
- |
- |
- |
- |
- |
- |
37,383 |
34,315 |
Germany |
- |
- |
- |
- |
- |
- |
9,954 |
9,291 |
Ireland |
- |
- |
- |
- |
- |
- |
15,977 |
15,977 |
Netherlands |
- |
- |
- |
- |
59 |
59 |
6,975 |
5,036 |
United States |
- |
- |
- |
- |
97 |
76 |
912 |
719 |
1,371 |
1,291 |
2,482 |
2,275 |
8,640 |
6,530 |
122,154 |
110,998 | |
Light Crude Oil & Medium Crude Oil |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |
Proved Developed Non-Producing |
||||||||
Australia |
700 |
700 |
- |
- |
- |
- |
- |
- |
Canada |
1,008 |
874 |
- |
- |
- |
- |
24,705 |
22,319 |
France |
1,814 |
1,666 |
- |
- |
- |
- |
- |
- |
Germany |
240 |
230 |
- |
- |
- |
- |
8,227 |
7,389 |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands |
- |
- |
- |
- |
- |
- |
17,815 |
15,327 |
United States |
- |
- |
- |
- |
- |
- |
- |
- |
Total Proved Developed Non-Producing |
3,762 |
3,470 |
- |
- |
- |
- |
50,747 |
45,035 |
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross |
Net | |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |
Proved Developed Non-Producing |
||||||||
Australia |
- |
- |
- |
- |
- |
- |
700 |
700 |
Canada |
- |
- |
2,536 |
2,389 |
1,649 |
1,283 |
7,197 |
6,275 |
France |
- |
- |
- |
- |
- |
- |
1,814 |
1,666 |
Germany |
- |
- |
- |
- |
- |
- |
1,611 |
1,462 |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands |
- |
- |
- |
- |
21 |
21 |
2,990 |
2,576 |
United States |
- |
- |
- |
- |
- |
- |
- |
- |
Total Proved Developed Non-Producing |
- |
- |
2,536 |
2,389 |
1,670 |
1,304 |
14,312 |
12,679 |
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |
Proved Undeveloped (3) (8) |
||||||||
Australia |
1,000 |
1,000 |
- |
- |
- |
- |
- |
- |
Canada |
8,677 |
7,595 |
- |
- |
- |
- |
79,475 |
71,420 |
France |
3,749 |
3,506 |
- |
- |
- |
- |
70 |
70 |
Germany |
243 |
237 |
- |
- |
- |
- |
2,361 |
1,918 |
Ireland |
- |
- |
- |
- |
- |
- |
3,714 |
3,714 |
Netherlands |
- |
- |
- |
- |
- |
- |
3,041 |
3,041 |
United States |
2,470 |
2,019 |
- |
- |
- |
- |
2,273 |
1,858 |
Total Proved Undeveloped |
16,139 |
14,357 |
- |
- |
- |
- |
90,934 |
82,021 |
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross |
Net | |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |
Proved Undeveloped |
||||||||
Australia |
- |
- |
- |
- |
- |
- |
1,000 |
1,000 |
Canada |
- |
- |
3,043 |
2,812 |
7,230 |
5,541 |
29,660 |
25,508 |
France |
- |
- |
- |
- |
- |
- |
3,761 |
3,518 |
Germany |
- |
- |
- |
- |
- |
- |
637 |
557 |
Ireland |
- |
- |
- |
- |
- |
- |
619 |
619 |
Netherlands |
- |
- |
- |
- |
1 |
1 |
508 |
508 |
United States |
- |
- |
- |
- |
315 |
258 |
3,164 |
2,587 |
Total Proved Undeveloped |
- |
- |
3,043 |
2,812 |
7,546 |
5,800 |
39,349 |
34,297 |
Light Crude Oil & Medium Crude Oil |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |
Proved (3) |
||||||||
Australia |
12,418 |
12,418 |
- |
- |
- |
- |
- |
- |
Canada |
21,962 |
19,460 |
- |
- |
12 |
8 |
217,098 |
195,467 |
France |
42,044 |
38,650 |
- |
- |
- |
- |
5,482 |
5,094 |
Germany |
5,288 |
5,173 |
- |
- |
- |
- |
41,480 |
36,817 |
Ireland |
- |
- |
- |
- |
- |
- |
99,575 |
99,575 |
Netherlands |
- |
- |
- |
- |
- |
- |
62,350 |
48,228 |
United States |
3,169 |
2,570 |
- |
- |
- |
- |
2,969 |
2,410 |
Total Proved |
84,881 |
78,271 |
- |
- |
12 |
8 |
428,954 |
387,591 |
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross |
Net | |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |
Proved |
||||||||
Australia |
- |
- |
- |
- |
- |
- |
12,418 |
12,418 |
Canada |
1,371 |
1,291 |
8,061 |
7,476 |
17,363 |
13,219 |
77,092 |
66,725 |
France |
- |
- |
- |
- |
- |
- |
42,958 |
39,499 |
Germany |
- |
- |
- |
- |
- |
- |
12,202 |
11,310 |
Ireland |
- |
- |
- |
- |
- |
- |
16,596 |
16,596 |
Netherlands |
- |
- |
- |
- |
81 |
81 |
10,473 |
8,120 |
United States |
- |
- |
- |
- |
412 |
334 |
4,076 |
3,306 |
Total Proved |
1,371 |
1,291 |
8,061 |
7,476 |
17,856 |
13,634 |
175,815 |
157,974 |
Light Crude Oil & Medium Crude Oil |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |
Probable (4) |
||||||||
Australia |
4,650 |
4,650 |
- |
- |
- |
- |
- |
- |
Canada |
14,103 |
12,146 |
- |
- |
2 |
1 |
151,707 |
135,215 |
France |
21,933 |
20,261 |
- |
- |
- |
- |
892 |
884 |
Germany |
2,279 |
2,238 |
- |
- |
- |
- |
54,284 |
47,482 |
Ireland |
- |
- |
- |
- |
- |
- |
50,787 |
50,787 |
Netherlands |
- |
- |
- |
- |
- |
- |
43,184 |
33,118 |
United States |
5,727 |
4,716 |
- |
- |
- |
- |
5,481 |
4,512 |
Total Probable |
48,692 |
44,011 |
- |
- |
2 |
1 |
306,335 |
271,998 |
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross |
Net | |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |
Probable |
||||||||
Australia |
- |
- |
- |
- |
- |
- |
4,650 |
4,650 |
Canada |
284 |
267 |
4,677 |
4,395 |
12,907 |
9,730 |
53,123 |
45,190 |
France |
- |
- |
- |
- |
- |
- |
22,082 |
20,408 |
Germany |
- |
- |
- |
- |
- |
- |
11,326 |
10,152 |
Ireland |
- |
- |
- |
- |
- |
- |
8,465 |
8,465 |
Netherlands |
- |
- |
- |
- |
63 |
56 |
7,260 |
5,576 |
United States |
- |
- |
- |
- |
760 |
625 |
7,401 |
6,093 |
Total Probable |
284 |
267 |
4,677 |
4,395 |
13,730 |
10,411 |
114,307 |
100,534 |
Light Crude Oil & Medium |
Heavy Oil |
Tight Oil |
Conventional Natural Gas | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) | |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) | |
Proved Plus Probable (3) (4) |
||||||||
Australia |
17,068 |
17,068 |
- |
- |
- |
- |
- |
- |
Canada |
36,065 |
31,606 |
- |
- |
14 |
9 |
368,805 |
330,682 |
France |
63,977 |
58,911 |
- |
- |
- |
- |
6,374 |
5,978 |
Germany |
7,567 |
7,411 |
- |
- |
- |
- |
95,764 |
84,299 |
Ireland |
- |
- |
- |
- |
- |
- |
150,362 |
150,362 |
Netherlands |
- |
- |
- |
- |
- |
- |
105,534 |
81,346 |
United States |
8,896 |
7,286 |
- |
- |
- |
- |
8,450 |
6,922 |
Total Proved Plus Probable |
133,573 |
122,282 |
- |
- |
14 |
9 |
735,289 |
659,589 |
Shale Gas |
Coal Bed Methane |
Natural Gas Liquids |
BOE | |||||
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross (2) |
Net (2) |
Gross |
Net | |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) | |
Proved Plus Probable (3) (4) |
||||||||
Australia |
- |
- |
- |
- |
- |
- |
17,068 |
17,068 |
Canada |
1,655 |
1,558 |
12,738 |
11,871 |
30,270 |
22,949 |
130,215 |
111,915 |
France |
- |
- |
- |
- |
- |
- |
65,040 |
59,907 |
Germany |
- |
- |
- |
- |
- |
- |
23,528 |
21,462 |
Ireland |
- |
- |
- |
- |
- |
- |
25,061 |
25,061 |
Netherlands |
- |
- |
- |
- |
144 |
137 |
17,733 |
13,696 |
United States |
- |
- |
- |
- |
1,172 |
959 |
11,477 |
9,399 |
Total Proved Plus Probable |
1,655 |
1,558 |
12,738 |
11,871 |
31,586 |
24,045 |
290,122 |
258,508 |
Notes: | |
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
"Gross Reserves" are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net Reserves" are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in reserves. |
(3) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(4) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(5) |
"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. |
(6) |
"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
(7) |
"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. |
(8) |
"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. |
Table 5: Net Present Values of Future Net Revenue - Based on Forecast Prices and Costs (1)
Before Deducting Future Income Taxes Discounted At |
After Deducting Future Income Taxes Discounted At | |||||||||
(M$) |
0% |
5% |
10% |
15% |
20% |
0% |
5% |
10% |
15% |
20% |
Proved Developed Producing (2) (4) (5) |
||||||||||
Australia |
134,236 |
217,117 |
240,607 |
240,546 |
231,618 |
164,830 |
197,187 |
199,187 |
190,432 |
178,594 |
Canada |
963,690 |
777,268 |
645,191 |
553,740 |
487,804 |
963,690 |
777,268 |
645,191 |
553,740 |
487,804 |
France |
2,009,158 |
1,404,527 |
1,073,623 |
871,502 |
736,836 |
1,664,358 |
1,169,631 |
894,523 |
725,047 |
611,642 |
Germany |
193,385 |
187,330 |
161,141 |
138,822 |
121,707 |
193,385 |
187,330 |
161,141 |
138,822 |
121,707 |
Ireland |
471,720 |
441,671 |
396,917 |
356,653 |
323,302 |
471,720 |
441,671 |
396,917 |
356,653 |
323,302 |
Netherlands |
76,272 |
86,832 |
91,069 |
92,068 |
91,365 |
65,732 |
76,545 |
81,019 |
82,239 |
81,743 |
United States |
29,716 |
23,345 |
19,334 |
16,637 |
14,710 |
29,716 |
23,345 |
19,334 |
16,637 |
14,710 |
Total Proved Developed Producing |
3,878,177 |
3,138,090 |
2,627,882 |
2,269,968 |
2,007,342 |
3,553,431 |
2,872,977 |
2,397,312 |
2,063,570 |
1,819,502 |
Proved Developed Non-Producing (2) (4) (6) |
||||||||||
Australia |
31,411 |
35,177 |
32,247 |
28,181 |
24,473 |
31,411 |
35,177 |
32,247 |
28,181 |
24,473 |
Canada |
147,607 |
108,964 |
87,413 |
73,769 |
64,329 |
147,607 |
108,964 |
87,413 |
73,769 |
64,329 |
France |
87,674 |
71,387 |
60,449 |
52,665 |
46,857 |
60,567 |
49,131 |
41,376 |
35,850 |
31,732 |
Germany |
41,121 |
29,470 |
21,864 |
16,769 |
13,244 |
41,121 |
29,470 |
21,864 |
16,769 |
13,244 |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands |
46,907 |
45,115 |
42,066 |
38,740 |
35,545 |
33,688 |
32,489 |
29,973 |
27,127 |
24,367 |
United States |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Total Proved Developed Non-Producing |
354,720 |
290,113 |
244,039 |
210,124 |
184,448 |
314,394 |
255,231 |
212,873 |
181,696 |
158,145 |
Proved Undeveloped (2) (7) |
||||||||||
Australia |
34,323 |
24,134 |
16,832 |
11,574 |
7,761 |
12,618 |
2,648 |
(1,772) |
(3,929) |
(5,057) |
Canada |
569,308 |
368,599 |
249,906 |
175,120 |
125,532 |
416,577 |
282,567 |
199,226 |
144,148 |
106,013 |
France |
187,253 |
137,261 |
104,175 |
81,348 |
64,957 |
129,800 |
91,741 |
66,604 |
49,467 |
37,335 |
Germany |
18,403 |
11,756 |
7,584 |
4,902 |
3,130 |
18,403 |
11,756 |
7,584 |
4,902 |
3,130 |
Ireland |
12,873 |
9,337 |
6,763 |
4,894 |
3,536 |
12,873 |
9,337 |
6,763 |
4,894 |
3,536 |
Netherlands |
10,896 |
9,095 |
7,611 |
6,411 |
5,443 |
8,160 |
6,584 |
5,294 |
4,263 |
3,443 |
United States |
72,284 |
38,191 |
20,027 |
9,645 |
3,348 |
72,284 |
38,191 |
20,027 |
9,645 |
3,348 |
Total Proved Undeveloped |
905,340 |
598,373 |
412,898 |
293,894 |
213,707 |
670,715 |
442,824 |
303,726 |
213,390 |
151,748 |
Proved (2) |
||||||||||
Australia |
199,970 |
276,428 |
289,686 |
280,301 |
263,852 |
208,859 |
235,012 |
229,662 |
214,684 |
198,010 |
Canada |
1,680,605 |
1,254,831 |
982,510 |
802,629 |
677,665 |
1,527,874 |
1,168,799 |
931,830 |
771,657 |
658,146 |
France |
2,284,085 |
1,613,175 |
1,238,247 |
1,005,515 |
848,650 |
1,854,725 |
1,310,503 |
1,002,503 |
810,364 |
680,709 |
Germany |
252,909 |
228,556 |
190,589 |
160,493 |
138,081 |
252,909 |
228,556 |
190,589 |
160,493 |
138,081 |
Ireland |
484,593 |
451,008 |
403,680 |
361,547 |
326,838 |
484,593 |
451,008 |
403,680 |
361,547 |
326,838 |
Netherlands |
134,075 |
141,042 |
140,746 |
137,219 |
132,353 |
107,580 |
115,618 |
116,286 |
113,629 |
109,553 |
United States |
102,000 |
61,536 |
39,361 |
26,282 |
18,058 |
102,000 |
61,536 |
39,361 |
26,282 |
18,058 |
Total Proved |
5,138,237 |
4,026,576 |
3,284,819 |
2,773,986 |
2,405,497 |
4,538,540 |
3,571,032 |
2,913,911 |
2,458,656 |
2,129,395 |
Probable (3) |
||||||||||
Australia |
198,227 |
163,180 |
128,734 |
101,649 |
81,484 |
107,201 |
87,874 |
68,562 |
53,406 |
42,201 |
Canada |
1,372,807 |
814,946 |
539,761 |
384,694 |
288,798 |
1,009,708 |
591,846 |
389,432 |
277,104 |
208,604 |
France |
1,378,689 |
734,502 |
464,026 |
323,290 |
239,221 |
974,931 |
502,379 |
305,000 |
203,471 |
143,693 |
Germany |
336,322 |
208,119 |
130,651 |
86,473 |
59,902 |
248,590 |
162,713 |
105,566 |
71,859 |
51,003 |
Ireland |
354,566 |
235,805 |
167,862 |
126,297 |
99,303 |
354,566 |
235,805 |
167,862 |
126,297 |
99,303 |
Netherlands |
162,029 |
137,048 |
115,870 |
98,750 |
85,096 |
111,908 |
92,487 |
75,843 |
62,469 |
51,946 |
United States |
270,229 |
147,720 |
90,240 |
59,467 |
41,247 |
175,706 |
98,838 |
61,958 |
41,765 |
29,522 |
Total Probable |
4,072,869 |
2,441,320 |
1,637,144 |
1,180,620 |
895,051 |
2,982,610 |
1,771,942 |
1,174,223 |
836,371 |
626,272 |
Proved Plus Probable (2) (3) |
||||||||||
Australia |
398,197 |
439,608 |
418,420 |
381,950 |
345,336 |
316,060 |
322,886 |
298,224 |
268,090 |
240,211 |
Canada |
3,053,412 |
2,069,777 |
1,522,271 |
1,187,323 |
966,463 |
2,537,582 |
1,760,645 |
1,321,262 |
1,048,761 |
866,750 |
France |
3,662,774 |
2,347,677 |
1,702,273 |
1,328,805 |
1,087,871 |
2,829,656 |
1,812,882 |
1,307,503 |
1,013,835 |
824,402 |
Germany |
589,231 |
436,675 |
321,240 |
246,966 |
197,983 |
501,499 |
391,269 |
296,155 |
232,352 |
189,084 |
Ireland |
839,159 |
686,813 |
571,542 |
487,844 |
426,141 |
839,159 |
686,813 |
571,542 |
487,844 |
426,141 |
Netherlands |
296,104 |
278,090 |
256,616 |
235,969 |
217,449 |
219,488 |
208,105 |
192,129 |
176,098 |
161,499 |
United States |
372,229 |
209,256 |
129,601 |
85,749 |
59,305 |
277,706 |
160,374 |
101,319 |
68,047 |
47,580 |
Total Proved Plus Probable |
9,211,106 |
6,467,896 |
4,921,963 |
3,954,606 |
3,300,548 |
7,521,150 |
5,342,974 |
4,088,134 |
3,295,027 |
2,755,667 |
Notes: | |
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(3) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(4) |
"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. |
(5) |
"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
(6) |
"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. |
(7) |
"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. |
Table 6: Total Future Net Revenue (Undiscounted) Based on Forecast Prices and Costs (1)
Abandonment |
Future Net |
Future Net | ||||||
Capital |
and |
Revenue |
Revenue | |||||
Operating |
Development |
Reclamation |
Before |
Future |
After | |||
(M$) |
Revenue |
Royalties |
Costs |
Costs |
Costs |
Income Taxes |
Income Taxes |
Income Taxes |
Proved (2) |
||||||||
Australia |
1,130,774 |
- |
585,013 |
98,280 |
247,512 |
199,969 |
(8,890) |
208,859 |
Canada |
3,767,788 |
508,170 |
1,060,685 |
421,548 |
96,780 |
1,680,605 |
152,731 |
1,527,874 |
France |
3,892,917 |
309,696 |
1,017,941 |
123,472 |
157,722 |
2,284,086 |
429,361 |
1,854,725 |
Germany |
812,577 |
43,400 |
383,854 |
12,267 |
120,147 |
252,909 |
- |
252,909 |
Ireland |
755,793 |
- |
174,058 |
35,412 |
61,729 |
484,594 |
- |
484,594 |
Netherlands |
523,311 |
103,758 |
197,686 |
22,639 |
65,154 |
134,074 |
26,495 |
107,579 |
United States |
297,606 |
83,116 |
48,860 |
60,639 |
2,991 |
102,000 |
- |
102,000 |
Total Proved |
11,180,766 |
1,048,140 |
3,468,097 |
774,257 |
752,035 |
5,138,237 |
599,697 |
4,538,540 |
Proved Plus Probable (2) (3) |
||||||||
Australia |
1,611,584 |
- |
777,207 |
175,660 |
260,522 |
398,197 |
82,137 |
316,060 |
Canada |
6,601,327 |
949,111 |
1,699,340 |
774,361 |
125,102 |
3,053,413 |
515,831 |
2,537,582 |
France |
6,232,560 |
486,688 |
1,560,331 |
317,562 |
205,205 |
3,662,774 |
833,118 |
2,829,656 |
Germany |
1,534,267 |
102,937 |
592,967 |
88,681 |
160,451 |
589,231 |
87,732 |
501,499 |
Ireland |
1,208,966 |
- |
272,665 |
35,412 |
61,729 |
839,159 |
- |
839,159 |
Netherlands |
887,526 |
181,892 |
286,933 |
45,647 |
76,950 |
296,104 |
76,616 |
219,488 |
United States |
888,444 |
241,131 |
130,837 |
137,814 |
6,434 |
372,229 |
94,523 |
277,706 |
Total Proved Plus Probable |
18,964,674 |
1,961,759 |
5,320,280 |
1,575,137 |
896,393 |
9,211,107 |
1,689,957 |
7,521,150 |
Notes: | |
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(3) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
Table 7: Future Net Revenue by Production Group Based on Forecast Prices and Costs (1)
Future Net Revenue |
||
Before Income Taxes (2) |
||
(Discounted at 10% Per Year) |
Unit Value | |
Proved Developed Producing |
(M$) |
($/boe) |
Light crude oil & medium crude oil (3) |
1,869,323 |
28.43 |
Heavy Oil (3) |
- |
- |
Conventional Natural gas (4) |
755,799 |
16.95 |
Shale Gas |
1,928 |
6.93 |
Coal Bed Methane |
832 |
2.19 |
Total Proved Developed Producing |
2,627,882 |
23.68 |
Proved Developed Non-Producing |
||
Light crude oil & medium crude oil (3) |
119,652 |
32.00 |
Heavy Oil (3) |
- |
- |
Conventional Natural gas (4) |
123,922 |
14.51 |
Shale Gas |
- |
- |
Coal Bed Methane |
465 |
1.17 |
Total Proved Developed Non-Producing |
244,039 |
19.25 |
Proved Undeveloped |
||
Light crude oil & medium crude oil (3) |
279,927 |
14.84 |
Heavy Oil (3) |
- |
- |
Conventional Natural gas (4) |
132,343 |
8.84 |
Shale Gas |
- |
- |
Coal Bed Methane |
628 |
1.34 |
Total Proved Undeveloped |
412,898 |
12.04 |
Proved |
||
Light crude oil & medium crude oil (3) |
2,268,902 |
25.72 |
Heavy Oil (3) |
- |
- |
Conventional Natural gas (4) |
1,012,064 |
14.82 |
Shale Gas |
1,928 |
6.97 |
Coal Bed Methane |
1,925 |
1.53 |
Total Proved |
3,284,819 |
20.79 |
Probable |
||
Light crude oil & medium crude oil (3) |
1,044,229 |
20.31 |
Heavy Oil (3) |
- |
- |
Conventional Natural gas (4) |
590,638 |
12.22 |
Shale Gas |
357 |
6.26 |
Coal Bed Methane |
1,920 |
2.62 |
Total Probable |
1,637,144 |
16.28 |
Proved Plus Probable |
||
Light crude oil & medium crude oil (3) |
3,313,131 |
23.76 |
Heavy Oil (3) |
- |
- |
Conventional Natural gas (4) |
1,602,702 |
13.70 |
Shale Gas |
2,285 |
6.93 |
Coal Bed Methane |
3,845 |
1.91 |
Total Proved Plus Probable |
4,921,963 |
19.04 |
Notes: | |
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) |
Other Company revenue and costs not related to a specific product type have been allocated proportionately to the specified product types. Unit values are based on Company Net Reserves. Net present value of reserves categories are an approximation based on major products. |
(3) |
Including solution gas and other by-products. |
(4) |
Including by-products but excluding solution gas. |
Reconciliations of Changes in Reserves
The following tables set forth a reconciliation of the changes in Vermilion's gross light and medium crude oil, heavy oil and associated and non-associated gas (combined) reserves as at December 31, 2016 compared to such reserves as at December 31, 2015.
Table 8: Reconciliation of Company Gross Reserves by Principal Product Type - Based on Forecast Prices and Costs (3)
Light Crude Oil & |
||||||||||||
AUSTRALIA |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
13,765 |
3,700 |
17,465 |
13,765 |
3,700 |
17,465 |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
700 |
1,300 |
2,000 |
700 |
1,300 |
2,000 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
260 |
(350) |
(90) |
260 |
(350) |
(90) |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Production |
(2,307) |
- |
(2,307) |
(2,307) |
- |
(2,307) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
12,418 |
4,650 |
17,068 |
12,418 |
4,650 |
17,068 |
- |
- |
- |
- |
- |
- |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Technical Revisions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Production |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
- |
- |
- |
13,765 |
3,700 |
17,465 |
||||||
Discoveries |
- |
- |
- |
- |
- |
- |
||||||
Extensions & Improved Recovery |
- |
- |
- |
700 |
1,300 |
2,000 |
||||||
Technical Revisions |
- |
- |
- |
260 |
(350) |
(90) |
||||||
Acquisitions |
- |
- |
- |
- |
- |
- |
||||||
Dispositions |
- |
- |
- |
- |
- |
- |
||||||
Economic Factors |
- |
- |
- |
- |
- |
- |
||||||
Production |
- |
- |
- |
(2,307) |
- |
(2,307) |
||||||
At December 31, 2016 |
- |
- |
- |
12,418 |
4,650 |
17,068 |
||||||
Light Crude Oil & |
||||||||||||
CANADA |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
22,990 |
14,792 |
37,782 |
22,971 |
14,786 |
37,757 |
9 |
3 |
12 |
10 |
3 |
13 |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
620 |
281 |
901 |
620 |
281 |
901 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
611 |
(1,284) |
(673) |
616 |
(1,280) |
(664) |
(9) |
(3) |
(12) |
4 |
(1) |
3 |
Acquisitions |
206 |
317 |
523 |
206 |
317 |
523 |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
(15) |
(1) |
(16) |
(15) |
(1) |
(16) |
- |
- |
- |
- |
- |
- |
Production |
(2,438) |
- |
(2,438) |
(2,436) |
- |
(2,436) |
- |
- |
- |
(2) |
- |
(2) |
At December 31, 2016 |
21,974 |
14,105 |
36,079 |
21,962 |
14,103 |
36,065 |
- |
- |
- |
12 |
2 |
14 |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
200,263 |
138,068 |
338,331 |
190,111 |
132,676 |
322,787 |
8,210 |
4,917 |
13,127 |
1,942 |
475 |
2,417 |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
18,401 |
20,608 |
39,009 |
18,401 |
20,608 |
39,009 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
27,342 |
(8,022) |
19,320 |
26,058 |
(7,696) |
18,362 |
1,394 |
(135) |
1,259 |
(110) |
(191) |
(301) |
Acquisitions |
13,078 |
6,758 |
19,836 |
13,006 |
6,671 |
19,677 |
72 |
87 |
159 |
- |
- |
- |
Dispositions |
(353) |
(132) |
(485) |
(353) |
(132) |
(485) |
- |
- |
- |
- |
- |
- |
Economic Factors |
(1,351) |
(612) |
(1,963) |
(649) |
(420) |
(1,069) |
(702) |
(192) |
(894) |
- |
- |
- |
Production |
(30,850) |
- |
(30,850) |
(29,476) |
- |
(29,476) |
(913) |
- |
(913) |
(461) |
- |
(461) |
At December 31, 2016 |
226,530 |
156,668 |
383,198 |
217,098 |
151,707 |
368,805 |
8,061 |
4,677 |
12,738 |
1,371 |
284 |
1,655 |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
14,795 |
12,751 |
27,546 |
71,162 |
50,554 |
121,717 |
||||||
Discoveries |
- |
- |
- |
- |
- |
- |
||||||
Extensions & Improved Recovery |
1,412 |
825 |
2,237 |
5,099 |
4,541 |
9,640 |
||||||
Technical Revisions |
2,004 |
(1,088) |
916 |
7,172 |
(3,709) |
3,463 |
||||||
Acquisitions |
1,045 |
471 |
1,516 |
3,431 |
1,914 |
5,345 |
||||||
Dispositions |
(8) |
(3) |
(11) |
(67) |
(25) |
(92) |
||||||
Economic Factors |
(31) |
(49) |
(80) |
(271) |
(152) |
(423) |
||||||
Production |
(1,854) |
- |
(1,854) |
(9,434) |
- |
(9,434) |
||||||
At December 31, 2016 |
17,363 |
12,907 |
30,270 |
77,092 |
53,123 |
130,215 |
||||||
Light Crude Oil & |
||||||||||||
FRANCE |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
40,721 |
21,325 |
62,046 |
40,721 |
21,325 |
62,046 |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
2,279 |
314 |
2,593 |
2,279 |
314 |
2,593 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
3,445 |
319 |
3,764 |
3,445 |
319 |
3,764 |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
(47) |
(25) |
(72) |
(47) |
(25) |
(72) |
- |
- |
- |
- |
- |
- |
Production |
(4,354) |
- |
(4,354) |
(4,354) |
- |
(4,354) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
42,044 |
21,933 |
63,977 |
42,044 |
21,933 |
63,977 |
- |
- |
- |
- |
- |
- |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
7,835 |
1,559 |
9,394 |
7,835 |
1,559 |
9,394 |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Technical Revisions |
(2,170) |
(654) |
(2,824) |
(2,170) |
(654) |
(2,824) |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
(20) |
(13) |
(33) |
(20) |
(13) |
(33) |
- |
- |
- |
- |
- |
- |
Production |
(163) |
- |
(163) |
(163) |
- |
(163) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
5,482 |
892 |
6,374 |
5,482 |
892 |
6,374 |
- |
- |
- |
- |
- |
- |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
- |
- |
- |
42,027 |
21,585 |
63,612 |
||||||
Discoveries |
- |
- |
- |
- |
- |
- |
||||||
Extensions & Improved Recovery |
- |
- |
- |
2,279 |
314 |
2,593 |
||||||
Technical Revisions |
- |
- |
- |
3,083 |
210 |
3,293 |
||||||
Acquisitions |
- |
- |
- |
- |
- |
- |
||||||
Dispositions |
- |
- |
- |
- |
- |
- |
||||||
Economic Factors |
- |
- |
- |
(50) |
(27) |
(77) |
||||||
Production |
- |
- |
- |
(4,381) |
- |
(4,381) |
||||||
At December 31, 2016 |
- |
- |
- |
42,958 |
22,082 |
65,040 |
||||||
Light Crude Oil & |
||||||||||||
GERMANY |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
244 |
755 |
999 |
244 |
755 |
999 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Acquisitions |
5,044 |
1,524 |
6,568 |
5,044 |
1,524 |
6,568 |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Production |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
5,288 |
2,279 |
7,567 |
5,288 |
2,279 |
7,567 |
- |
- |
- |
- |
- |
- |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
31,500 |
17,999 |
49,499 |
31,500 |
17,999 |
49,499 |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
- |
33,249 |
33,249 |
- |
33,249 |
33,249 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
4,250 |
(898) |
3,352 |
4,250 |
(898) |
3,352 |
- |
- |
- |
- |
- |
- |
Acquisitions |
11,182 |
3,934 |
15,116 |
11,182 |
3,934 |
15,116 |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Production |
(5,452) |
- |
(5,452) |
(5,452) |
- |
(5,452) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
41,480 |
54,284 |
95,764 |
41,480 |
54,284 |
95,764 |
- |
- |
- |
- |
- |
- |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
- |
- |
- |
5,250 |
3,000 |
8,250 |
||||||
Discoveries |
- |
- |
- |
- |
- |
- |
||||||
Extensions & Improved Recovery |
- |
- |
- |
244 |
6,297 |
6,541 |
||||||
Technical Revisions |
- |
- |
- |
708 |
(150) |
559 |
||||||
Acquisitions |
- |
- |
- |
6,909 |
2,179 |
9,087 |
||||||
Dispositions |
- |
- |
- |
- |
- |
- |
||||||
Economic Factors |
- |
- |
- |
- |
- |
- |
||||||
Production |
- |
- |
- |
(909) |
- |
(909) |
||||||
At December 31, 2016 |
- |
- |
- |
12,202 |
11,326 |
23,528 |
||||||
Light Crude Oil & |
||||||||||||
IRELAND |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Technical Revisions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Production |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
105,821 |
47,405 |
153,226 |
105,821 |
47,405 |
153,226 |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
3,714 |
2,718 |
6,432 |
3,714 |
2,718 |
6,432 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
8,610 |
721 |
9,331 |
8,610 |
721 |
9,331 |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
57 |
(57) |
- |
57 |
(57) |
- |
- |
- |
- |
- |
- |
- |
Production |
(18,627) |
- |
(18,627) |
(18,627) |
- |
(18,627) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
99,575 |
50,787 |
150,362 |
99,575 |
50,787 |
150,362 |
- |
- |
- |
- |
- |
- |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
- |
- |
- |
17,637 |
7,901 |
25,538 |
||||||
Discoveries |
- |
- |
- |
- |
- |
- |
||||||
Extensions & Improved Recovery |
- |
- |
- |
619 |
453 |
1,072 |
||||||
Technical Revisions |
- |
- |
- |
1,435 |
121 |
1,556 |
||||||
Acquisitions |
- |
- |
- |
- |
- |
- |
||||||
Dispositions |
- |
- |
- |
- |
- |
- |
||||||
Economic Factors |
- |
- |
- |
10 |
(10) |
- |
||||||
Production |
- |
- |
- |
(3,105) |
- |
(3,105) |
||||||
At December 31, 2016 |
- |
- |
- |
16,596 |
8,465 |
25,061 |
||||||
Light Crude Oil & |
||||||||||||
NETHERLANDS |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Technical Revisions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Production |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
48,199 |
48,688 |
96,887 |
48,199 |
48,688 |
96,887 |
- |
- |
- |
- |
- |
- |
Discoveries |
233 |
145 |
378 |
233 |
145 |
378 |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
8,104 |
8,782 |
16,886 |
8,104 |
8,782 |
16,886 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
20,790 |
(15,818) |
4,972 |
20,790 |
(15,818) |
4,972 |
- |
- |
- |
- |
- |
- |
Acquisitions |
2,654 |
1,446 |
4,100 |
2,654 |
1,446 |
4,100 |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
(128) |
(59) |
(187) |
(128) |
(59) |
(187) |
- |
- |
- |
- |
- |
- |
Production |
(17,502) |
- |
(17,502) |
(17,502) |
- |
(17,502) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
62,350 |
43,184 |
105,534 |
62,350 |
43,184 |
105,534 |
- |
- |
- |
- |
- |
- |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
88 |
83 |
171 |
8,122 |
8,198 |
16,320 |
||||||
Discoveries |
1 |
1 |
2 |
40 |
25 |
65 |
||||||
Extensions & Improved Recovery |
3 |
7 |
10 |
1,353 |
1,470 |
2,823 |
||||||
Technical Revisions |
17 |
(31) |
(14) |
3,482 |
(2,667) |
815 |
||||||
Acquisitions |
5 |
3 |
8 |
447 |
244 |
691 |
||||||
Dispositions |
- |
- |
- |
- |
- |
- |
||||||
Economic Factors |
(1) |
(0) |
(1) |
(22) |
(10) |
(32) |
||||||
Production |
(32) |
- |
(32) |
(2,949) |
- |
(2,949) |
||||||
At December 31, 2016 |
81 |
63 |
144 |
10,473 |
7,260 |
17,733 |
||||||
Light Crude Oil & |
||||||||||||
UNITED STATES |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
2,034 |
3,818 |
5,852 |
2,034 |
3,818 |
5,852 |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
1,105 |
1,644 |
2,749 |
1,105 |
1,644 |
2,749 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
178 |
271 |
449 |
178 |
271 |
449 |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
(4) |
(6) |
(10) |
(4) |
(6) |
(10) |
- |
- |
- |
- |
- |
- |
Production |
(144) |
- |
(144) |
(144) |
- |
(144) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
3,169 |
5,727 |
8,896 |
3,169 |
5,727 |
8,896 |
- |
- |
- |
- |
- |
- |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
2,170 |
4,378 |
6,548 |
2,170 |
4,378 |
6,548 |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
1,011 |
1,578 |
2,589 |
1,011 |
1,578 |
2,589 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
(129) |
(460) |
(589) |
(129) |
(460) |
(589) |
- |
- |
- |
- |
- |
- |
Acquisitions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
(6) |
(15) |
(21) |
(6) |
(15) |
(21) |
- |
- |
- |
- |
- |
- |
Production |
(77) |
- |
(77) |
(77) |
- |
(77) |
- |
- |
- |
- |
- |
- |
At December 31, 2016 |
2,969 |
5,481 |
8,450 |
2,969 |
5,481 |
8,450 |
- |
- |
- |
- |
- |
- |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
346 |
698 |
1,044 |
2,742 |
5,246 |
7,988 |
||||||
Discoveries |
- |
- |
- |
- |
- |
- |
||||||
Extensions & Improved Recovery |
141 |
219 |
360 |
1,415 |
2,127 |
3,541 |
||||||
Technical Revisions |
(62) |
(155) |
(217) |
94 |
39 |
134 |
||||||
Acquisitions |
- |
- |
- |
- |
- |
- |
||||||
Dispositions |
- |
- |
- |
- |
- |
- |
||||||
Economic Factors |
(2) |
(2) |
(4) |
(7) |
(11) |
(18) |
||||||
Production |
(11) |
- |
(11) |
(168) |
- |
(168) |
||||||
At December 31, 2016 |
412 |
760 |
1,172 |
4,076 |
7,401 |
11,477 |
||||||
Light Crude Oil & |
||||||||||||
TOTAL COMPANY |
Total Oil (4) |
Medium Crude Oil |
Heavy Oil |
Tight Oil | ||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
At December 31, 2015 |
79,510 |
43,635 |
123,145 |
79,491 |
43,629 |
123,120 |
9 |
3 |
12 |
10 |
3 |
13 |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
4,948 |
4,294 |
9,242 |
4,948 |
4,294 |
9,242 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
4,492 |
(1,044) |
3,450 |
4,499 |
(1,040) |
3,459 |
(9) |
(3) |
(12) |
4 |
(1) |
3 |
Acquisitions |
5,250 |
1,841 |
7,091 |
5,250 |
1,841 |
7,091 |
- |
- |
- |
- |
- |
- |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Economic Factors |
(66) |
(32) |
(98) |
(66) |
(32) |
(98) |
- |
- |
- |
- |
- |
- |
Production |
(9,243) |
- |
(9,243) |
(9,241) |
- |
(9,241) |
- |
- |
- |
(2) |
- |
(2) |
At December 31, 2016 |
84,891 |
48,694 |
133,587 |
84,881 |
48,692 |
133,573 |
- |
- |
- |
12 |
2 |
14 |
Total Gas (4) |
Conventional Natural Gas |
Coal Bed Methane (5) |
Shale Gas (5) | |||||||||
Proved + |
Proved + |
Proved + |
Proved + | |||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
Factors |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
At December 31, 2015 |
395,788 |
258,097 |
653,885 |
385,637 |
252,705 |
638,342 |
8,210 |
4,917 |
13,127 |
1,942 |
475 |
2,417 |
Discoveries |
233 |
145 |
378 |
233 |
145 |
378 |
- |
- |
- |
- |
- |
- |
Extensions & Improved Recovery |
31,230 |
66,935 |
98,165 |
31,230 |
66,935 |
98,165 |
- |
- |
- |
- |
- |
- |
Technical Revisions |
58,693 |
(25,131) |
33,562 |
57,408 |
(24,805) |
32,603 |
1,394 |
(135) |
1,259 |
(110) |
(191) |
(301) |
Acquisitions |
26,914 |
12,138 |
39,052 |
26,842 |
12,051 |
38,893 |
72 |
87 |
159 |
- |
- |
- |
Dispositions |
(353) |
(132) |
(485) |
(353) |
(132) |
(485) |
- |
- |
- |
- |
- |
- |
Economic Factors |
(1,448) |
(756) |
(2,204) |
(746) |
(564) |
(1,310) |
(702) |
(192) |
(894) |
- |
- |
- |
Production |
(72,671) |
- |
(72,671) |
(71,297) |
- |
(71,297) |
(913) |
- |
(913) |
(461) |
- |
(461) |
At December 31, 2016 |
438,386 |
311,296 |
749,682 |
428,954 |
306,335 |
735,289 |
8,061 |
4,677 |
12,738 |
1,371 |
284 |
1,655 |
Natural Gas Liquids |
BOE |
|||||||||||
Proved + |
Proved + |
|||||||||||
Proved Probable P+P (1) (2) |
Proved |
Probable |
Probable |
Proved |
Probable |
Probable |
||||||
Factors |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(Mboe) |
||||||
At December 31, 2015 |
15,229 |
13,532 |
28,761 |
160,706 |
100,184 |
260,889 |
||||||
Discoveries |
1 |
1 |
2 |
40 |
25 |
65 |
||||||
Extensions & Improved Recovery |
1,556 |
1,051 |
2,607 |
11,709 |
16,502 |
28,210 |
||||||
Technical Revisions |
1,959 |
(1,274) |
685 |
16,233 |
(6,506) |
9,730 |
||||||
Acquisitions |
1,050 |
474 |
1,524 |
10,787 |
4,337 |
15,123 |
||||||
Dispositions |
(8) |
(3) |
(11) |
(67) |
(25) |
(92) |
||||||
Economic Factors |
(34) |
(51) |
(85) |
(340) |
(210) |
(550) |
||||||
Production |
(1,897) |
- |
(1,897) |
(23,253) |
- |
(23,253) |
||||||
At December 31, 2016 |
17,856 |
13,730 |
31,586 |
175,815 |
114,307 |
290,122 |
Notes: | |
(1) |
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(2) |
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(3) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(4) |
For reporting purposes, "Total Oil" is the sum of Light Crude oil and Medium Crude Oil, Heavy Oil and Tight Oil. For reporting purposes, "Total Gas" is the sum of Conventional Natural Gas, Coal Bed Methane and Shale Gas. |
(5) |
"Coal Bed Methane" and "Shale Gas" were considered "Unconventional Natural Gas" in previous years. NI 51-101 no longer differentiates between conventional and unconventional activities. |
The table below sets out the future development costs deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).
Table 9: Future Development Costs(1)
Total Proved |
Total Proved Plus Probable | |
(M$) |
Estimated Using Forecast Prices and Costs |
Estimated Using Forecast Prices and Costs |
Australia |
||
2017 |
9,420 |
9,420 |
2018 |
6,701 |
6,701 |
2019 |
51,052 |
51,052 |
2020 |
2,993 |
2,993 |
2021 |
3,052 |
57,174 |
Remainder |
25,062 |
48,320 |
Total for all years undiscounted |
98,280 |
175,660 |
Canada |
||
2017 |
77,141 |
101,695 |
2018 |
90,442 |
126,482 |
2019 |
81,623 |
128,701 |
2020 |
95,424 |
189,622 |
2021 |
59,376 |
175,978 |
Remainder |
17,542 |
51,883 |
Total for all years undiscounted |
421,548 |
774,361 |
France |
||
2017 |
39,113 |
60,593 |
2018 |
29,528 |
49,613 |
2019 |
23,548 |
107,737 |
2020 |
6,753 |
40,020 |
2021 |
14,167 |
23,931 |
Remainder |
10,363 |
35,668 |
Total for all years undiscounted |
123,472 |
317,562 |
Germany |
||
2017 |
2,183 |
3,562 |
2018 |
584 |
3,272 |
2019 |
8,499 |
30,655 |
2020 |
154 |
6,863 |
2021 |
153 |
41,162 |
Remainder |
694 |
3,167 |
Total for all years undiscounted |
12,267 |
88,681 |
Ireland |
||
2017 |
1,311 |
1,311 |
2018 |
- |
- |
2019 |
1,706 |
1,706 |
2020 |
16,890 |
16,890 |
2021 |
- |
- |
Remainder |
15,505 |
15,505 |
Total for all years undiscounted |
35,412 |
35,412 |
Netherlands |
||
2017 |
2,200 |
7,790 |
2018 |
13,525 |
15,009 |
2019 |
604 |
4,838 |
2020 |
385 |
4,278 |
2021 |
287 |
8,095 |
Remainder |
5,638 |
5,637 |
Total for all years undiscounted |
22,639 |
45,647 |
United States |
||
2017 |
10,500 |
10,500 |
2018 |
18,426 |
36,468 |
2019 |
18,207 |
48,039 |
2020 |
13,506 |
42,806 |
2021 |
- |
- |
Remainder |
- |
1 |
Total for all years undiscounted |
60,639 |
137,814 |
Total Company |
||
2017 |
141,868 |
194,871 |
2018 |
159,206 |
237,545 |
2019 |
185,239 |
372,728 |
2020 |
136,105 |
303,472 |
2021 |
77,035 |
306,340 |
Remainder |
74,804 |
160,181 |
Total for all years undiscounted |
774,257 |
1,575,137 |
Note: | |
(1) |
The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
Vermilion expects to source its capital expenditure requirements from internally generated cash flow and, as appropriate, from Vermilion's existing credit facility or equity or debt financing. It is anticipated that costs of funding the future development costs will not impact development of its properties or Vermilion's reserves or future net revenue.
CONTINGENT RESOURCES
Summary information regarding contingent resources and net present value of future net revenues from contingent resources are set forth below and are derived, in each case, from the GLJ Resources Assessment. The GLJ Resources Assessment was prepared in accordance with COGEH and NI-51-101 by GLJ, an independent qualified reserve evaluator. All contingent resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2016. Contingent resources are in addition to reserves estimated in the GLJ Report.
A range of contingent resources estimates (low, best and high) were prepared by GLJ. See notes 6 to 8 of the tables below for a description of low estimate, best estimate and high estimate.
The GLJ Resources Assessment estimated gross risked contingent resources with a project maturity subclass of "Development Pending" of 120.4 million boe (low estimate) to 309.4 million boe (high estimate), with a best estimate of 198.5 million boe. Contingent resources are in addition to reserves estimated in the GLJ Report.
The GLJ Resources Assessment estimated gross risked contingent resources with a project maturity subclass of "Development Unclarified" of 10.7 million boe (low estimate) to 28.7 million boe (high estimate), with a best estimate of 19.5 million boe.
An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
Table 10: Summary of Risked Oil and Gas Contingent Resources as at December 31, 2016 (1) (2) - Forecast Prices and Costs (3) (4)
Light Crude Oil & |
Conventional |
Coal Bed |
Natural Gas |
BOE |
Unrisked | ||||||||||||||||||||||
Resources |
Medium Crude Oil |
Natural Gas |
Methane |
Liquids |
BOE | ||||||||||||||||||||||
Project |
Chance |
||||||||||||||||||||||||||
Maturity |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
of Dev. |
Gross |
Net | ||||||||||||||
Sub-Class |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(%) (9) |
(Mboe) |
(Mboe) | ||||||||||||||
Contingent (1C) - Low Estimate |
|||||||||||||||||||||||||||
Development Pending(10) |
|||||||||||||||||||||||||||
Australia(11) |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Canada(12) |
13,145 |
9,681 |
250,957 |
226,293 |
1,455 |
1,382 |
19,917 |
15,769 |
75,131 |
63,396 |
81.9% |
91,750 |
77,305 | ||||||||||||||
France(13) |
14,152 |
13,241 |
969 |
969 |
- |
- |
- |
- |
14,314 |
13,403 |
86.8% |
16,486 |
15,438 | ||||||||||||||
Germany(14) |
- |
- |
17,317 |
15,138 |
- |
- |
- |
- |
2,886 |
2,523 |
78.3% |
3,686 |
3,222 | ||||||||||||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Netherlands(15) |
- |
- |
10,336 |
10,336 |
- |
- |
2 |
2 |
1,725 |
1,725 |
81.4% |
2,119 |
2,119 | ||||||||||||||
USA(16) |
20,581 |
17,072 |
18,952 |
15,720 |
- |
- |
2,627 |
2,179 |
26,367 |
21,871 |
90.0% |
29,296 |
24,300 | ||||||||||||||
Total |
47,878 |
39,994 |
298,531 |
268,456 |
1,455 |
1,382 |
22,546 |
17,950 |
120,423 |
102,918 |
84.0% |
143,337 |
122,384 | ||||||||||||||
Contingent (2C) - Best Estimate |
|||||||||||||||||||||||||||
Development Pending(10) |
|||||||||||||||||||||||||||
Australia(11) |
2,440 |
2,440 |
- |
- |
- |
- |
- |
- |
2,440 |
2,440 |
80.0% |
3,050 |
3,050 | ||||||||||||||
Canada(12) |
25,648 |
18,373 |
389,272 |
346,617 |
3,534 |
3,357 |
29,537 |
22,869 |
120,653 |
99,571 |
80.3% |
150,178 |
123,661 | ||||||||||||||
France(13) |
27,543 |
25,702 |
1,246 |
1,246 |
- |
- |
- |
- |
27,751 |
25,908 |
85.1% |
32,628 |
30,453 | ||||||||||||||
Germany(14) |
- |
- |
29,595 |
25,886 |
- |
- |
- |
- |
4,933 |
4,314 |
78.3% |
6,300 |
5,510 | ||||||||||||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Netherlands(15) |
- |
- |
28,521 |
28,521 |
- |
- |
6 |
6 |
4,760 |
4,760 |
81.3% |
5,853 |
5,853 | ||||||||||||||
USA(16) |
29,466 |
24,441 |
27,811 |
23,069 |
- |
- |
3,855 |
3,197 |
37,956 |
31,483 |
90.0% |
42,173 |
34,981 | ||||||||||||||
Total |
85,097 |
70,956 |
476,445 |
425,339 |
3,534 |
3,357 |
33,398 |
26,072 |
198,493 |
168,476 |
82.6% |
240,182 |
203,508 | ||||||||||||||
Contingent (3C) - High Estimate |
|||||||||||||||||||||||||||
Development Pending(10) |
|||||||||||||||||||||||||||
Australia(11) |
3,280 |
3,280 |
- |
- |
- |
- |
- |
- |
3,280 |
3,280 |
80.0% |
4,100 |
4,100 | ||||||||||||||
Canada(12) |
52,590 |
37,459 |
567,390 |
500,749 |
5,174 |
4,788 |
41,650 |
31,616 |
189,667 |
153,331 |
79.2% |
239,562 |
193,233 | ||||||||||||||
France(13) |
43,866 |
40,873 |
1,609 |
1,609 |
- |
- |
- |
- |
44,134 |
41,141 |
84.3% |
52,336 |
48,774 | ||||||||||||||
Germany(14) |
- |
- |
54,150 |
47,382 |
- |
- |
- |
- |
9,025 |
7,897 |
78.3% |
11,526 |
10,086 | ||||||||||||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Netherlands(15) |
- |
- |
50,159 |
50,159 |
- |
- |
13 |
13 |
8,373 |
8,373 |
80.5% |
10,403 |
10,403 | ||||||||||||||
USA(16) |
42,381 |
35,152 |
40,945 |
33,961 |
- |
- |
5,675 |
4,707 |
54,880 |
45,519 |
90.0% |
60,977 |
50,577 | ||||||||||||||
Total |
142,117 |
116,764 |
714,253 |
633,860 |
5,174 |
4,788 |
47,338 |
36,336 |
309,359 |
259,541 |
81.6% |
378,904 |
317,173 | ||||||||||||||
Light Crude Oil & |
Conventional |
Coal Bed |
Natural Gas |
BOE |
Unrisked | ||||||||||||||||||||||
Resources |
Medium Crude Oil |
Natural Gas |
Methane |
Liquids |
BOE | ||||||||||||||||||||||
Project |
Chance |
||||||||||||||||||||||||||
Maturity |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
of Dev. |
Gross |
Net | ||||||||||||||
Sub-Class |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(%) (9) |
(Mboe) |
(Mboe) | ||||||||||||||
Contingent (1C) - Low Estimate |
|||||||||||||||||||||||||||
Development Unclarified(17) |
|||||||||||||||||||||||||||
Australia |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Canada(18) |
- |
- |
44,744 |
39,976 |
- |
- |
897 |
745 |
8,354 |
7,408 |
58.2% |
14,361 |
12,743 | ||||||||||||||
France(19) |
1,511 |
1,434 |
- |
- |
- |
- |
- |
- |
1,511 |
1,434 |
42.4% |
3,560 |
3,376 | ||||||||||||||
Germany |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Netherlands |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Total |
1,511 |
1,434 |
44,744 |
39,976 |
- |
- |
897 |
745 |
9,865 |
8,842 |
55.0% |
17,921 |
16,119 | ||||||||||||||
Contingent (2C) - Best Estimate |
|||||||||||||||||||||||||||
Development Unclarified(17) |
|||||||||||||||||||||||||||
Australia |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Canada(18) |
- |
- |
75,428 |
66,726 |
- |
- |
1,640 |
1,339 |
14,211 |
12,460 |
57.2% |
24,859 |
21,796 | ||||||||||||||
France(19) |
2,539 |
2,410 |
- |
- |
- |
- |
- |
- |
2,539 |
2,410 |
44.6% |
5,690 |
5,398 | ||||||||||||||
Germany |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Netherlands(20) |
- |
- |
16,351 |
15,777 |
- |
- |
32 |
16 |
2,757 |
2,646 |
49.4% |
5,580 |
5,301 | ||||||||||||||
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Total |
2,539 |
2,410 |
91,779 |
82,503 |
- |
- |
1,672 |
1,355 |
19,507 |
17,516 |
54.0% |
36,129 |
32,495 | ||||||||||||||
Contingent (3C) - High Estimate |
|||||||||||||||||||||||||||
Development Unclarified(17) |
|||||||||||||||||||||||||||
Australia |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Canada(18) |
- |
- |
103,491 |
89,867 |
- |
- |
2,178 |
1,727 |
19,427 |
16,705 |
57.6% |
33,746 |
29,063 | ||||||||||||||
France(19) |
3,825 |
3,632 |
- |
- |
- |
- |
- |
- |
3,825 |
3,632 |
46.4% |
8,250 |
7,829 | ||||||||||||||
Germany |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Netherlands(20) |
- |
- |
32,346 |
31,475 |
- |
- |
48 |
24 |
5,439 |
5,270 |
53.4% |
10,184 |
9,761 | ||||||||||||||
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | ||||||||||||||
Total |
3,825 |
3,632 |
135,837 |
121,342 |
- |
- |
2,226 |
1,751 |
28,691 |
25,607 |
55.0% |
52,180 |
46,653 |
Table 11: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2016 - Forecast Prices and Costs (3)
Resources Project |
||||||||||
Maturity Sub-Class |
Before Income Taxes, Discounted at (5) |
After Income Taxes, Discounted at (5) | ||||||||
(M$) |
0% |
5% |
10% |
15% |
20% |
0% |
5% |
10% |
15% |
20% |
Contingent (1C) - Low Estimate (6) |
||||||||||
Development Pending (10) |
||||||||||
Australia(11) |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Canada(12) |
1,469,731 |
806,673 |
468,784 |
284,859 |
179,205 |
567,431 |
315,876 |
182,036 |
107,244 |
107,244 |
France(13) |
819,095 |
435,463 |
247,355 |
146,903 |
90,157 |
582,296 |
295,394 |
158,897 |
88,278 |
49,769 |
Germany(14) |
29,787 |
19,161 |
11,552 |
6,390 |
2,959 |
20,027 |
11,662 |
5,658 |
1,665 |
(894) |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands(15) |
51,663 |
37,509 |
28,134 |
21,720 |
17,177 |
27,656 |
19,744 |
14,440 |
10,833 |
8,313 |
USA(16) |
875,320 |
424,777 |
223,556 |
125,266 |
73,505 |
562,210 |
269,146 |
138,253 |
74,966 |
42,140 |
Total |
3,245,596 |
1,723,583 |
979,381 |
585,138 |
363,003 |
2,261,816 |
1,163,377 |
633,124 |
357,778 |
206,572 |
Contingent (2C) - Best Estimate (7) |
||||||||||
Development Pending (10) |
||||||||||
Australia(11) |
102,151 |
60,643 |
36,438 |
22,134 |
13,559 |
26,695 |
12,642 |
5,228 |
1,407 |
(483) |
Canada(12) |
2,749,285 |
1,453,434 |
840,871 |
519,322 |
337,021 |
2,003,094 |
1,033,233 |
579,568 |
345,415 |
215,410 |
France(13) |
1,730,450 |
899,321 |
508,686 |
305,273 |
191,641 |
1,230,218 |
615,216 |
334,091 |
191,820 |
114,668 |
Germany(14) |
103,451 |
71,870 |
50,479 |
35,968 |
25,990 |
74,526 |
50,615 |
34,375 |
23,449 |
16,048 |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands(15) |
160,324 |
110,209 |
79,494 |
59,475 |
45,757 |
86,998 |
58,171 |
40,486 |
29,074 |
21,367 |
USA(16) |
1,561,749 |
736,050 |
390,965 |
226,282 |
139,356 |
1,007,434 |
471,250 |
247,014 |
140,765 |
85,218 |
Total |
6,407,410 |
3,331,527 |
1,906,933 |
1,168,454 |
753,324 |
4,428,965 |
2,241,127 |
1,240,762 |
731,930 |
452,228 |
Contingent (3C) - High Estimate (8) |
||||||||||
Development Pending (10) |
||||||||||
Australia(11) |
190,589 |
116,134 |
72,383 |
46,105 |
29,966 |
63,277 |
36,147 |
20,606 |
11,695 |
6,558 |
Canada(12) |
5,020,914 |
2,498,830 |
1,392,053 |
837,248 |
532,137 |
3,660,740 |
1,782,927 |
966,824 |
563,961 |
346,457 |
France(13) |
2,954,319 |
1,525,736 |
866,518 |
524,651 |
332,885 |
2,100,039 |
1,051,087 |
577,537 |
337,293 |
205,471 |
Germany(14) |
252,820 |
174,810 |
124,211 |
90,601 |
67,647 |
184,908 |
126,647 |
88,732 |
63,652 |
46,653 |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands(15) |
315,718 |
211,894 |
151,407 |
113,180 |
87,473 |
171,705 |
113,248 |
79,106 |
57,702 |
43,468 |
USA(16) |
2,640,857 |
1,172,989 |
614,674 |
358,063 |
224,065 |
1,708,970 |
754,738 |
392,026 |
226,212 |
140,202 |
Total |
11,375,217 |
5,700,393 |
3,221,246 |
1,969,848 |
1,274,173 |
7,889,639 |
3,864,794 |
2,124,831 |
1,260,515 |
788,809 |
Contingent (1C) - Low Estimate (6) |
||||||||||
Development Unclarified (17) |
||||||||||
Australia |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Canada(18) |
81,186 |
32,743 |
13,139 |
4,876 |
1,294 |
58,404 |
22,305 |
7,967 |
2,138 |
(237) |
France(19) |
109,246 |
56,246 |
30,550 |
17,349 |
10,224 |
77,091 |
38,798 |
20,522 |
11,315 |
6,453 |
Germany |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands(20) |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Total |
190,432 |
88,989 |
43,689 |
22,225 |
11,518 |
135,495 |
61,103 |
28,489 |
13,453 |
6,216 |
Contingent (2C) - Best Estimate (7) |
||||||||||
Development Unclarified (17) |
||||||||||
Australia |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Canada(18) |
149,050 |
60,346 |
25,047 |
10,046 |
3,342 |
107,851 |
41,837 |
15,842 |
5,073 |
466 |
France(19) |
198,194 |
95,437 |
49,664 |
27,439 |
15,881 |
140,218 |
66,266 |
33,693 |
18,135 |
10,199 |
Germany |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands(20) |
63,974 |
35,129 |
18,879 |
9,435 |
3,747 |
34,153 |
16,587 |
6,654 |
985 |
(2,320) |
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Total |
411,218 |
190,912 |
93,590 |
46,920 |
22,970 |
282,222 |
124,690 |
56,189 |
24,193 |
8,345 |
Contingent (3C) - High Estimate (8) |
||||||||||
Development Unclarified (17) |
||||||||||
Australia |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Canada(18) |
250,258 |
97,428 |
41,153 |
18,033 |
7,732 |
181,844 |
68,851 |
27,516 |
10,840 |
3,628 |
France(19) |
320,784 |
143,786 |
72,178 |
39,161 |
22,464 |
227,214 |
100,294 |
49,348 |
26,186 |
14,667 |
Germany |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Netherlands(20) |
176,750 |
94,921 |
54,922 |
33,238 |
20,539 |
96,181 |
48,927 |
25,901 |
13,615 |
6,587 |
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Total |
747,792 |
336,135 |
168,253 |
90,432 |
50,735 |
505,239 |
218,072 |
102,765 |
50,641 |
24,882 |
Notes: | ||
(1) |
Contingent resources are defined in the COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated, as at a given date, and that the resources can be profitably produced in the future. The risked net present value of the future net revenue from the contingent resources does not represent the fair market value of the contingent resources. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein. | |
(2) |
GLJ prepared the estimates of contingent resources shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. | |
(3) |
The forecast price and cost assumptions utilized in the year-end 2016 reserves report were also utilized by GLJ in preparing the GLJ Resource Assessment. See "GLJ December 31, 2016 Forecast Prices" in this AIF. | |
(4) |
"Gross" contingent resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net" contingent resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in contingent resources. | |
(5) |
The risked net present value of future net revenue attributable to the contingent resources does not represent the fair market value of the contingent resources. Estimated abandonment and reclamation costs have been included in the evaluation. | |
(6) |
This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. | |
(7) |
This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. | |
(8) |
This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. | |
(9) |
The Chance of Development (CoDev) is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows: | |
| ||
(10) |
Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development). | |
(11) |
Contingent resources for Australia have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these contingent resources on commercial production is $142 MM and the expected timeline is between 7 and 9 years. The specific contingencies for these resources are corporate commitment and development timing. | |
(12) |
Contingent resources for Canada have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these contingent resources on commercial production is $1,170 MM and the expected timeline is between 1 and 12 years. The specific contingencies for these resources are corporate commitment and development timing. | |
(13) |
Contingent resources for France have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these contingent resources on commercial production is $550 MM and the expected timeline is between 3and 10 years. The specific contingencies for these resources are corporate commitment and development timing. | |
(14) |
Contingent resources for Germany have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these contingent resources on commercial production is $55 MM and the expected timeline is between 3 and 5 years. The specific contingencies for these resources are corporate commitment and development timing. | |
(15) |
Contingent resources for Netherlands have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these contingent resources on commercial production is $34 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are corporate commitment and development timing. | |
(16) |
Contingent resources for USA have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these contingent resources on commercial production is $431 MM and the expected timeline is between 4 and 12 years. The specific contingencies for these resources are corporate commitment and development timing. | |
(17) |
Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. | |
(18) |
In Canada, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 14.2 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $108 MM with an expected timeline of 4 to 15 years. | |
Ferrier Notikewin |
Based on contingencies related to corporate commitment and development timing that is greater than 10 years, GLJ has estimated risked unclarified best estimate contingent resources at 5.1 mmboe and the risked estimated cost to bring these resources on commercial production is $36 MM. The expected timeline is 11 to 15 years. | |
Ferrier Falher |
Based on contingencies related to corporate commitment and development timing that is greater than 10 years, GLJ has estimated risked unclarified best estimate contingent resources at 3.8 mmboe and the risked estimated cost to bring these resources on commercial production is $28 MM. The expected timeline is 11 to 15 years. | |
West Pembina Glauconite |
Based on contingencies related to corporate commitment and development timing as well as economic risk related to capital and operating cost uncertainty due to limited horizontal development in proximity to interest lands, GLJ has estimated risked unclarified best estimate contingent resources at 5.3 mmboe and the risked estimated cost to bring these resources on commercial production is $44 MM. The expected timeline is 4 to 10 years. | |
(19) |
In France, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 2.5 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $36 MM with an expected timeline of 8 to 10 years. | |
Charmottes |
Based on contingencies related to corporate commitment and development timing, along with the project still being in the pre-development study/sourcing stage related to waterflood development, GLJ has estimated risked unclarified best estimate contingent resources at 1.3 mmboe and the risked estimated cost to bring these resources on commercial production is $29 MM. The expected timeline is 8 to 10 years. | |
Chaunoy |
Based on contingencies related to corporate commitment and development timing, along with a CO2 pilot project still being in the conceptual study stage, GLJ has estimated risked unclarified best estimate contingent resources at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $7 MM. The expected timeline is 9 to 10 years. | |
(20) |
In the Netherlands, GLJ has estimated an aggregate of risked unclarified best estimate contingent resources of 2.8 mmboe for the projects outlined below. Utilizing established recovery technology, the risked estimated to bring these resources on commercial production an aggregate of $45 MM with an expected timeline of 3 to 9 years. | |
Netherlands East |
Based on contingencies related to corporate commitment and development timing along with proof-of-concept utilizing directional drilling and unknown deliverability from Zechstein carbonates, GLJ has estimated risked unclarified best estimate contingent resources at 1.6 mmboe and the risked estimated cost to bring these resources on commercial production is $24 MM. The expected timeline is 3 to 9 years. | |
Netherlands West |
Based on contingencies related to corporate commitment and development timing along with further study required regarding the deliverability of the Bunter sands, GLJ has estimated risked unclarified best estimate contingent resources at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $21 MM. The expected timeline is 5 years. | |
PROSPECTIVE RESOURCES
Summary information regarding prospective resources and net present value of future net revenues from prospective resources are set forth below and are derived, in each case, from the GLJ Resources Assessment. The GLJ Resources Assessment was prepared in accordance with COGEH and NI-51-101 by GLJ, an independent qualified reserve evaluator. All prospective resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2016. Prospective resources are in addition to reserves estimated in the GLJ Report.
A range of prospective resources estimates (low, best and high) were prepared by GLJ. See notes 6 to 8 of the tables below for a description of low estimate, best estimate and high estimate.
The GLJ Resources Assessment estimated gross risked prospective resources of 45.2 million boe (low estimate) to 147.9 million boe (high estimate), with a best estimate of 89.5 million boe.
An estimate of risked net present value of future net revenue of prospective resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes prospective resources that are considered too uncertain with respect to the chance of development and chance of discovery to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
Table 12: Summary of Risked Oil and Gas Prospective Resources as at December 31, 2016 (1) (2) - Forecast Prices and Costs (3) (4)
Light Crude Oil & |
Conventional |
Coal Bed |
Natural Gas |
BOE |
Unrisked | |||||||||||||
Resources |
Medium Crude Oil |
Natural Gas |
Methane |
Liquids |
BOE | |||||||||||||
Project |
Chance of |
|||||||||||||||||
Maturity |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Commerciality |
Gross |
Net | |||||
Sub-Class |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
(%) (9) |
(Mboe) |
(Mboe) | |||||
Prospective - Low Estimate |
||||||||||||||||||
Prospect(10) |
||||||||||||||||||
Australia(11) |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |||||
Canada(12) |
185 |
166 |
95,116 |
87,039 |
- |
- |
5,458 |
4,703 |
21,496 |
19,376 |
32.9% |
65,396 |
58,986 | |||||
France(13) |
3,379 |
3,044 |
- |
- |
- |
- |
- |
- |
3,379 |
3,044 |
49.0% |
6,898 |
6,253 | |||||
Germany(14) |
- |
- |
88,561 |
76,691 |
- |
- |
- |
- |
14,760 |
12,782 |
24.6% |
59,995 |
51,954 | |||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |||||
Netherlands(15) |
- |
- |
33,037 |
31,606 |
- |
- |
16 |
14 |
5,522 |
5,282 |
11.6% |
47,452 |
45,232 | |||||
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |||||
Total |
3,564 |
3,210 |
216,714 |
195,336 |
- |
- |
5,474 |
4,717 |
45,157 |
40,484 |
25.1% |
179,741 |
162,425 | |||||
Prospective - Best Estimate |
||||||||||||||||||
Prospect(10) |
||||||||||||||||||
Australia(11) |
579 |
579 |
- |
- |
- |
- |
- |
- |
579 |
579 |
48.0% |
1,207 |
1,027 | |||||
Canada(12) |
2,263 |
2,029 |
170,797 |
153,565 |
- |
- |
10,195 |
8,412 |
40,924 |
36,035 |
34.3% |
119,269 |
105,029 | |||||
France(13) |
9,609 |
8,532 |
- |
- |
- |
- |
- |
- |
9,609 |
8,532 |
37.2% |
25,835 |
22,939 | |||||
Germany(14) |
- |
- |
169,557 |
147,917 |
- |
- |
- |
- |
28,260 |
24,653 |
24.6% |
114,865 |
100,205 | |||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |||||
Netherlands(15) |
- |
- |
60,647 |
57,618 |
- |
- |
30 |
27 |
10,138 |
9,630 |
11.8% |
85,890 |
81,192 | |||||
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |||||
Total |
12,451 |
11,140 |
401,001 |
359,100 |
- |
- |
10,225 |
8,439 |
89,510 |
79,429 |
25.8% |
347,066 |
310,392 | |||||
Prospective - High Estimate |
||||||||||||||||||
Prospect(10) |
||||||||||||||||||
Australia(11) |
1,462 |
1,462 |
- |
- |
- |
- |
- |
- |
1,462 |
1,462 |
48.0% |
3,046 |
3,046 | |||||
Canada(12) |
2,394 |
2,142 |
244,013 |
217,049 |
- |
- |
14,659 |
11,724 |
57,722 |
50,041 |
35.6% |
162,333 |
140,646 | |||||
France(13) |
21,406 |
19,496 |
- |
- |
- |
- |
- |
- |
21,406 |
19,496 |
48.4% |
44,243 |
40,766 | |||||
Germany(14) |
- |
- |
289,626 |
254,136 |
- |
- |
- |
- |
48,271 |
42,356 |
24.6% |
196,205 |
172,162 | |||||
Ireland |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |||||
Netherlands(15) |
- |
- |
114,102 |
106,974 |
- |
- |
59 |
52 |
19,076 |
17,881 |
11.9% |
159,744 |
148,690 | |||||
USA |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |||||
Total |
25,262 |
23,100 |
647,741 |
578,159 |
- |
- |
14,718 |
11,776 |
147,937 |
131,236 |
26.2% |
565,571 |
505,310 |
Table 13: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2016 - Forecast Prices and Costs (3)
Resources Project |
||||||||||
Maturity Sub-Class |
Before Income Taxes, Discounted at (5) |
After Income Taxes, Discounted at (5) | ||||||||
(M$) |
0% |
5% |
10% |
15% |
20% |
0% |
5% |
10% |
15% |
20% |
Prospective (Pr1) -Low Estimate (6) |
||||||||||
Prospect (10) |
||||||||||
Canada (12) |
273,867 |
127,001 |
60,110 |
27,921 |
11,751 |
198,318 |
85,907 |
35,748 |
12,466 |
1,407 |
France (13) |
151,213 |
75,323 |
38,554 |
20,217 |
10,789 |
102,347 |
48,093 |
22,638 |
10,518 |
4,652 |
Germany (14) |
155,230 |
65,643 |
24,054 |
5,229 |
(3,139) |
106,234 |
38,604 |
8,125 |
(4,675) |
(9,585) |
Netherlands (15) |
146,420 |
81,758 |
50,537 |
34,384 |
25,278 |
75,803 |
39,394 |
21,746 |
13,088 |
8,573 |
Total |
726,730 |
349,725 |
173,255 |
87,751 |
44,679 |
482,702 |
211,998 |
88,257 |
31,397 |
5,047 |
Prospective (Pr2) -Best Estimate (7) |
||||||||||
Prospect (10) |
||||||||||
Australia (11) |
46,694 |
25,575 |
14,527 |
8,526 |
5,152 |
18,252 |
9,659 |
5,268 |
2,957 |
1,705 |
Canada (12) |
727,622 |
350,852 |
183,676 |
102,149 |
59,257 |
528,484 |
248,071 |
122,227 |
63,175 |
33,061 |
France (13) |
517,189 |
263,016 |
143,095 |
82,612 |
50,242 |
362,550 |
176,276 |
91,520 |
50,373 |
29,196 |
Germany (14) |
572,696 |
240,171 |
105,603 |
47,332 |
20,454 |
415,985 |
166,082 |
66,349 |
24,697 |
6,525 |
Netherlands (15) |
364,314 |
193,047 |
120,340 |
83,689 |
62,715 |
195,684 |
99,659 |
59,140 |
39,348 |
28,449 |
Total |
2,228,515 |
1,072,661 |
567,241 |
324,308 |
197,820 |
1,520,955 |
699,747 |
344,504 |
180,550 |
98,936 |
Prospective (Pr3) -High Estimate (8) |
||||||||||
Prospect (10) |
||||||||||
Australia (11) |
150,518 |
78,083 |
43,242 |
25,161 |
15,218 |
62,445 |
31,968 |
17,425 |
9,981 |
5,947 |
Canada (12) |
1,110,298 |
500,889 |
256,708 |
143,539 |
85,330 |
808,440 |
354,301 |
174,070 |
92,184 |
51,196 |
France (13) |
1,550,119 |
742,476 |
388,981 |
219,441 |
131,689 |
1,098,279 |
514,614 |
263,597 |
145,437 |
85,435 |
Germany (14) |
1,215,756 |
520,750 |
240,583 |
116,696 |
57,872 |
897,478 |
370,617 |
162,227 |
72,477 |
31,319 |
Netherlands (15) |
785,423 |
409,343 |
255,631 |
178,273 |
133,629 |
425,214 |
216,893 |
132,001 |
90,034 |
66,319 |
Total |
4,812,114 |
2,251,541 |
1,185,145 |
683,110 |
423,738 |
3,291,856 |
1,488,393 |
749,320 |
410,113 |
240,216 |
Notes: | |
(1) |
Prospective resources are defined in the COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects. Prospective resources have both an associated chance of discovery (CoDis) and a chance of development (CoDev). There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. The estimates of prospective resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated, as at a given date, and that the resources can be profitably produced in the future. The risked net present value of the future net revenue from the prospective resources does not represent the fair market value of the prospective resources. Actual prospective resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein. |
(2) |
GLJ prepared the estimates of prospective resources shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. |
(3) |
The forecast price and cost assumptions utilized in the year-end 2016 reserves report were also utilized by GLJ in preparing the GLJ Resource Assessment. See "GLJ December 31, 2016 Forecast Prices" in this AIF. |
(4) |
"Gross" prospective resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net" prospective resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in prospective resources. |
(5) |
The risked net present value of future net revenue attributable to the prospective resources does not represent the fair market value of the prospective resources. Estimated abandonment and reclamation costs have been included in the evaluation. |
(6) |
This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. |
(7) |
This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. |
(8) |
This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. |
(9) |
The chance of commerciality is defined as the product of the chance of discovery and the chance of development. Chance of discovery is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Chance of development is defined as the estimated probability that, once discovered, a known accumulation will be commercially developed. |
The Chance of Development (CoDev) is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows: | |
The Chance of Discovery (CoDis) is defined in COGEH as the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. Five factors have been considered in determining the CoDis as follows:
| |
(10) |
GLJ has sub-classified the best estimate prospective resources by maturity status, consistent with the requirements of the COGE Handbook. These prospective resources have been sub-classified as "Prospect" which the COGE Handbook defines as a potential accumulation within a play that is sufficiently well defined to present a viable drilling target. |
(11) |
Prospective resources for Australia have been estimated based on development timing and reservoir risk, GLJ has estimated the CoDev at 80% and the CoDis at 60%. The corresponding chance of commerciality is 48%. Risked best estimate prospective resources have been estimated at .06 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is $17.2 MM. The expected development timeline is 8 years. |
(12) |
Prospective resources for Canada have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 86% and the aggregate CoDis at 40%. The corresponding chance of commerciality is 34%. Risked best estimate prospective resources have been estimated at an aggregate of 40.9 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $621.9 MM. The expected development timeline is 2 to 20 years. |
Wilrich Prospect: |
Based on reservoir risk, development timing and limited Wilrich development on the land base, GLJ has estimated the CoDev at 35% and the CoDis at 85%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 22.2 mmboe and the risked estimated cost to bring these resources on commercial production is $218 MM with an expected timeline of 2 to 8 years. | ||||
West Pembina Glauconite Prospect: |
Based on chance of discovery risk due to uncertainty regarding threshold for reservoir quality to support commercial development of resources with horizontal drilling, along with economic risk related to capital and operating cost uncertainty due to limited horizontal development in proximity to interest lands and chance of development risk related to corporate commitment and development timing. GLJ has estimated the CoDev at 34% and the CoDis at 90%. The corresponding chance of commerciality is 31%. Risked best estimate prospective resources have been estimated at 8.4 mmboe and the risked estimated cost to bring these resources on commercial production is $242 MM with an expected timeline of 6 to 14 years. | ||||
Drayton Valley Notikewin Prospect: |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 85%. The corresponding chance of commerciality is 60%. Risked best estimate prospective resources have been estimated at 4.6 mmboe and the risked estimated cost to bring these resources on commercial production is $69.3 MM. The expected development timeline is 10 to 12 years. | ||||
Saskatchewan Prospects |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 90% and the CoDis at 80%. The corresponding chance of commerciality is 72%. Risked best estimate prospective resources have been estimated at 3.0 mmboe and the risked estimated cost to bring these resources on commercial production is $63.6 MM with an expected timeline of 7 to 12 years | ||||
Ferrier Falher Prospect |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 90%. The corresponding chance of commerciality is 54%. Risked best estimate prospective resources have been estimated at 2.6 mmboe and the risked estimated cost to bring these resources on commercial production is $24.9 MM with an expected timeline of 16 to 20 years. | ||||
Utikuma Gilwood Prospect |
Based on reservoir risk, development timing and limited Gilwood development in the area, GLJ has estimated the CoDev at 60% and the CoDis at 50%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 0.2 mmboe and the risked estimated cost to bring these resources on commercial production is $3.2 MM with an expected timeline of 16 to 20 years. | ||||
(13) |
Prospective resources for France have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 52% and the aggregate CoDis at 71%. The corresponding chance of commerciality is 37%. Risked best estimate prospective resources have been estimated at an aggregate of 9.6 Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of $254.3 MM. The expected development timeline is 3 to 12 years. | ||||
Rachee Prospect |
Based on risk of closure and data quality along with development timing, GLJ has estimated the CoDev at 80% and the CoDis at 80%. The corresponding chance of commerciality is 64%. Risked best estimate prospective resources have been estimated at 3.4 mmboe and the risked estimated cost to bring these resources on commercial production is $125.0 MM with an expected timeline of 10 to 14 years. | ||||
Malnoue Prospect |
Based on reservoir, structure and trap risk along with development timing, GLJ has estimated the CoDev at 70% and the CoDis at 38%. The corresponding chance of commerciality is 27%. Risked best estimate prospective resources have been estimated at 1.4 mmboe and the risked estimated cost to bring these resources on commercial production is $31.6 MM with an expected timeline of 8 to 12 years. | ||||
West Lavergne Prospect |
Based on structure risk and development timing GLJ has estimated the CoDev at 80% and the CoDis at 70%. The corresponding chance of commerciality is 56%. Risked best estimate prospective resources have been estimated at 1.2 mmboe and the risked estimated cost to bring these resources on commercial production is $6.1 MM with an expected timeline of 4 years. | ||||
Champotran Prospect |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 80% and the CoDis at 80%. The corresponding chance of commerciality is 64%. Risked best estimate prospective resources have been estimated at 0.7 mmboe and the risked estimated cost to bring these resources on commercial production is $14.6 MM with an expected timeline of 7 to 8 years. | ||||
Cazaux Prospect |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 30%. The corresponding chance of commerciality is 21%. Risked best estimate prospective resources have been estimated at 0.6 mmboe and the risked estimated cost to bring these resources on commercial production is $10.3 MM with an expected timeline of 5 to 7 years. | ||||
Vulaines Prospect |
Based on reservoir and structure risk along with development timing, GLJ has estimated the CoDev at 80% and the CoDis at 40%. The corresponding chance of commerciality is 32%. Risked best estimate prospective resources have been estimated at 0.6 mmboe and the risked estimated cost to bring these resources on commercial production is $12.6 MM with an expected timeline of 5 to 6 years. | ||||
Phobos Prospect |
Based on reservoir, and closure risk, economic factors and development timing, GLJ has estimated the CoDev at 50% and the CoDis at 50%. The corresponding chance of commerciality is 25%. Risked best estimate prospective resources have been estimated at 0.5 mmboe and the risked estimated cost to bring these resources on commercial production is $20.6 MM with an expected timeline of 9 to 10 years. | ||||
Charmottes Prospect |
Based on reservoir risk and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 50%. The corresponding chance of commerciality is 30%. Risked best estimate prospective resources have been estimated at 0.5 mmboe and the risked estimated cost to bring these resources on commercial production is $18.5 MM with an expected timeline of 8 to 10 years. | ||||
Bernet Prospect |
Based on risks associated with reservoir, seal and trap along with economic factors, and development timing, GLJ has estimated the CoDev at 50% and the CoDis at 65%. The corresponding chance of commerciality is 33%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $6.7 MM with an expected timeline of 5 to 6 years. | ||||
Vert Le Grand Prospect |
Based on reservoir and structure risk along with development timing, GLJ has estimated the CoDev at 70% and the CoDis at 28%. The corresponding chance of commerciality is 20%. Risked best estimate prospective resources have been estimated at 0.2 mmboe and the risked estimated cost to bring these resources on commercial production is $3.6 MM with an expected timeline of 3 years. | ||||
Pays De Born Prospect |
Based on reservoir, seal and trap risk, along with economic factors and development timing, GLJ has estimated the CoDev at 50% and the CoDis at 50%. The corresponding chance of commerciality is 25%. Risked best estimate prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $2.6 MM with an expected timeline of 8 to 9 years. | ||||
Les Genets Prospect |
Based on reservoir, seal and closure risk, along with economic factors and development timing, GLJ has estimated the CoDev at 60% and the CoDis at 16%. The corresponding chance of commerciality is 9.6%. Risked best estimate prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $0.9 MM with an expected timeline of 9 years. | ||||
North Acacias Prospect |
Based on reservoir, seal and trap risk, along with economic factors and development timing, GLJ has estimated the CoDev at 70% and the CoDis at 39%. The corresponding chance of commerciality is 27%. Risked best estimate prospective resources have been estimated at 0.08 mmboe and the risked estimated cost to bring these resources on commercial production is $1.2 MM with an expected timeline of 6 to 7 years. | ||||
(14) |
Prospective resources for Germany have been estimated based on the individual prospects outlined below. GLJ has estimated the aggregate CoDev at 60% and the aggregate CoDis at 41%. The corresponding chance of commerciality is 25%. Risked best estimate prospective resources have been estimated at an aggregate of 28.3 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of 173.6MM. The expected development timeline is 2 to 15 years. | ||||
Ihlow Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 71%, and the CoDis at 51%. The corresponding chance of commerciality is 36%. Risked best estimate prospective resources have been estimated at 6.6 mmboe and the risked estimated cost to bring these resources on commercial production is $44.7 MM with an expected timeline of 8 years. | ||||
Wisselshorst A Prospect |
Based on seal and trap risk along with development timing , GLJ has estimated the CoDev at 90%, and the CoDis at 45%. The corresponding chance of commerciality is 41%. Risked best estimate prospective resources have been estimated at 4.8 mmboe and the risked estimated cost to bring these resources on commercial production is $32.2 MM with an expected timeline of 8 years. | ||||
Simonswolde South Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 71%, and the CoDis at 48%. The corresponding chance of commerciality is 34%. Risked best estimate prospective resources have been estimated at 4.1 mmboe and the risked estimated cost to bring these resources on commercial production is $14.6 MM with an expected timeline of 10 years. | ||||
Klosterseelte Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 49%, and the CoDis at 49%. The corresponding chance of commerciality is 24%. Risked best estimate prospective resources have been estimated at 2.8 mmboe and the risked estimated cost to bring these resources on commercial production is $12.2 MM with an expected timeline of 5 years. | ||||
Ohlendorf Prospect |
Based on source and trap risk along with development timing, GLJ has estimated the CoDev at 58%, and the CoDis at 30%. The corresponding chance of commerciality is 17%. Risked best estimate prospective resources have been estimated at 2.4 mmboe and the risked estimated cost to bring these resources on commercial production is $10.1 MM with an expected timeline of 15 years. | ||||
Wisselshorst B Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 90%, and the CoDis at 38%. The corresponding chance of commerciality is 34%. Risked best estimate prospective resources have been estimated at 2.3 mmboe and the risked estimated cost to bring these resources on commercial production is $17.9 MM with an expected timeline of 11 years. | ||||
Jeddeloh Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 38%, and the CoDis at 31%. The corresponding chance of commerciality is 12%. Risked best estimate prospective resources have been estimated at 2.3 mmboe and the risked estimated cost to bring these resources on commercial production is $18.5 MM with an expected timeline of 8 years. | ||||
Simonswolde North Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 62%, and the CoDis at 45%. The corresponding chance of commerciality is 28%. Risked best estimate prospective resources have been estimated at 1.4 mmboe and the risked estimated cost to bring these resources on commercial production is $5.6 MM with an expected timeline of 8 years. | ||||
Uphuser Meer Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 47%, and the CoDis at 51%. The corresponding chance of commerciality is 24%. Risked best estimate prospective resources have been estimated at 1.0 mmboe and the risked estimated cost to bring these resources on commercial production is $4.5 MM with an expected timeline of 9 years. | ||||
Burgmoor Z5 Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 63%, and the CoDis at 52%. The corresponding chance of commerciality is 33%. Risked best estimate prospective resources have been estimated at 0.7 mmboe and the risked estimated cost to bring these resources on commercial production is $2.8 MM with an expected timeline of 2 years. | ||||
Wellie Prospect |
Based on reservoir, seal and source risk along with development timing, GLJ has estimated the CoDev at 32%, and the CoDis at 20%. The corresponding chance of commerciality is 6%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $3 MM with an expected timeline of 11 years. | ||||
Otterstedt Prospect |
Based on reservoir, seal and trap risk along with development timing , GLJ has estimated the CoDev at 46%, and the CoDis at 34%. The corresponding chance of commerciality is 16%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $3.2 MM with an expected timeline of 14 years. | ||||
Widdernhausen East Prospect |
Based on reservoir, seal and trap risk along with development timing, GLJ has estimated the CoDev at 32%, and the CoDis at 44%. The corresponding chance of commerciality is 14%. Risked best estimate prospective resources have been estimated at 0.3 mmboe and the risked estimated cost to bring these resources on commercial production is $2.1 MM with an expected timeline of 12 years. | ||||
Ostervesede Prospect |
Based on reservoir and seal risk along with development timing, GLJ has estimated the CoDev at 23%, and the CoDis at 25%. The corresponding chance of commerciality is 6%. Risked best estimate prospective resources have been estimated at 0.1 mmboe and the risked estimated cost to bring these resources on commercial production is $0.7 MM with an expected timeline of 11 years. | ||||
(15) |
Prospective resources for Netherlands have been estimated based on the factors outlined below. GLJ has estimated the aggregate CoDev at 40% and the aggregate CoDis at 30%. The corresponding chance of commerciality is 12%. Risked best estimate prospective resources have been estimated at an aggregate of 10.1 mmboe. Utilizing established recovery technology, the risked estimated cost to bring these resources on commercial production is an aggregate of 88.2 MM with an expected timeline of 2 to 12 years. | ||||
Prospective resources for Netherlands East have been estimated based on the individual areas outlined below. GLJ has estimated the aggregate CoDev at 25% and the aggregate CoDis at 44%. The corresponding chance of commerciality is 11%. Risked best estimate prospective resources have been estimated at an aggregate of 8.0 mmboe and the risked estimated cost to bring these resources on commercial production is an aggregate of 66.3 MM with an expected timeline of 2 to 12 years. | |||||
| |||||
Prospective resources for Netherlands West have been estimated based on the factors outlined below. GLJ has estimated the aggregate CoDev at 65% and the aggregate CoDis at 28%. The corresponding chance of commerciality is 18%. Risked best estimate prospective resources have been estimated at an aggregate of 2.1 mmboe and the risked estimated cost to bring these resources on commercial production is an aggregate of$ 21.8 MM with an expected timeline of 2 to 9 years. | |||||
| |||||
ABOUT VERMILION
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel equivalent of oil. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Netbacks and Operating Recycle Ratio are measures that do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculations of similar measures for other entities. "Operating Recycle Ratio" is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost). "Netbacks" are per boe and per Mcf measures used in operational and capital allocation decisions. "Operating Netback" is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. Management assesses Operating Netback as a measure of the profitability and efficiency of our field operations. F&D (finding and development) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital, by the change in the reserves, incorporating revisions and production, for the same period.
SOURCE Vermilion Energy Inc.
CALGARY, Feb. 13, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on March 15, 2017 to all shareholders of record on February 23, 2017. The ex-dividend date for this payment is February 21, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
We commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016. We increased the proration factor by a further 25% beginning with the January 16, 2017 dividend payment. Eligible shareholders who have elected to participate in the Premium DividendTM component will receive a 1.5% premium on 50% of their participating shares, and the regular cash dividend on the remaining 50% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to continue increasing the proration during 2017, at the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, Jan. 13, 2017 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on February 15, 2017 to all shareholders of record on January 24, 2017. The ex-dividend date for this payment is January 20, 2017. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
We commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016. We increased the proration factor by a further 25% beginning with the January 16, 2017 dividend payment. Eligible shareholders who have elected to participate in the Premium DividendTM component will receive a 1.5% premium on 50% of their participating shares, and the regular cash dividend on the remaining 50% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to continue increasing the proration during 2017, at the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, Dec. 19, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We" or "Our") (TSX, NYSE: VET) is pleased to announce that we have completed the previously announced acquisition of interests in production and exploration assets in Germany (the "Acquisition") from Engie E&P Deutschland GmbH, for total consideration of €33 million ($46.2 million), based on the effective date of January 1, 2016. After adjustments for cash flows between the effective date and closing date, Vermilion's cash cost for the Acquisition is projected to be approximately €28.3 million ($39.6 million).
The Acquisition includes operated and non-operated interests in five oil and three gas producing fields, along with an operated interest in one exploration license (the "Assets"). Vermilion will assume operatorship of six of the eight producing fields, with the other fields operated by ExxonMobil Production Deutschland (EMPG) and Deutsche Erdoel AG (DEA).
Production from the Assets has averaged 2,000 boe/d (51% oil) in 2016 through the end of October. We expect to increase production by approximately 10% in 2017 based on budgeted capital investment of €3.6 million ($5.1 million). Using the current forward strip, we forecast fund flows from operations(1) of approximately €17.6 million ($24.9 million) from the Assets in 2017.
The Acquisition provides us with our first operated producing properties in Germany, and advances our objective of developing a material business unit in this country. Germany has a long history of oil and natural gas development, and a consistent fiscal framework with low political risk. The Assets are expected to be complementary with our existing European portfolio, offering similar subsurface characteristics and development opportunities.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 4.5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
(1) Fund flows from operations is a financial measure that does not have a standardized meaning prescribed by International Financial Reporting Standards (IFRS). Fund flows from operations is a measure of profit or loss in accordance with IFRS 8 "Operating Segments", calculated as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit and our ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments.
DISCLAIMER
Natural gas volumes have been converted on the basis of six thousand cubic feet ("mcf") of natural gas to one barrel equivalent of oil. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Certain statements included or incorporated by reference in this press release may constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this press release may include, but are not limited to:
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
SOURCE Vermilion Energy Inc.
CALGARY, Dec. 9, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on January 16, 2017 to all shareholders of record on December 22, 2016. The ex-dividend date for this payment is December 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
We commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016. We are increasing the proration factor by a further 25% beginning with the January 16, 2017 dividend payment. Eligible shareholders who have elected to participate in the Premium DividendTM component will receive a 1.5% premium on 50% of their participating shares, and the regular cash dividend on the remaining 50% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to continue increasing the proration during 2017, at the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, Nov. 10, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on December 15, 2016 to all shareholders of record on November 22, 2016. The ex-dividend date for this payment is November 18, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
As previously announced, we commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016. Eligible shareholders who have elected to participate in the Premium DividendTM component currently receive a 1.5% premium on 75% of their participating shares, and the regular cash dividend on the remaining 25% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to continue increasing the proration during 2017, at the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, Oct. 31, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and nine months ended September 30, 2016.
The unaudited financial statements and management discussion and analysis for the three and nine months ended September 30, 2016, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
HIGHLIGHTS
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
TM denotes trademark of Canaccord Genuity Capital Corporation. |
HIGHLIGHTS | |||||||
Three Months Ended |
Nine Months Ended | ||||||
($M except as indicated) |
Sep 30, |
Jun 30, |
Sep 30, |
Sep 30, |
Sep 30, | ||
Financial |
2016 |
2016 |
2015 |
2016 |
2015 | ||
Petroleum and natural gas sales |
232,660 |
212,855 |
245,051 |
622,900 |
705,267 | ||
Fund flows from operations |
140,974 |
126,568 |
129,435 |
361,209 |
379,726 | ||
Fund flows from operations ($/basic share) (1) |
1.21 |
1.10 |
1.17 |
3.14 |
3.48 | ||
Fund flows from operations ($/diluted share) (1) |
1.19 |
1.09 |
1.16 |
3.11 |
3.44 | ||
Net loss |
(14,475) |
(55,696) |
(83,310) |
(156,019) |
(75,222) | ||
Net loss ($/basic share) |
(0.12) |
(0.48) |
(0.76) |
(1.36) |
(0.69) | ||
Capital expenditures |
41,039 |
71,714 |
93,381 |
175,526 |
357,865 | ||
Acquisitions |
10,391 |
8,550 |
22,155 |
19,811 |
22,670 | ||
Asset retirement obligations settled |
2,066 |
2,200 |
2,123 |
6,290 |
6,448 | ||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 |
1.935 |
1.935 | ||
Dividends declared |
75,465 |
74,662 |
71,244 |
222,974 |
211,610 | ||
% of fund flows from operations |
54% |
59% |
55% |
62% |
56% | ||
Net dividends (1) |
24,553 |
24,146 |
26,654 |
73,556 |
103,341 | ||
% of fund flows from operations |
17% |
19% |
21% |
20% |
27% | ||
Payout (1) |
67,658 |
98,060 |
122,158 |
255,372 |
467,654 | ||
% of fund flows from operations |
48% |
78% |
94% |
71% |
123% | ||
Net debt |
1,343,923 |
1,398,950 |
1,363,043 |
1,343,923 |
1,363,043 | ||
Ratio of net debt to annualized fund flows from operations |
2.4 |
2.8 |
2.6 |
2.8 |
2.7 | ||
Operational | |||||||
Production |
|||||||
Crude oil and condensate (bbls/d) |
27,842 |
28,416 |
30,108 |
28,483 |
30,106 | ||
NGLs (bbls/d) |
2,478 |
2,713 |
2,678 |
2,621 |
2,163 | ||
Natural gas (mmcf/d) |
199.66 |
198.93 |
140.97 |
199.90 |
123.51 | ||
Total (boe/d) |
63,596 |
64,285 |
56,280 |
64,421 |
52,854 | ||
Average realized prices |
|||||||
Crude oil, condensate and NGLs ($/bbl) |
53.24 |
53.90 |
56.57 |
48.95 |
61.48 | ||
Natural gas ($/mcf) |
3.98 |
3.53 |
5.36 |
3.76 |
5.18 | ||
Production mix (% of production) |
|||||||
% priced with reference to WTI |
19% |
20% |
24% |
20% |
26% | ||
% priced with reference to AECO |
20% |
22% |
22% |
22% |
21% | ||
% priced with reference to TTF and NBP |
32% |
29% |
20% |
29% |
18% | ||
% priced with reference to Dated Brent |
29% |
29% |
34% |
29% |
35% | ||
Netbacks ($/boe) |
|||||||
Operating netback |
27.88 |
27.66 |
32.25 |
25.75 |
33.55 | ||
Fund flows from operations netback |
23.25 |
21.90 |
24.58 |
20.46 |
26.64 | ||
Operating expenses |
9.05 |
9.02 |
10.99 |
9.21 |
11.25 | ||
Average reference prices |
|||||||
WTI (US $/bbl) |
44.94 |
45.59 |
46.43 |
41.33 |
51.00 | ||
Edmonton Sweet index (US $/bbl) |
42.06 |
42.51 |
43.01 |
38.11 |
46.64 | ||
Dated Brent (US $/bbl) |
45.85 |
45.57 |
50.26 |
41.77 |
55.39 | ||
AECO ($/mmbtu) |
2.32 |
1.40 |
2.90 |
1.85 |
2.77 | ||
NBP ($/mmbtu) |
5.29 |
5.78 |
8.40 |
5.69 |
8.62 | ||
TTF ($/mmbtu) |
5.43 |
5.61 |
8.48 |
5.58 |
8.52 | ||
Average foreign currency exchange rates |
|||||||
CDN $/US $ |
1.31 |
1.29 |
1.31 |
1.32 |
1.26 | ||
CDN $/Euro |
1.46 |
1.46 |
1.46 |
1.48 |
1.40 | ||
Share information ('000s) | |||||||
Shares outstanding - basic |
117,386 |
116,173 |
110,818 |
117,386 |
110,818 | ||
Shares outstanding - diluted (1) |
120,183 |
118,948 |
113,643 |
120,183 |
113,643 | ||
Weighted average shares outstanding - basic |
116,814 |
115,366 |
110,293 |
114,975 |
109,052 | ||
Weighted average shares outstanding - diluted (1) |
118,177 |
116,587 |
111,193 |
116,221 |
110,433 |
(1) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" |
MESSAGE TO SHAREHOLDERS
Oil prices have increased from the lows experienced during Q1 2016, but remain less than half of what they were in mid-2014 before the downturn started. While future prices are very difficult to accurately predict, it is possible that oversupply will persist and suppress prices for a considerable period. We intend to continue managing our company based on the current commodity strip, maintaining a low level of financial leverage, and keeping cash uses for dividends and exploration and development ("E&D") capital investment below our internal cash generation. At the same time, we are targeting continued growth in production per share.
Whether commodity prices are high or low, we follow a consistent strategy. This strategy is outlined in the current edition of our Corporate Presentation found on our website. We would like to review this strategy with you in the next few paragraphs.
Our capital markets model aims to deliver consistent growth-and-income to our shareholders. We are proud of our thirteen-year record of continuous monthly dividends. We have increased our dividend three times during this period and have never decreased it. Our goal is to also increase our production base on a per-share basis at organic growth rates that are appropriate to our asset base, and over the past five years this growth has accelerated. We intend to provide both the organic growth and income components of this model within our internally-generated cash flow.
Our operating, geographic and organizational models are integral to successfully delivering this ambitious growth-and-income capital markets model. We believe that the four model components represent an internally consistent strategy that differentiates Vermilion from our competitors.
Our operating model provides a framework to ensure that our asset composition supports our capital markets model. Vermilion's largely conventional and semi-conventional asset base delivers the high margins, low base decline rates and strong capital efficiencies which are required to deliver a self-funded growth-and-income model. These characteristics are paramount as we continue to develop the deep and diversified project inventory that supports our targeted organic growth rates for the long-term. We expect to further augment this organic inventory and growth through opportunistic and accretive acquisitions. Prospective acquisitions are subject to disciplined tests to ensure consistency with our operating and capital markets models. With a deep organic inventory already established, we are determined that any acquisitions will be accretive to the "organic part" of our company, and not dilutive of it.
Vermilion's geographic model is a significant differentiator for the Company. Since our first international acquisition in 1997, we have demonstrated our ability to successfully enter new jurisdictions and add assets to our portfolio that are aligned with our operating model. In addition, our geographic diversification provides flexibility to allocate capital to the highest return products and projects for a given economic environment, and creates the opportunity for outsized acquisition returns in certain jurisdictions. Our three regions (Europe, North America and Australia) all feature stable political, fiscal and regulatory regimes.
Our organizational model features a relatively-decentralized business unit structure to effectively manage our geographic diversity. Nonetheless, throughout our company, we maintain a consistent technical focus and emphasize the importance of our shared culture. While capital investment selection is managed as a portfolio at the corporate level, each of our business units (with their integrated engineering, geoscience, production operations and regulatory functions) is responsible for proposing a robust set of capital projects. Once a capital project slate has been selected at the corporate level, our business units are responsible for delivering their production, capital and operating expense targets.
Our self-funded growth-and-income model is fully aligned with the three priorities we have previously communicated to our shareholders. First, we intend to maintain a strong balance sheet. Second, we endeavor to protect our dividend. Third, we seek to deliver continued production growth on a per share basis. We believe that through disciplined execution of our strategy and adherence to these priorities, Vermilion can remain a core investment holding for our shareholders throughout the commodity price cycle.
Q3 2016 REVIEW
The third quarter was a strong one from both operational and financial perspectives. Production was relatively flat from the previous quarter despite a 43% reduction in E&D capital expenditures. Our cash uses for net dividends, E&D capital investment and abandonment expenditures represented 48% of fund flows. This resulted in over $70 million of excess cash generation after payout, which we used to fund minor bolt-on acquisitions in Canada and to reduce net debt by $55 million during the quarter.
Profitability Enhancement Plan ("PEP") initiatives continue to deliver cost savings across our business. As an expansion of our PEP program, all of Vermilion's employees were requested to submit an additional five cost-reducing ideas earlier this year. As a result of this widespread employee engagement, additional cost reductions have been achieved. We estimate that full-year PEP savings related to capital, operating and administrative expenditures will exceed $60 million in 2016. Per-unit operating and G&A expenses are forecasted to decrease by 15% and 13%, respectively, year-over-year. As announced with our Q2 2016 results, identified cost savings allowed us to expand our 2016 capital program with only a modest change in our capital budget.
We began proration of the Premium DividendTM component of our Dividend Reinvestment Plan by 25% beginning with our October dividend payment. Eligible shareholders who have elected to participate in the Premium DividendTM component are now receiving the 1.5% premium on 75% of their participating shares and the regular cash dividend on the remaining 25% of their shares. We expect to increase the proration factor by a further 25% beginning with the January 2017 dividend payment. Subject to unexpected changes in the commodity price outlook, we will continue to increase the proration during 2017, by the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan. We also intend to reduce the discount associated with our traditional Dividend Reinvestment Plan from 3% to 2%, beginning with the January 2017 dividend payment, subject to TSX approval.
Europe
Subsequent to the third quarter, we commenced our four (4.0 net) well Champotran drilling program in France. These wells will be completed and placed on production in early 2017. This program follows three consecutive years of highly successful Champotran drilling campaigns, during which we have drilled 14 wells with a 100% success rate. The wells drilled during the 2015 campaign continue to deliver strong production results with cumulative production to date approximately 17% greater than we had originally budgeted. Activity during the third quarter in France focused on well optimizations in the Neocomian fields. Our ongoing activities in the Neocomian have resulted in steady production growth since we acquired this asset in 2012. In Q3 2016, oil production levels in these fields reached the highest rate since June 1995, despite not having drilled any wells since the acquisition. We expect to drill our first wells in the Neocomian in 2017.
We completed our two-well drilling campaign in the Netherlands during the quarter. Langezwaag-3 encountered 17 meters of net pay in the Zechstein-2 carbonate formation. This well is being completed and is expected to be placed on production in November, at which time an in-line production test will be conducted. Andel-6ST encountered a large gas column of inadequate reservoir quality to justify completion. Potential remains to sidetrack this well to an updip location where higher quality gas zones may be encountered. The well has been suspended to allow us to reprocess seismic data to determine the viability of the potential updip target. As expected, production from our Diever-02 and Slootdorp-06/07 wells remained curtailed at the end of Q3 2016 pending final approval of our applications to increase production rates at the conclusion of the extended well test periods. We expect the extended well tests to be completed, and the related approvals to be received, during the first half of 2017.
In Germany, we commenced integration activities associated with the acquisition of assets from Engie E&P Deutschland GmbH that we announced in the prior quarter. As noted, this acquisition will provide Vermilion with our first operated position in the country and is expected to close by the end of the year. Germany remains a key area of interest for Vermilion as we advance our objective of developing a material business unit in the country.
Irish production averaged 59 mmcf/d (9,879 boe/d) net to Vermilion during Q3 2016, representing an increase of 25% versus the prior quarter. Production results continued to benefit from better than expected well deliverability and minimal downtime. Following the conclusion of a successful offshore work campaign that included laying a flowline to the P2 well, all six wells are now available for production.
North America
With our 2016 capital plan for North America predominately focused on preserving value through the drilling of operated land expiries and non-operated wells proposed by partners, third quarter capital activities in Canada were limited. We participated in four (1.2 net) condensate-rich Mannville wells drilled by partners but did not conduct any operated drilling. During the quarter, approximately 1,900 boe/d of natural gas weighted production remained voluntarily curtailed in response to low AECO prices. Although the majority of the curtailed volumes would have been economic at Q3 2016 AECO prices, the production is not required to meet our corporate targets, and we believe higher anticipated winter prices will deliver more cash flow from these wells. The majority of this curtailed production will be brought back online in Q1 2017.
During Q4 2016 we intend to drill or participate in seven (5.6 net) Mannville wells. With the exception of one (0.6 net) well, these wells are scheduled to be brought on production in early 2017. As announced in Q2, this activity is being largely funded by savings identified through PEP initiatives.
Australia
The two sidetrack wells drilled in Australia during Q2 2016 continued to demonstrate strong productive capability with combined production rates exceeding 4,500 bbls/d when utilized. Vermilion intends to produce these wells intermittently to meet corporate production targets while seeking to optimize ultimate recoveries and oil pricing. Following our successful 2015 and 2016 drilling campaigns, we do not expect to drill any additional wells in Australia until 2019. Late in the quarter, we commenced a planned 10-day maintenance shutdown. The scope of activities was completed as scheduled and production resumed on October 3, 2016. We also continued to advance our Wandoo Platforms Life Extension project during the quarter.
Sustainability
We recently announced that Vermilion was one of only five oil and gas companies in the world, and the only oil and gas company in North America, to be awarded a position on CDP's Climate "A" List. CDP (formerly Carbon Disclosure Project) is a London-based not-for-profit organization that administers a global environmental disclosure system that assists in the measurement and management of corporate environmental impacts. To achieve Climate "A" List recognition, a company must receive consistently high scores across all of CDP's scoring dimensions. Only 193 companies globally achieved Climate "A" List recognition in 2016, and only three Canadian companies were awarded a position on this year's list.
Vermilion has voluntarily reported emissions data to CDP for each year since 2012. We firmly believe in the importance of measuring and understanding our current environmental impact. This assists our effort to identify and realize opportunities to operate in an even more environmentally and socially sustainable manner in the future.
We also recently released our third annual Sustainability Report which details our efforts to generate environmental, social, and economic benefits for all stakeholders. The report describes our approach to sustainability in our operations, and details our progress and challenges in this regard. We are committed to providing increasingly complete information and objective assessment of our performance in this area on an annual basis. Furthermore, we believe the integration of sustainability principles into our business strategy increases shareholder returns and reduces long-term risks to our business model. Our 2016 Sustainability Report is available on our corporate website at www.vermilionenergy.com/sustainability.
2017 BUDGET
Following the preliminary 2017/2018 E&D capital investment and production targets we disclosed in the prior quarter, our Board of Directors has formally approved an E&D capital budget of $295 million for 2017. We continue to target production of between 69,000 to 70,000 boe/d in 2017. This budget funds development of high-return projects including our condensate-rich Mannville projects in Canada, continued drilling in France, favorably-priced European natural gas projects in the Netherlands, and our emerging Turner Sands play in the United States. The preliminary targets we announced last quarter for 2018 are unchanged with E&D capital investment of $335 million and corresponding production of 75,000 to 76,000 boe/d. Production at the top end of these ranges would represent per share growth of approximately 6% for both years, within our targeted range of 5-7% annual per share production growth.
Our 2017 E&D budget represents the third year of significantly lower capital expenditures since the current commodity price downturn started in 2014. Despite this reduced spending level, we expect to continue delivering strong per share production growth. Our geographic and commodity diversification allow for a high return capital program even in depressed commodity markets, and provides the flexibility to respond to changes in individual commodity markets as prices recover.
At current strip prices, Vermilion expects to fully fund 2017 E&D expenditures and cash dividends from fund flows from operations, with surplus cash generation primarily directed to debt reduction. We maintain the operational flexibility to reduce our 2017 E&D program if commodity prices unexpectedly weaken. Should capital availability increase during the year as a result of a meaningful and sustainable improvement in commodity prices, we do have the capability to increase E&D investment levels. However, we would expect any potential increase to be modest and fully funded by internal cash generation under the prevailing commodity strip.
Europe
Our 2017 E&D budget for the Netherlands of $46 million represents an increase of 92% from our forecasted 2016 investment of $24 million. We anticipate drilling three (1.5 net) exploration wells and one (0.5 net) development well, as compared to our 2016 activity of two (0.9 net) exploration wells. Included in our budget for the Netherlands is a $10 million seismic program in our Akkrum and Zuid Friesland concessions and a major turnaround at our Garijp Treatment Centre.
In France, we have set a 2017 E&D budget of $69 million, representing a 5% increase from our 2016 forecast of $66 million. We intend to complete and tie-in the four (4.0 net) Champotran wells being drilled in Q4 2016 in early 2017 and continue our ongoing program of workovers and optimizations. We also expect to drill our first four (4.0 net) wells in the Neocomian fields in the Paris Basin. The Neocomian fields were acquired by Vermilion in 2012 and since then, we have increased production by approximately 50% through workovers and artificial lift optimizations.
Our 2017 German capital program of $18 million represents a significant increase from the $4 million forecast for 2016. Vermilion will assume operatorship for the drilling phase of the Burgmoor Z5 development well (0.25 net) in the Dümmersee-Uchte area, where we are a member of a four-partner consortium. Completion, tie-in and associated production from this well is expected in mid-2018. We also expect to invest in optimizations and other well work on the acquired Engie assets. Lastly, we will continue to advance our permitting, studies and other activities associated with the farm-in agreement we signed in mid-2015.
Following the achievement of first gas at Corrib on December 30, 2015, and the tie-in of the P2 well during Q3 2016, a low level of capital investment is expected in 2017.
North America
We expect to invest approximately $108 million in E&D activities in Canada in 2017, representing an increase of 83% from the $59 million forecasted for 2016. Our Canadian assets provide significant flexibility to ramp activity levels up or down in response to the prevailing commodity price environment, with a diversified project inventory that provides exposure to oil, condensate and natural gas opportunities.
Our Canadian investment program is significantly oil-weighted. In 2017, we expect to drill or participate in 19 (11.3 net) Mannville wells as well as complete 2.5 net wells and tie-in 6.0 net wells drilled in 2016. Our Ellerslie condensate-focused Mannville program provides particularly attractive economics in the current commodity price environment. Our Cardium light oil program includes nine (6.0 net) wells, with five (5.0 net) of those wells being operated. We intend to drill or participate in 13 (11.3 net) Midale light oil wells in our Southeast Saskatchewan light oil play, as well as to complete and tie-in the four operated wells we drilled earlier in 2016.
In the United States, we expect to drill and complete three (3.0 net) wells targeting the light oil Turner Sand in the Powder River Basin of Wyoming.
Australia
Following our successful 2015 and 2016 drilling campaigns, we do not expect to drill any additional wells in Australia until 2019. Our 2017 E&D budget of $30 million for Australia will focus on adding value through asset optimization and targeted proactive maintenance. Approximately 50% of our budgeted E&D capital program for 2017 is allocated to further improving and debottlenecking our fluid handling capability on the Wandoo B platform. Once completed, we expect that this infrastructure enhancement will allow us to increase oil production on the platform by 600 to 700 bbls/d to help offset natural decline and maintain steady production. The balance of our budget will support a refurbishment campaign that will further extend the life of our Australian assets while reducing future repair and maintenance expenditures.
Capital Expenditures by Country
Country |
2017 Budget* ($MM) |
2016 Estimate ($MM) |
2017 vs. 2016 % Change |
2017 Net Wells |
2016 Net Wells |
Canada |
108 |
59 |
83% |
28.6 |
16.2 |
France |
69 |
66 |
5% |
4.0 |
4.0 |
Netherlands |
46 |
24 |
92% |
2.0 |
0.9 |
Germany |
18 |
4 |
350% |
0.3 |
- |
Australia |
30 |
63 |
(52%) |
- |
2.0 |
USA |
16 |
13 |
23% |
3.0 |
- |
Ireland |
2 |
9 |
(78%) |
- |
- |
Central and Eastern Europe |
6 |
2 |
200% |
- |
- |
Total E&D Capital Expenditures |
295 |
240 |
23% |
37.9 |
23.1 |
Development Capital by Category
Category |
2017 Budget* ($MM) |
2016 Estimate ($MM) |
2017 vs. 2016 % Change |
Drilling, completion, new well equipment and tie-in, workovers and recompletions |
175 |
160 |
9% |
Production equipment and facilities |
70 |
50 |
40% |
Seismic, studies, land and other |
50 |
30 |
67% |
Total E&D Capital Expenditures |
295 |
240 |
23% |
* 2017 Budget reflects foreign exchange assumptions of USD/CAD 1.32, CAD/EUR 1.48 and CAD/AUD 0.99. |
Commodity Hedging
Vermilion hedges to manage commodity price exposures and increase the stability of cash flows providing additional certainty with regards to the execution of our capital program. We currently have 33% of our expected net-of-royalty production hedged for 2017, including 50% of anticipated European natural gas volumes and 49% of anticipated North American gas volumes. We will continue to hedge into the 2017 and 2018 periods as suitable opportunities arise.
For additional information on our current hedge position, please visit our website at http://www.vermilionenergy.com/ir/hedging.cfm.
ORGANIZATIONAL UPDATE
Vermilion is pleased to announce the appointment of Mr. Robert Michaleski to our Board of Directors effective October 3, 2016.
Mr. Michaleski brings over 30 years of experience in various senior management and executive capacities at Pembina Pipeline Corporation. He has overseen Pembina's transformation from an Alberta-based oil pipeline company into one of North America's leading integrated energy transportation and midstream services companies. When he took over leadership, Pembina's total enterprise value was $450 million and, when he retired in 2013, it was over $12.5 billion. He was Chief Executive Officer from 2000 to 2013 and also President from 2000 to 2012. He was Vice President and Chief Financial Officer from 1997 to 2000, Vice President of Finance from 1992 to 1997, Controller from 1980 to 1992, and Manager of Internal Audit from 1978 to 1980. He has been a Director of Pembina since 2000, a Director of Essential Energy Services Ltd. since 2012, and a Director of Coril Holdings Ltd. since 2003. A proud supporter of the community, Mr. Michaleski provides his leadership to United Way of Calgary and Area serving as co-chair of the General Oil and Gas Division since 2010 and a Director since 2013. Mr. Michaleski holds a Bachelor of Commerce (Honours) Degree from the University of Manitoba. He received his Chartered Accountant designation in 1978. He is a member of the Institute of Corporate Directors.
We look forward to the contributions that Mr. Michaleski will make to our Board of Directors and to the ongoing success of Vermilion.
GUIDANCE
On November 9, 2015 we announced preliminary 2016 capital expenditure guidance of $350 million and production guidance of between 63,000-65,000 boe/d. On January 5, 2016, in response to the continued weakness in commodity prices we reduced our 2016 capital expenditure guidance to $285 million with corresponding production guidance of 62,500-63,500 boe/d. On February 29, 2016, we further revised our 2016 capital expenditure guidance to $235 million as a result of continued commodity price deterioration. We maintained our production guidance of 62,500-63,500 boe/d. The February 29, 2016 reduction primarily reflected lower expected non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands pipeline twinning program. On August 8, 2016, we modestly increased our 2016 capital expenditure guidance to $240 million with the reinstatement of a four-well drilling program in the Champotran field in France and added drilling activity in Canada, partially offset by capital cost savings achieved to date.
We released our 2017 capital budget and related guidance concurrent with the release of our Q3 2016 results.
The following table summarizes our guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | |
2016 Guidance |
|||
2016 Guidance |
November 9, 2015 |
350 |
63,000 to 65,000 |
2016 Guidance |
January 5, 2016 |
285 |
62,500 to 63,500 |
2016 Guidance |
February 29, 2016 |
235 |
62,500 to 63,500 |
2016 Guidance |
August 8, 2016 |
240 |
62,500 to 63,500 |
2017 Guidance |
|||
2017 Guidance |
October 31, 2016 |
295 |
69,000 to 70,000 |
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on Monday, October 31, 2016 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 86185996. The replay will be available until midnight mountain time on November 7, 2016.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=1271561&s=1&k=AEF031F136D078731757071F156C8DC9 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
TM denotes trademark of Canaccord Genuity Capital Corporation.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas project in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
SOURCE Vermilion Energy Inc.
CALGARY, Oct. 28, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce that we have been awarded a position on CDP's Climate "A" List. CDP (formerly Carbon Disclosure Project) is a London-based not-for-profit organization that administers a global environmental disclosure system that assists in the measurement and management of corporate environmental impacts. To achieve Climate "A" List recognition, a company must receive consistently high scores across all of CDP's scoring dimensions.
Vermilion is one of only 193 companies globally to achieve Climate "A" List recognition in 2016 and the only North American energy company on the list. Across all sectors, only three Canadian companies, including Vermilion, were awarded a position on this year's Climate "A" List. Vermilion is one of only five oil and gas companies in the world to be named to the Climate "A" List.
Vermilion has voluntarily reported emissions data to CDP for each year since 2012. We firmly believe in the importance of measuring and understanding our current environmental impact. This assists our effort to identify and realize opportunities to operate in an even more environmentally and socially sustainable manner in the future.
The Climate "A" List, along with the climate scores of all companies publicly taking part in CDP's climate change program this year, is available on CDP's website at www.cdp.net.
We are also pleased to announce that we have released our third annual Sustainability Report which details our efforts to generate environmental, social, and economic benefits for all stakeholders. The report describes our approach to sustainability in our operations, and details our progress and challenges in this regard. We are committed to providing increasingly complete information and objective assessment of our performance in this area on an annual basis. Furthermore, we believe the integration of sustainability principles into our business strategy increases shareholder returns and reduces long-term risks to our business model.
Our 2016 Sustainability Report is available on our corporate website at www.vermilionenergy.com/sustainability.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas project in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%.
Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings. We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate "A" List performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, France, the Netherlands and Germany. In addition, Vermilion emphasizes strategic community investment in each of our operating areas.
Management and directors of Vermilion hold approximately 5% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Oct. 14, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on November 15, 2016 to all shareholders of record on October 24, 2016. The ex-dividend date for this payment is October 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
As previously announced, we commenced prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend paid on October 17, 2016. Eligible shareholders who have elected to participate in the Premium DividendTM component currently receive a 1.5% premium on 75% of their shares, and the regular cash dividend on the remaining 25% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to continue increasing the proration during 2017, at the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, Sept. 12, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on October 17, 2016 to all shareholders of record on September 22, 2016. The ex-dividend date for this payment is September 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
As previously announced, we will be prorating the Premium DividendTM component of our Dividend Reinvestment Plan by 25%, beginning with the dividend payable on October 17, 2016. Eligible shareholders who have elected to participate in the Premium DividendTM component will continue to receive a 1.5% premium on 75% of their shares, and will receive the regular cash dividend on the remaining 25% of their shares. Subject to unexpected changes in the commodity price outlook, it is our intent to continue increasing the proration during 2017, at the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 5%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
TM denotes trademark of Canaccord Genuity Capital Corporation.
SOURCE Vermilion Energy Inc.
CALGARY, Aug. 12, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on September 15, 2016 to all shareholders of record on August 22, 2016. The ex-dividend date for this payment is August 18, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Aug. 8, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and six months ended June 30, 2016.
The unaudited financial statements and management discussion and analysis for the three and six months ended June 30, 2016, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
HIGHLIGHTS
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Estimated proved plus probable and proved developed producing reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated June 27, 2016 with an effective date of December 31, 2015. |
TMdenotes trademark of Canaccord Genuity Capital Corporation. |
HIGHLIGHTS |
||||||||
Three Months Ended |
Six Months Ended | |||||||
($M except as indicated) Financial |
Jun 30, |
Mar 31, |
Jun 30, |
Jun 30, |
Jun 30, | |||
Petroleum and natural gas sales |
212,855 |
177,385 |
264,331 |
390,240 |
460,216 | |||
Fund flows from operations |
126,568 |
93,667 |
129,496 |
220,235 |
250,291 | |||
Fund flows from operations ($/basic share) (1) |
1.10 |
0.83 |
1.18 |
1.93 |
2.31 | |||
Fund flows from operations ($/diluted share) (1) |
1.09 |
0.82 |
1.17 |
1.91 |
2.28 | |||
Net (loss) earnings |
(55,696) |
(85,848) |
6,813 |
(141,544) |
8,088 | |||
Net (loss) earnings ($/basic share) |
(0.48) |
(0.76) |
0.06 |
(1.24) |
0.07 | |||
Capital expenditures |
71,714 |
62,773 |
90,173 |
134,487 |
264,484 | |||
Acquisitions |
8,550 |
870 |
480 |
9,420 |
515 | |||
Asset retirement obligations settled |
2,200 |
2,024 |
1,218 |
4,224 |
4,325 | |||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 |
1.290 |
1.290 | |||
Dividends declared |
74,662 |
72,847 |
70,976 |
147,509 |
140,366 | |||
% of fund flows from operations |
59% |
78% |
55% |
67% |
56% | |||
Net dividends (1) |
24,146 |
24,857 |
28,675 |
49,003 |
76,687 | |||
% of fund flows from operations |
19% |
27% |
22% |
22% |
31% | |||
Payout (1) |
98,060 |
89,654 |
120,066 |
187,714 |
345,496 | |||
% of fund flows from operations |
78% |
96% |
93% |
85% |
138% | |||
% of fund flows from operations (excluding the Corrib project) (1) |
N/A |
N/A |
76% |
N/A |
123% | |||
Net debt |
1,398,950 |
1,367,063 |
1,377,902 |
1,398,950 |
1,377,902 | |||
Ratio of net debt to annualized fund flows from operations |
2.8 |
3.6 |
2.7 |
3.2 |
2.8 | |||
Operational | ||||||||
Production |
||||||||
Crude oil and condensate (bbls/d) |
28,416 |
29,199 |
30,689 |
28,808 |
30,104 | |||
NGLs (bbls/d) |
2,713 |
2,672 |
2,094 |
2,693 |
1,901 | |||
Natural gas (mmcf/d) |
198.93 |
201.11 |
114.29 |
200.02 |
114.64 | |||
Total (boe/d) |
64,285 |
65,389 |
51,831 |
64,837 |
51,113 | |||
Average realized prices |
||||||||
Crude oil, condensate and NGLs ($/bbl) |
53.90 |
39.35 |
68.90 |
46.63 |
64.23 | |||
Natural gas ($/mcf) |
3.53 |
3.76 |
4.86 |
3.65 |
5.06 | |||
Production mix (% of production) |
||||||||
% priced with reference to WTI |
20% |
20% |
27% |
20% |
27% | |||
% priced with reference to AECO |
22% |
25% |
21% |
24% |
21% | |||
% priced with reference to TTF and NBP |
29% |
26% |
16% |
28% |
17% | |||
% priced with reference to Dated Brent |
29% |
29% |
36% |
28% |
35% | |||
Netbacks ($/boe) |
||||||||
Operating netback |
27.66 |
21.63 |
36.89 |
24.64 |
34.30 | |||
Fund flows from operations netback |
21.90 |
16.12 |
26.76 |
19.00 |
27.83 | |||
Operating expenses |
9.02 |
9.58 |
12.12 |
9.30 |
11.40 | |||
Average reference prices |
||||||||
WTI (US $/bbl) |
45.59 |
33.45 |
57.94 |
39.52 |
53.29 | |||
Edmonton Sweet index (US $/bbl) |
42.51 |
29.76 |
55.08 |
36.13 |
48.46 | |||
Dated Brent (US $/bbl) |
45.57 |
33.89 |
61.92 |
39.73 |
57.95 | |||
AECO ($/mmbtu) |
1.40 |
1.83 |
2.65 |
1.61 |
2.70 | |||
NBP ($/mmbtu) |
5.78 |
5.97 |
8.42 |
5.88 |
8.71 | |||
TTF ($/mmbtu) |
5.61 |
5.70 |
8.38 |
5.66 |
8.54 | |||
Average foreign currency exchange rates |
||||||||
CDN $/US $ |
1.29 |
1.37 |
1.23 |
1.33 |
1.24 | |||
CDN $/Euro |
1.46 |
1.52 |
1.36 |
1.49 |
1.38 | |||
Share information ('000s) | ||||||||
Shares outstanding - basic |
116,173 |
113,451 |
109,806 |
116,173 |
109,806 | |||
Shares outstanding - diluted (1) |
118,948 |
116,491 |
112,626 |
118,948 |
112,626 | |||
Weighted average shares outstanding - basic |
115,366 |
112,725 |
109,319 |
114,046 |
108,421 | |||
Weighted average shares outstanding - diluted (1) |
116,587 |
114,110 |
110,746 |
115,090 |
109,792 |
(1) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
MESSAGE TO SHAREHOLDERS
Over the past two years of significantly lower commodity prices, Vermilion's course and priorities have remained consistent. Our priorities are to maintain a strong balance sheet, protect our dividend, and to provide for future production growth, in that order. Despite the challenging pricing environment, we have been able to achieve all of these objectives.
Following our disciplined approach to financial management, we remain committed to running a sustainable growth-and-income business model. We are managing our business based on the current commodity strip price, and have structured our spending so that fund flows from operations will match or exceed cash outflows for net dividends and exploration and development ("E&D") capital expenditures. Based on current strip prices, we project a 2016 payout of approximately 80%, which provides cash flow to fund our first priority, strengthening the balance sheet through debt reduction.
Our Profitability Enhancement Program ("PEP") initiative continues to generate tangible results, further strengthening our balance sheet and enhancing the long-term profitability of our business. PEP cost savings related to capital spending, operating expenses and G&A expenditures reached nearly $90 million for full-year 2015, and we expect to deliver a further $40 to $50 million of cost reductions for 2016. Year-to-date, we have reduced unit operating expenses by 18% versus the prior year. Looking forward, we anticipate full-year unit operating expense to be lower than 2015, which would result in four consecutive years of unit operating cost improvement, reflecting both increased volumes and our reduced cost structure.
Another initiative in response to low commodity prices is the Premium DividendTM Component of our Dividend Reinvestment Plan, which we implemented in early 2015 as a short-term measure to preserve our financial flexibility and to conservatively and inexpensively access equity capital. We plan to start prorating the Premium DividendTM by 25% in Q4 2016. Subject to unexpected changes in the commodity price outlook, it is our intent to continue increasing the proration during 2017, at the end of which there would be no further equity issuance under the Premium DividendTM component of our Dividend Reinvestment Plan.
Last quarter, we reiterated our intention to adhere closely to our announced $235 million E&D capital budget for 2016. This budget represents a decrease of over 50% from 2015 and more than 65% from 2014 capital expenditure levels. Despite this significant reduction in capital investment and the voluntary reduction of over 2,000 boe/d of gas production in Canada currently (approximately 1,000 boe/d on an annual basis for 2016) with the objective of achieving higher prices this winter, we still anticipate achieving production of between 62,500 to 63,500 boe/d, representing 15% year-over-year production growth, or nearly 10% growth on a per share basis. Due to continuing improvements in the cost efficiency of our capital projects, we have been able to add additional capital activities to our 2016 capital plan with only a $5 million increase to our E&D capital budget, bringing it to $240 million for 2016. Additional activities include the reinstatement of a four-well drilling program in the Champotran field in France, three (3.0 net) Cardium wells, and seven (4.0 net) Mannville wells in Canada. Vermilion's international exposure and diversified project inventory provides the flexibility to react to changing conditions and selectively allocate capital to the highest rate of return projects. This advantage is even more evident during times of restricted capital availability.
Having focused on our long-term priorities of protecting our balance sheet, defending our dividend, and continuing to invest in long-term growth, Vermilion is positioned to excel when commodity prices move off the lows recorded earlier this year. As part of an ongoing effort to better define and disclose our future growth profile, we have accelerated certain parts of our annual budgeting process and expanded our efforts to look at our potential budgets for the next two years, instead of just 2017. While we will not disclose our formal budget guidance until late in 2016, we are able to set approximate targets now for the next two years based on current forward commodity prices. At present, subject to unexpected changes in the commodity price outlook, we anticipate investing E&D capital of approximately $295 million in 2017 and approximately $335 million in 2018. With these projected investment levels, we expect to deliver production of 69,000 to 70,000 boe/d in 2017 and 75,000 to 76,000 boe/d in 2018, representing year-over-year increases of 9% for both years. We believe that the depth and capital efficiency of our portfolio of assets and projects has never been stronger. Over the long-term, we continue to target consistent organic production growth with only a modest increase in capital investment. A summary of our drilling locations by region and major play type can be found in our updated August 2016 investor presentation, located on the company website.
OPERATIONS REVIEW
Europe
In France, we have reinstated a four-well drilling program in Champotran. This program will follow on three consecutive years of Champotran drilling campaigns, where we have drilled 14 wells to date with a 100% success rate. As with our other highly-economic workover and waterflood activities in France, Champotran drilling targets favourably priced Brent crude production and generates strong capital efficiencies.
Subsequent to quarter end, we spudded the first well in our two (0.9 net) well drilling program in the Netherlands. As we announced last quarter, we were able to add this activity back into our $235 million capital budget by finding investment and cost reductions elsewhere in our budget. The prolific nature of the wells and the premium price received for our European gas, generate rates of return in excess of 100% for drilling projects in the Netherlands at current prices. Our plan is to drill the Langezwaag-03 (42% working interest) and Andel-6ST (45% working interest) wells during Q3 2016. If successful, we expect to bring the wells on-stream in the latter part of 2016.
In Germany, we entered into a definitive purchase and sale agreement for operated and non-operated interests in five oil and three gas producing fields from Engie E&P Deutschland GmbH, for total consideration of €33 million ($47.9 million). The acquisition will be funded through existing credit facilities and is expected to close in late 2016. Vermilion will assume operatorship of six of the eight producing fields. The assets are expected to produce approximately 2,000 boe/d (50% oil) in 2016. Proved plus probable reserves are estimated at 9.2 million boe(2) (74% proved developed producing(2)) based on an independent evaluation by GLJ Petroleum Consultants Ltd. with an effective date of December 31, 2015. Transaction metrics are estimated at approximately $24,000 per boe per day, $5.86 per boe of proved plus probable reserves(2) including future development capital (generating a 2P recycle ratio of 3.5 times based on projected 2016 netbacks), and 3.1 times estimated 2016 operating cash flow(1). The acquisition is expected to be accretive for all pertinent per share metrics including production, fund flows from operations(2), reserves and net asset value.
The Engie acquisition adds another low decline rate (approximately 10%) asset to our portfolio, and provides us with our first operated producing properties in Germany. The producing assets and lands to be acquired are natural extensions to our steadily expanding land base in the North German Basin, which is the dominant producing region in Germany. The development opportunities and subsurface characteristics of the acquired assets are similar to our existing European portfolio, including a number of low-risk optimization and workover opportunities from which we expect to maintain a flat-to-moderately growing production profile while generating free cash flow(1). In addition, we have identified development and exploration drilling opportunities that are not included in our current reserves estimate. Vermilion entered Germany in early 2014 through the acquisition of a 25% non-operating interest in a four-partner consortium. In July 2015, we executed a significant exploratory farm-in that provides us with participating interest in over 850,000 net acres of undeveloped land, as well as access to key technical data in the North German Basin. This acquisition significantly advances our objective of developing a material business unit in Germany, a country with a long history of oil and natural gas development, a consistent fiscal framework and low political risk.
The four exploration blocks conditionally granted to Vermilion in 2015 were ratified by the Republic of Croatia on June 9, 2016. The blocks cover approximately 2.35 million gross acres, with a substantial portion of the acreage located near existing crude oil and natural gas fields in northeast Croatia near the Hungarian border. Capital commitments are modest and back-loaded. The initial 5-year exploration period consists of two phases with an option to relinquish the blocks following the initial 3-year phase. The ratification makes Vermilion the largest onshore landholder in Croatia. Like our concessions in Hungary, the assets in Croatia are located in the under-developed Pannonian basin and are well-positioned to benefit from renewed investment and new technology.
Since the initiation of first gas at Corrib in Ireland on December 30, 2015, project ramp up has exceeded our expectations in terms of uptime and well deliverability. Net to Vermilion, production averaged approximately 34 mmcf/d (5,650 boe/d) in Q1 2016, 47 mmcf/d (7,877 boe/d) in Q2 2016, and reached full plant capacity of approximately 65 mmcf/d (10,900 boe/d) at the end of Q2 2016. During the quarter, planned recertification activities associated with the third party gas distribution pipeline network were completed, as well as some subsea inspections, maintenance and repairs on the subsea systems. Currently, five of the six wells are on production, with the final well to be brought online in Q3 2016 following the conclusion of an offshore work program to lay a pipeline to the sixth well.
Australia
Following our successful sidetrack well drilled in Q4 2015, we executed a two-well drilling program in Q2 2016. The wells drilled at Wandoo are extreme long-reach lateral wells. While having true vertical depths of only 600 metres, the two most recent sidetrack wells have measured depths of nearly 3,000 metres and 3,800 metres, respectively. We are pleased that our 2016 Australia drilling program came in under budget, while meeting all operational and health, safety and environmental objectives. The first well was placed on production at the end of June at an average rate of 2,000 bbls/d for the first month of production, with the second well placed on production in during the last week of July at an average rate of 2,700 bbls/d. Both wells have been produced at restricted rates to manage production levels and limit early-stage well drawdown Although we do not anticipate the need to drill another well until 2019, we may consider drilling one additional sidetrack well in 2017 or 2018, should rig availability on the northwest shelf and favourable day rates make such an investment particularly attractive.
North America
Q2 2016 capital activities in Canada and the United States were limited, as our 2016 capital plan focused on drilling land expiries on our operated properties and participating in wells proposed by our partners on non-operated properties. We currently have approximately 12 mmcf/d (2,000 boe/d) of gas-weighted production voluntarily curtailed in response to low AECO prices, with the intent of achieving greater value by bringing this production back on when gas prices improve. Similarly, we have deferred completion into 2017 for our four (4.0 net) operated Midale oil wells drilled in southeast Saskatchewan drilled earlier in 2016. While the wells are economic to drill, complete, and tie in at current prices, we believe that net present value will be enhanced by delaying completion and tie-in until oil prices increase from their current level.
Sustainability, Governance and Culture
Vermilion's MSCI ESG (Environment, Social and Governance) rating increased from BB to BBB and our Governance Metrics score for 2016 ranks in the 90th percentile globally. This follows our 9th-place ranking in the 2016 Corporate Knights Future 40 Responsible Corporate Leaders in Canada list (the highest ranking for an oil and gas company). Recognition such as this reflects Vermilion's continued focus on combining financial results with exemplary environmental, social and governance performance. Our next Sustainability Report is expected to be released in August 2016, which will have further information about our environmental and social stewardship.
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Estimated proved plus probable and proved developed producing reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated June 27, 2016 with an effective date of December 31, 2015. |
TM denotes trademark of Canaccord Genuity Capital Corporation. |
ORGANIZATIONAL UPDATE
John Donovan, formerly Executive Vice President of Business Development, has retired from Vermilion. We appreciate John's contributions to Vermilion, and wish him the best in the future. Leadership of our business development effort has been assumed by Jenson Tan, who has transitioned from his previous role of Director of New Ventures to Director of Business Development. Jenson joined Vermilion in 2010, and has played a key role in acquisitions within our legacy European businesses and our entries into Germany and Central and Eastern Europe. He was previously with ConocoPhillips Canada, where he was Asset Team Leader for fields in Alberta and Saskatchewan, following earlier assignments with ConocoPhillips in the US, China and Indonesia. Jenson received a Bachelor of Science degree in Petroleum Engineering from the University of Texas.
2016 GUIDANCE
On November 9, 2015 we announced preliminary 2016 capital expenditure guidance of $350 million and production guidance of between 63,000-65,000 boe/d. On January 5, 2016, in response to the continued weakness in commodity prices we reduced our 2016 capital expenditure guidance to $285 million with corresponding production guidance of 62,500-63,500 boe/d. On February 29, 2016, we further revised our 2016 capital expenditure guidance to $235 million as a result of continued commodity price deterioration. We maintained our production guidance of 62,500-63,500 boe/d. The February 29, 2016 reduction primarily reflected lower expected non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands pipeline twinning program. On August 8, 2016, we modestly increased our 2016 capital expenditure guidance to $240 million with the reinstatement of a four-well drilling program in the Champotran field in France and added drilling activity in Canada, partially offset by capital cost savings achieved to date.
The following table summarizes our 2016 guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | ||
2016 Guidance |
||||
2016 Guidance |
November 9, 2015 |
350 |
63,000 to 65,000 | |
2016 Guidance |
January 5, 2016 |
285 |
62,500 to 63,500 | |
2016 Guidance |
February 29, 2016 |
235 |
62,500 to 63,500 | |
2016 Guidance |
August 8, 2016 |
240 |
62,500 to 63,500 |
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on Monday, August 8, 2016 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 46839068. The replay will be available until midnight mountain time on August 15, 2016.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=1222046&s=1&k=37804B2464A94546769FA13BF5CADFB8 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
SOURCE Vermilion Energy Inc.
CALGARY, July 11, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on August 15, 2016 to all shareholders of record on July 22, 2016. The ex-dividend date for this payment is July 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield in excess of 6%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, June 28, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) has entered into a definitive purchase and sale agreement whereby Vermilion, through its wholly owned subsidiary, will acquire interests in several production and exploration assets in Germany (the "Acquisition") from Engie E&P Deutschland GmbH, for total consideration of €33 million ($47.9 million). The Acquisition has an effective date of January 1, 2016 and is anticipated to close in late Q4 2016, subject to customary closing adjustments. Vermilion will fund the Acquisition through existing credit facilities.
The Acquisition includes operated and non-operated interests in five oil and three gas producing fields, along with an operated interest in one exploration license (the "Assets"). The Assets are located within the prolific North German Basin in northwest Germany and are forecasted to produce approximately 2,000 boe/d in 2016 (50% oil). Proved plus probable reserves are estimated at 9.2 million boe(1) (74% proved developed producing(1)) based on an independent evaluation by GLJ Petroleum Consultants Ltd. with an effective date of December 31, 2015. The transaction metrics are estimated at approximately $24,000 per boe per day, $5.86 per boe of proved plus probable reserves(1) including future development capital (generating a 2P recycle ratio of 3.5 times based on projected 2016 netbacks), and 3.1 times estimated 2016 operating cash flow(2) using the current forward commodity strip. The Acquisition is expected to be accretive for all pertinent per share metrics including production, fund flows from operations(2), reserves and net asset value.
Vermilion will assume operatorship of six of the eight producing fields, with the other fields operated by ExxonMobil Production Deutschland ("EMPG") and Deutsche Erdoel AG ("DEA"). The Acquisition also includes a 50% operated interest in a 190 km oil pipeline network and a 66.7% operated interest in the Bedekaspel exploration license located in the Permian Rotliegend gas fairway, adding to Vermilion's existing 16.7% interest.
The Acquisition adds a low decline (approximately 10%) production base to our portfolio, and provides us with our first operated producing properties in Germany, further strengthening our presence in the country. The Assets are expected to be complementary with our existing European portfolio, offering similar subsurface characteristics and development opportunities. We have identified a number of low-risk optimization and workover opportunities on the acquired assets, from which we expect to maintain a flat-to-moderately growing production profile while generating free cash flow(2) to further support our growth-and-income capital markets model. In addition, we have identified development and exploration drilling opportunities that are not included in our current reserves estimate.
Vermilion entered Germany in early 2014 through the acquisition of a 25% non-operating interest in a four-partner consortium. In July 2015, we executed a significant exploratory farm-in agreement that provides us with participating interest in over 850,000 net acres of undeveloped land, as well as access to key technical data in the North German Basin. This Acquisition substantially advances our objective of developing a material business unit in Germany, a country with a long history of oil and natural gas development, a consistent fiscal framework and low political risk.
About Vermilion
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Natural gas volumes have been converted on the basis of six thousand cubic feet ("mcf") of natural gas to one barrel equivalent of oil. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(1) Estimated proved plus probable and proved developed producing reserves attributable to the Assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated June 27, 2016 with an effective date of December 31, 2015.
(2) Non-standardized and non-GAAP financial measures: This news release includes references to certain financial measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). Fund flows from operations is a non-standardized financial measure that is calculated as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit and our ability to generate cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Free cash flow and operating cash flow are non-GAAP financial measures. Free cash flow is calculated as fund flows from operations less capital expenditures. Operating cash flow is calculated as fund flows from operations before general and administration expense, interest and income taxes. We consider free cash flow and operating cash flow to be key measures as they are used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures. For additional information on non-standardized and non-GAAP financial measures, please refer to the Management's Discussion and Analysis contained in Vermilion's 2015 Annual Report for the year ended December 31, 2015 available on SEDAR or at the Company's website (www.vermilionenergy.com).
DISCLAIMER
Certain statements included or incorporated by reference in this press release may constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this press release may include, but are not limited to:
Statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
SOURCE Vermilion Energy Inc.
CALGARY, June 10, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on July 15, 2016 to all shareholders of record on June 22, 2016. The ex-dividend date for this payment is June 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, May 13, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on June 15, 2016 to all shareholders of record on May 24, 2016. The ex-dividend date for this payment is May 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 6%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, May 6, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion" or "Company") (TSX, NYSE: VET) is pleased to report that at its annual meeting of shareholders held on May 6, 2016 each of the nine nominees proposed as directors and listed in its Proxy Statement and Information Circular dated April 6, 2015, were elected as directors of the Company.
The detailed results of the vote by ballot are as follows:
Votes for |
Votes Withheld | |||
Number |
Percent (%) |
Number |
Percent (%) | |
Larry J. Macdonald |
69,305,638 |
95.29 |
3,425,640 |
4.71 |
Lorenzo Donadeo |
69,822,039 |
96.00 |
2,909,239 |
4.00 |
Claudio A. Ghersinich |
69,818,697 |
96.00 |
2,912,581 |
4.00 |
Loren M. Leiker |
72,677,044 |
99.93 |
54,234 |
0.07 |
William F. Madison |
72,513,315 |
99.70 |
217,963 |
0.30 |
Dr. Timothy R. Marchant |
72,671,095 |
99.92 |
60,183 |
0.08 |
Anthony Marino |
71,071,526 |
97.72 |
1,659,752 |
2.28 |
Sarah E. Raiss |
72,093,775 |
99.12 |
637,503 |
0.88 |
Catherine L. Williams |
72,093,352 |
99.12 |
637,926 |
0.88 |
For complete voting results, please see our Report of Voting Results available through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, May 6, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three months ended March 31, 2016.
HIGHLIGHTS
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
ANNUAL GENERAL MEETING WEBCAST
As Vermilion's Annual General Shareholders Meeting is being held today, May 6, 2016 at 10:00 AM MST at the Metropolitan Centre, 333 – 4th Avenue S.W., Calgary, Alberta, there will not be a first quarter conference call. In lieu of the conference call, a presentation will be given by Mr. Anthony Marino, President & Chief Executive Officer at the end of the meeting. Questions from the public can be submitted via the webcast.
Please visit http://event.on24.com/r.htm?e=1160062&s=1&k=7AC4E39F48A74F6596F60B059A660FC5 or Vermilion's website at http://www.vermilionenergy.com/ir/eventspresentations.cfm and click on webcast under the upcoming events to view the webcast which will commence at approximately 10:15 AM MST.
HIGHLIGHTS |
|||||
Three Months Ended | |||||
($M except as indicated) |
Mar 31, |
Dec 31, |
Mar 31, | ||
Financial |
2016 |
2015 |
2015 | ||
Petroleum and natural gas sales |
177,385 |
234,319 |
195,885 | ||
Fund flows from operations |
93,667 |
136,441 |
120,795 | ||
Fund flows from operations ($/basic share) (1) |
0.83 |
1.22 |
1.12 | ||
Fund flows from operations ($/diluted share) (1) |
0.82 |
1.21 |
1.11 | ||
Net (loss) earnings |
(85,848) |
(142,080) |
1,275 | ||
Net (loss) earnings ($/basic share) |
(0.76) |
(1.28) |
0.01 | ||
Capital expenditures |
62,773 |
128,996 |
174,311 | ||
Acquisitions |
870 |
6,227 |
35 | ||
Asset retirement obligations settled |
2,024 |
4,921 |
3,107 | ||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 | ||
Dividends declared |
72,847 |
71,965 |
69,390 | ||
% of fund flows from operations |
78% |
53% |
57% | ||
Net dividends (1) |
24,857 |
25,201 |
48,012 | ||
% of fund flows from operations |
27% |
18% |
40% | ||
Payout (1) |
89,654 |
159,118 |
225,430 | ||
% of fund flows from operations |
96% |
117% |
187% | ||
% of fund flows from operations (excluding the Corrib project) (1) |
N/A |
106% |
173% | ||
Net debt |
1,367,063 |
1,381,951 |
1,388,603 | ||
Ratio of net debt to annualized fund flows from operations |
3.6 |
2.5 |
2.9 | ||
Operational |
|||||
Production |
|||||
Crude oil and condensate (bbls/d) |
29,199 |
31,304 |
29,514 | ||
NGLs (bbls/d) |
2,672 |
2,739 |
1,706 | ||
Natural gas (mmcf/d) |
201.11 |
162.09 |
115.00 | ||
Total (boe/d) |
65,389 |
61,058 |
50,386 | ||
Average realized prices |
|||||
Crude oil, condensate and NGLs ($/bbl) |
39.35 |
51.64 |
58.25 | ||
Natural gas ($/mmbtu) |
3.76 |
4.55 |
5.26 | ||
Production mix (% of production) |
|||||
% priced with reference to WTI |
20% |
21% |
28% | ||
% priced with reference to AECO |
25% |
24% |
20% | ||
% priced with reference to TTF and NBP |
26% |
20% |
18% | ||
% priced with reference to Dated Brent |
29% |
35% |
34% | ||
Netbacks ($/boe) |
|||||
Operating netback |
21.63 |
28.44 |
31.30 | ||
Fund flows from operations netback |
16.12 |
23.91 |
29.07 | ||
Operating expenses |
9.58 |
11.50 |
10.56 | ||
Average reference prices |
|||||
WTI (US $/bbl) |
33.45 |
42.18 |
48.63 | ||
Edmonton Sweet index (US $/bbl) |
29.76 |
39.72 |
41.83 | ||
Dated Brent (US $/bbl) |
33.89 |
43.69 |
53.97 | ||
AECO ($/mmbtu) |
1.83 |
2.46 |
2.75 | ||
TTF ($/mmbtu) |
5.70 |
7.28 |
8.70 | ||
Average foreign currency exchange rates |
|||||
CDN $/US $ |
1.37 |
1.34 |
1.24 | ||
CDN $/Euro |
1.52 |
1.46 |
1.40 | ||
Share information ('000s) |
|||||
Shares outstanding - basic |
113,451 |
111,991 |
107,718 | ||
Shares outstanding - diluted (1) |
116,491 |
115,025 |
110,761 | ||
Weighted average shares outstanding - basic |
112,725 |
111,393 |
107,513 | ||
Weighted average shares outstanding - diluted (1) |
114,110 |
112,543 |
109,305 |
(1) |
The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; estimated contingent resources; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates and interest rates; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
ABBREVIATIONS
$M |
thousand dollars |
$MM |
million dollars |
AECO |
the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta |
bbl(s) |
barrel(s) |
bbls/d |
barrels per day |
bcf |
billion cubic feet |
boe |
barrel of oil equivalent, including: crude oil, condensate, natural gas liquids, and natural gas (converted on the basis of one boe for six mcf of natural gas) |
boe/d |
barrel of oil equivalent per day |
btu |
British thermal units |
CGU |
Cash generating unit, the basis upon which Vermilion's assets are evaluated for potential impairments |
DRIP |
Dividend Reinvestment Plan |
GJ |
gigajoules |
HH |
Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana |
mbbls |
thousand barrels |
mboe |
thousand barrel of oil equivalent |
mcf |
thousand cubic feet |
mcf/d |
thousand cubic feet per day |
mmboe |
million barrel of oil equivalent |
mmbtu |
million British thermal units |
mmcf |
million cubic feet |
mmcf/d |
million cubic feet per day |
MWh |
megawatt hour |
NBP |
the reference price paid for natural gas in the United Kingdom, quoted in pence per therm, at the National Balancing Point Virtual Trading Point operated by National Grid. Our production in Ireland is priced with reference to NBP. |
NGLs |
natural gas liquids, which includes butane, propane, and ethane |
PRRT |
Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia |
TTF |
the day-ahead price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility |
Virtual Trading Point operated by Dutch TSO Gas Transport Services | |
WTI |
West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma |
MESSAGE TO SHAREHOLDERS
While oil prices have now risen from the lows reached in Q1 2016, we continue to experience significant volatility in energy commodity prices and uncertainty as to the timing of a sustained price recovery. During this period of challenging economic conditions in the energy sector, a number of companies have been forced to undertake asset sales and dividend reductions or cancellations to remain viable. At Vermilion, we have always taken a conservative approach to managing our balance sheet, historically maintaining significantly lower leverage than many of our peers. Consequently, we entered the commodity price downturn in a position of relative financial strength, allowing us to maintain an adequate balance sheet through cost and investment reductions without the need to undertake asset sale or dividend reduction measures. Our first priority remains the protection of our balance sheet, followed by protection of our dividend. We believe our Company remains well positioned on both accounts. At the same time, we have been making very capital-efficient investments in our business to continue to record strong production growth per share.
We remain committed to preserving this sustainable business model. We are basing our cost and investment structure on the current commodity price strip, ensuring that fund flows from operations exceed our cash outflows for net dividends and exploration and development ("E&D") capital expenditures. During the first quarter, we reduced our planned E&D capital budget by $50 million to enhance Vermilion's sustainability in the falling commodity price environment. The resulting $235 million E&D budget represents a decrease of over 50% from 2015 levels and more than 65% from 2014 levels. Despite this significant reduction in capital investment, we still anticipate delivering production of between 62,500 to 63,500 boe/d, reflecting year-over-year production growth of 15%, or nearly 10% on a per share basis. Production additions from Corrib plus growth in other business units made possible through significantly improved capital efficiencies have enabled this strong per share growth despite significantly lower capital investment levels.
For 2016, we intend to adhere closely to our $235 million E&D capital budget. Using recent commodity strip pricing and taking into account this planned level of spending, we expect to incur only minimal cash taxes, estimated at $10 to $20 million, and project a total payout ratio of less than 80%. Should a meaningful recovery in commodity prices occur in 2016, we expect to direct the vast majority of incremental cash flow to debt reduction rather than increasing capital spending. Conversely, if there is significant deterioration in commodity prices, we would seek to reduce our expenditures further to avoid incurring additional debt on our balance sheet.
Our international diversification provides structural pricing advantages that differentiate Vermilion from its peers. While European natural gas prices have been under pressure in 2016, they remain substantially above North American gas prices. In addition, our overseas oil production is indexed to Dated Brent, which continues to trade at a premium to WTI. Overall, the prices realized for our international production exceed those received by most North American producers and most particularly by our Canadian peers. Our price-advantaged Brent crude oil and European natural gas business units are anticipated to generate approximately 80% of Vermilion's 2016 fund flows from operations, and the majority of our 2016 capital expenditures are directed to these business units to exploit this advantage.
Vermilion's international exposure and diversified project inventory also provide flexibility to react to changing conditions and selectively allocate capital to the highest rate of return projects for a given commodity environment. This advantage is even more evident when capital availability is restricted. Since the announcement of our $235 million capital budget, we have further revised some of our planned activities including the reinstatement of a two (0.9 net) well drilling program in the Netherlands, finding investment and cost reductions elsewhere in our budget to fund the Netherlands wells.
We have included the two Netherlands wells in our 2016 capital program because of the prolific productivity of our Netherlands gas reservoirs and the premium price received for our European natural gas. We plan to drill the Langezwaag-03 (42% working interest) and Andel-6ST (45% working interest) wells during Q3 2016. If successful, we expect to bring the wells on-stream late in the third and fourth quarters of 2016, respectively. Activities in France will continue to focus on our highly-economic workover and optimization activities. In Germany, the majority of our capital in 2016 will be directed to permitting and pre-drill activities for the planned drilling of the Burgmoor Z5 well and two potential exploration prospects in 2017.
Since the initiation of first gas at Corrib in Ireland on December 30, 2015, we have experienced robust well deliverability and minimal downtime. Net production in Q1 2016 averaged approximately 34 mmcf/d (5,650 boe/d). Field production is subject to limitations on maximum pipeline operating pressures that will remain in effect until the planned recertification process for the third party sales gas distribution pipeline network is concluded. Five of the six wells are capable of producing, with the remaining well to be brought online in the third quarter of 2016 following the conclusion of our offshore work program to lay a pipeline to the sixth well. Upon completion of the recertification process, production levels at Corrib are expected to rise to an estimated peak rate of 58 mmcf/d (9,700 boe/d), net to Vermilion. Corrib remains one of the drivers of our 2016 and 2017 production growth, and is expected to be an important contributor to free cash flow(1) in this and coming years.
Following our successful sidetrack well drilled from the Wandoo A platform in Q4 2015, we are planning a two-well drilling program in Q2 2016. Offshore drilling in Australia requires a great deal of advance contracting and logistical planning, which means that full-cycle costs are minimized by maintaining funding for this project in 2016 despite current oil price weakness. Furthermore, with service costs near their lows, it is an advantageous time to drill these high-quality sidetrack wells.
In Canada, our Mannville condensate-rich gas assets performed strongly in the first quarter with average production of 13,000 boe/d, an increase of 18% percent over the prior quarter. This significant production increase resulted from the combination of both operated and non-operated drilling and completion activity, as well as the re-start of non-operated wells that were previously shut-in due to infrastructure capacity constraints. Our drilling, completion, equip and tie-in ("DCET") costs continue to improve as a result of our ongoing focus on operational and process improvements and continued service cost reductions. Our DCET costs in the Mannville averaged $3.6 million per well in the first quarter of 2016, a nearly 15% reduction as compared to our average DCET of $4.2 million per well in 2015, and approximately a 40% reduction from our cost level when we imitated this play three years ago.
Similarly, cycle times and costs continue to trend lower in our Midale light oil development in southeast Saskatchewan. Since assuming operations in 2014, we have achieved more than a 35% reduction in average drilling days per well, as well as benefitting from lower service costs. Expected DCET costs for a typical one-mile Midale horizontal well are now $1.9 million, down 35% as compared to $2.9 million in 2014. In the first quarter we drilled six (4.5 net) oil wells in the Midale, including three (3.0 net) operated wells, to prevent mineral land expiries. All three operated wells had strong oil indicators, but we have elected to leave these wells standing uncompleted. While the wells are economic to complete, we believe that net present value will be enhanced by delaying completion and tie-in until oil prices improve.
In the United States, we are disclosing results for several wells drilled in our shallow Turner Sand play on the eastern flank of the Powder River Basin in Wyoming. The Seedy Draw North Federal 1H well was completed in Q3 2015 in the Turner Shurley Sand in the southern part of our contiguous 83,250 acre lease block. This well is significantly outperforming our 275 mbbl oil type curve established from a nearby well drilled by the previous operator. Peak production of approximately 300 bbls/d of oil was recorded in the third through fifth months of production. The Seedy Draw North Federal 1H is currently producing 200 bbls/d of oil (240 boed/d including gas production) in its ninth month of production, with cumulative oil production to-date of 63 mbbls.
Two additional wells drilled in the Turner Shurley Sand in Q4 2015 were completed during the first quarter. Both wells were completed with 20-stage fracturing treatments along 1,400 meter horizontal laterals at a vertical depth of approximately 1,500 meters. One of the wells (the Coyote Draw Federal 1H), located in the north part of our lease block, has been on production for one month at a current oil rate of 150 bbls/d, and is expected to continue to increase in production as load water is recovered and the well cleans up. The second well (the Reed Federal 17-1H) was drilled in the southern area, approximately one mile from our Seedy Draw North Federal 1H well. The Reed Federal 17-1H was successfully fracture stimulated, but we unfortunately junked almost the entire horizontal liner section when we attempted to drill out the frac plugs. The well is producing 65 bbls/d of oil from approximately 10% of the completed horizontal section. Despite the mechanical failure of the Reed Federal 17-1H, we consider these well results very encouraging in terms of productivity as we begin development of this large contiguous lease block in the Turner Sand.
We entered the current commodity downturn in a position of relative financial strength, and we took a number of actions throughout 2015 to preserve our balance sheet. During Q1 2016, we redeemed our senior unsecured notes that came due on February 10, 2016 using funds drawn against our revolving credit facility. Following the redemption, all of our debt is now classified as senior debt pursuant to the terms of the revolving credit facility. As a result, we requested, and received amendments from our lending syndicate to eliminate the consolidated total senior debt to consolidated EBITDA(2) financial covenant and increase the ratio of consolidated total senior debt to total capitalization financial covenant from 50% to 55%. The revolving credit facility limit of $2.0 billion remains unchanged and we have approximately $520 million of borrowing capacity available. We were in compliance with all covenants as of March 31, 2016 and expect, based on 2016 commodity strip pricing, to remain in compliance with the amended financial covenants.
We continue to prioritize the strength of our balance sheet and the long-term profitability of our business through our Profitability Enhancement Program ("PEP") initiative. Associated PEP cost savings related to capital spending, operating expense and G&A expenditures reached nearly $90 million for full-year 2015. For 2016, we expect to deliver a further $30 to $40 million of cost reductions. Our focus on driving down costs has generated tangible results. Finding and development costs(3), as estimated at year-end 2015, were down 48% year-over-year and our unit operating expenses for Q1 2016 are down 17% quarter-over-quarter and 9% year-over-year, reflecting both increased volumes and our reduced cost structure.
Vermilion was recently ranked 9th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list, an improvement over last year's ranking of 15th. We are also the highest rated oil and gas company on the list of top sustainability performers. This recognition reflects Vermilion's focus on financial results combined with exemplary environmental, social and governance performance.
Vermilion was recognized by the Great Place to Work® Institute as a Best Workplace in Canada, France, the Netherlands and Germany in 2016. Vermilion was the only energy company to rank on the Best Workplaces lists in Canada and in France. The Great Place to Work® awards recognize Vermilion's strong corporate culture, a key driver of Vermilion's leading long-term corporate performance.
In spite of the challenges posed by the current commodity environment, we continue to believe our long-term strategy will position Vermilion to exit this downturn stronger than ever. All Vermilion employees are shareholders, and management and directors hold approximately 6% of our outstanding shares, ensuring alignment of interests to deliver long-term value. We believe that our diversified asset portfolio and operational capabilities position us to protect our balance sheet, defend our dividend, and continue long-term growth.
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) |
Our covenants include financial measures defined within our revolving credit facility. Please see the "Financial Position Review" section of the Management's Discussion and Analysis. |
(3) |
Finding and development costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital costs for the period, including the change in undiscounted future development capital, by the change in the reserves, incorporating revisions and production, for the same period. |
ORGANIZATIONAL UPDATE
We wish to acknowledge that Joe Killi and Kevin Reinhart are not standing for re-election as directors at the May 6, 2016 Annual General Meeting. Both individuals have been key contributors to Vermilion's success during their tenures with the Board and we would like to take this opportunity to thank them for their valuable counsel and wish them all the best in their future endeavours.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis ("MD&A"), dated May 5, 2016, of Vermilion Energy Inc.'s ("Vermilion", "We", "Our", "Us" or the "Company") operating and financial results as at and for the three months ended March 31, 2016 compared with the corresponding period in the prior year.
This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three months ended March 31, 2016 and the audited consolidated financial statements for the year ended December 31, 2015 and 2014, together with accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
The unaudited condensed consolidated interim financial statements for the three months ended March 31, 2016 and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with IAS 34, "Interim Financial Reporting", as issued by the International Accounting Standard Board ("IASB").
This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). These financial measures include:
In addition, this MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS and are not disclosed in our financial statements. As such, these financial measures are considered non-GAAP financial measures and therefore are unlikely to be comparable with similar financial measures presented by other issuers. For a full description of these non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "NON-GAAP FINANCIAL MEASURES".
VERMILION'S BUSINESS
Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, exploration, development and optimization of producing properties in North America, Europe, and Australia. We manage our business through our Calgary head office and our international business unit offices.
This MD&A separately discusses each of our business units in addition to our corporate segment.
CHANGE IN PRESENTATION
Prior to 2016, we reported our condensate production in Canada and the Netherlands business units within the NGLs production line. Beginning in Q1 2016, we now report condensate production within the crude oil and condensate production line. We believe that this presentation better reflects the historical and forecasted pricing for condensate, which is more closely correlated with crude oil pricing than with pricing for propane, butane and ethane (collectively "NGLs" for the purposes of this report). Comparative periods have been adjusted to reflect this change.
2015 REVIEW AND 2016 GUIDANCE
On November 9, 2015 we announced preliminary 2016 capital expenditure guidance of $350 million and production guidance of between 63,000-65,000 boe/d. On January 5, 2016, in response to the continued weakness in commodity prices we adjusted our 2016 capital expenditure guidance to $285 million with corresponding production guidance of 62,500-63,500 boe/d. On February 29, 2016, we further revised our 2016 capital expenditure guidance to $235 million as a result of continued commodity price deterioration. We maintained our production guidance of 62,500-63,500 boe/d. The February 29, 2016 reduction primarily reflects lower expected non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands pipeline twinning program.
The following table summarizes our 2016 guidance:
Date |
Capital Expenditures ($MM) |
Production (boe/d) | ||||
2016 Guidance |
||||||
2016 Guidance |
November 9, 2015 |
350 |
63,000 to 65,000 | |||
2016 Guidance |
January 5, 2016 |
285 |
62,500 to 63,500 | |||
2016 Guidance |
February 29, 2016 |
235 |
62,500 to 63,500 |
CONSOLIDATED RESULTS OVERVIEW
Three Months Ended |
% change | |||||||
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||||
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||||
Production |
||||||||
Crude oil and condensate (bbls/d) |
29,199 |
31,304 |
29,514 |
(7%) |
(1%) | |||
NGLs (bbls/d) |
2,672 |
2,739 |
1,706 |
(2%) |
57% | |||
Natural gas (mmcf/d) |
201.11 |
162.09 |
115.00 |
24% |
75% | |||
Total (boe/d) |
65,389 |
61,058 |
50,386 |
7% |
30% | |||
Build (draw) in inventory (mbbls) |
142 |
(93) |
383 |
|||||
Financial metrics |
||||||||
Fund flows from operations ($M) |
93,667 |
136,441 |
120,795 |
(31%) |
(22%) | |||
Per share ($/basic share) |
0.83 |
1.22 |
1.12 |
(32%) |
(26%) | |||
Net (loss) earnings |
(85,848) |
(142,080) |
1,275 |
(40%) |
(6,833%) | |||
Per share ($/basic share) |
(0.76) |
(1.28) |
0.01 |
(41%) |
(7,700%) | |||
Cash flows from operating activities ($M) |
73,883 |
164,863 |
22,647 |
(55%) |
226% | |||
Net debt ($M) |
1,367,063 |
1,381,951 |
1,388,603 |
(1%) |
(2%) | |||
Cash dividends ($/share) |
0.645 |
0.645 |
0.645 |
- |
- | |||
Activity |
||||||||
Capital expenditures ($M) |
62,773 |
128,996 |
174,311 |
(51%) |
(64%) | |||
Acquisitions ($M) |
870 |
6,227 |
35 |
(86%) |
2,386% | |||
Gross wells drilled |
12.00 |
8.00 |
29.00 |
|||||
Net wells drilled |
8.26 |
5.56 |
20.04 |
Operational review
Financial review
Net (loss) earnings
Cash flows from operating activities
Fund flows from operations
Net debt
Dividends
COMMODITY PRICES
Three Months Ended |
% change | |||||||
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||||
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||||
Average reference prices |
||||||||
Crude oil |
||||||||
WTI (US $/bbl) |
33.45 |
42.18 |
48.63 |
(21%) |
(31%) | |||
Edmonton Sweet index (US $/bbl) |
29.76 |
39.72 |
41.83 |
(25%) |
(29%) | |||
Dated Brent (US $/bbl) |
33.89 |
43.69 |
53.97 |
(22%) |
(37%) | |||
Natural gas |
||||||||
AECO ($/mmbtu) |
1.83 |
2.46 |
2.75 |
(26%) |
(33%) | |||
TTF ($/mmbtu) |
5.70 |
7.28 |
8.70 |
(22%) |
(34%) | |||
TTF (€/mmbtu) |
3.76 |
4.98 |
6.23 |
(24%) |
(40%) | |||
NBP ($/mmbtu) |
5.97 |
7.41 |
9.01 |
(19%) |
(34%) | |||
NBP (€/mmbtu) |
3.94 |
5.07 |
6.45 |
(22%) |
(39%) | |||
Henry Hub ($/mmbtu) |
2.87 |
3.03 |
3.70 |
(5%) |
(22%) | |||
Henry Hub (US $/mmbtu) |
2.09 |
2.27 |
2.98 |
(8%) |
(30%) | |||
Average foreign currency exchange rates |
||||||||
CDN $/US $ |
1.37 |
1.34 |
1.24 |
2% |
10% | |||
CDN $/Euro |
1.52 |
1.46 |
1.40 |
4% |
9% | |||
Average realized prices ($/boe) |
||||||||
Canada |
21.16 |
28.94 |
35.81 |
(27%) |
(41%) | |||
France |
43.16 |
54.20 |
64.33 |
(20%) |
(33%) | |||
Netherlands |
33.26 |
42.61 |
48.60 |
(22%) |
(32%) | |||
Germany |
31.78 |
39.68 |
45.21 |
(20%) |
(30%) | |||
Ireland |
33.07 |
- |
- |
100% |
100% | |||
Australia |
46.93 |
58.74 |
83.80 |
(20%) |
(44%) | |||
United States |
30.10 |
41.94 |
48.79 |
(28%) |
(38%) | |||
Consolidated |
30.53 |
41.04 |
47.17 |
(26%) |
(35%) | |||
Production mix (% of production) |
||||||||
% priced with reference to WTI |
20% |
22% |
28% |
|||||
% priced with reference to AECO |
25% |
24% |
20% |
|||||
% priced with reference to TTF and NBP |
26% |
20% |
18% |
|||||
% priced with reference to Dated Brent |
29% |
34% |
34% |
FUND FLOWS FROM OPERATIONS
Three Months Ended | |||||||||
Mar 31, 2016 |
Dec 31, 2015 |
Mar 31, 2015 | |||||||
$M |
$/boe |
$M |
$/boe |
$M |
$/boe | ||||
Petroleum and natural gas sales |
177,385 |
30.53 |
234,319 |
41.04 |
195,885 |
47.17 | |||
Royalties |
(13,961) |
(2.40) |
(16,285) |
(2.85) |
(16,424) |
(3.95) | |||
Petroleum and natural gas revenues |
163,424 |
28.13 |
218,034 |
38.19 |
179,461 |
43.22 | |||
Transportation |
(10,390) |
(1.79) |
(10,147) |
(1.78) |
(9,540) |
(2.30) | |||
Operating |
(55,628) |
(9.58) |
(65,645) |
(11.50) |
(43,851) |
(10.56) | |||
General and administration |
(13,577) |
(2.34) |
(12,431) |
(2.18) |
(13,560) |
(3.27) | |||
PRRT |
(128) |
(0.02) |
(1,054) |
(0.18) |
(2,354) |
(0.57) | |||
Corporate income taxes |
(3,160) |
(0.54) |
3,113 |
0.55 |
(17,623) |
(4.24) | |||
Interest expense |
(14,750) |
(2.54) |
(16,584) |
(2.90) |
(13,298) |
(3.20) | |||
Realized gain on derivative instruments |
28,423 |
4.89 |
21,164 |
3.71 |
6,257 |
1.51 | |||
Realized foreign exchange (loss) gain |
(652) |
(0.11) |
(252) |
(0.04) |
3,306 |
0.78 | |||
Realized other income |
105 |
0.02 |
243 |
0.04 |
31,997 |
7.70 | |||
Fund flows from operations |
93,667 |
16.12 |
136,441 |
23.91 |
120,795 |
29.07 |
The following table shows a reconciliation of the change in fund flows from operations:
($M) |
Q1/16 vs. Q4/15 |
Q1/16 vs. Q1/15 | ||||
Fund flows from operations – Comparative period |
136,441 |
120,795 | ||||
Sales volume variance: |
||||||
Canada |
684 |
6,322 | ||||
France |
(2,470) |
11,538 | ||||
Netherlands |
(2,473) |
12,812 | ||||
Germany |
(245) |
(464) | ||||
Ireland |
16,947 |
17,004 | ||||
Australia |
(23,000) |
16,313 | ||||
United States |
(229) |
545 | ||||
Pricing variance on sold volumes: |
||||||
WTI |
(13,270) |
(18,885) | ||||
AECO |
(5,658) |
(9,195) | ||||
Dated Brent |
(17,833) |
(38,907) | ||||
TTF and NBP |
(9,387) |
(15,583) | ||||
Changes in: |
||||||
Royalties |
2,324 |
2,463 | ||||
Transportation |
(243) |
(850) | ||||
Operating |
10,017 |
(11,777) | ||||
General and administration |
(1,146) |
(17) | ||||
PRRT |
926 |
2,226 | ||||
Corporate income taxes |
(6,273) |
14,463 | ||||
Interest |
1,834 |
(1,452) | ||||
Realized derivatives |
7,259 |
22,166 | ||||
Realized foreign exchange |
(400) |
(3,958) | ||||
Realized other income |
(138) |
(31,892) | ||||
Fund flows from operations – Current period |
93,667 |
93,667 |
Fund flows from operations of $93.7 million during Q1 2016 represented a decrease of 31% versus Q4 2015. This decrease relates primarily to lower pricing on all commodities and a 138,000 bbls build in inventory in Australia (compared to a draw of 97,000 bbls in Q4 2015). The impact of lower pricing was minimized by a full quarter of production from Corrib and global cost reductions, including a 15% decrease in operating costs.
Fund flows from operations decreased 22% for the three months ended March 31, 2016, versus the comparable period in 2015. The decrease was the result of lower pricing for all commodities and the absence of a $31.8 million court-awarded recovery recognized in Q1 2015. The decrease in pricing was partially offset by global cost reductions (including a 9% reduction in per unit operating expense), realized gains on derivative instruments, and lower current taxes.
Fluctuations in fund flows from operations (and correspondingly net (loss) earnings and cash flows from operating activities) may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas. In addition, fund flows from operations may be highly affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the consolidated balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized in income.
CANADA BUSINESS UNIT
Overview
Operational review
Three Months Ended |
% change | |||||||
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||||
Canada business unit |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | |||
Production |
||||||||
Crude oil and condensate (bbls/d) |
10,317 |
10,413 |
12,163 |
(1%) |
(15%) | |||
NGLs (bbls/d) |
2,633 |
2,710 |
1,706 |
(3%) |
54% | |||
Natural gas (mmcf/d) |
97.16 |
87.90 |
61.78 |
11% |
57% | |||
Total (boe/d) |
29,141 |
27,773 |
24,165 |
5% |
21% | |||
Production mix (% of total) |
||||||||
Crude oil and condensate |
35% |
38% |
50% |
|||||
NGLs |
9% |
10% |
7% |
|||||
Natural gas |
56% |
52% |
43% |
|||||
Activity |
||||||||
Capital expenditures ($M) |
29,771 |
27,554 |
114,849 |
8% |
(74%) | |||
Acquisitions ($M) |
755 |
6,169 |
35 |
|||||
Gross wells drilled |
12.00 |
5.00 |
25.00 |
|||||
Net wells drilled |
8.26 |
2.56 |
16.04 |
Production
Activity review
Financial review
Three Months Ended |
% change | ||||||
Canada business unit |
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||
($M except as indicated) |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||
Sales |
56,110 |
73,952 |
77,884 |
(24%) |
(28%) | ||
Royalties |
(5,498) |
(7,146) |
(8,592) |
(23%) |
(36%) | ||
Transportation |
(4,151) |
(3,784) |
(3,942) |
10% |
5% | ||
Operating |
(21,343) |
(24,575) |
(19,099) |
(13%) |
12% | ||
General and administration |
(2,476) |
(3,669) |
(4,015) |
(33%) |
(38%) | ||
Fund flows from operations |
22,642 |
34,778 |
42,236 |
(35%) |
(46%) | ||
Netbacks ($/boe) |
|||||||
Sales |
21.16 |
28.94 |
35.81 |
(27%) |
(41%) | ||
Royalties |
(2.07) |
(2.80) |
(3.95) |
(26%) |
(48%) | ||
Transportation |
(1.57) |
(1.48) |
(1.81) |
6% |
(13%) | ||
Operating |
(8.05) |
(9.62) |
(8.78) |
(16%) |
(8%) | ||
General and administration |
(0.94) |
(1.44) |
(1.85) |
(35%) |
(49%) | ||
Fund flows from operations netback |
8.53 |
13.60 |
19.42 |
(37%) |
(56%) | ||
Realized prices |
|||||||
Crude oil and condensate ($/bbl) |
39.69 |
53.44 |
52.91 |
(26%) |
(25%) | ||
NGLs ($/bbl) |
7.31 |
7.89 |
22.37 |
(7%) |
(67%) | ||
Natural gas ($/mmbtu) |
1.93 |
2.57 |
2.97 |
(25%) |
(35%) | ||
Total ($/boe) |
21.16 |
28.94 |
35.81 |
(27%) |
(41%) | ||
Reference prices |
|||||||
WTI (US $/bbl) |
33.45 |
42.18 |
48.63 |
(21%) |
(31%) | ||
Edmonton Sweet index (US $/bbl) |
29.76 |
39.72 |
41.83 |
(25%) |
(29%) | ||
Edmonton Sweet index ($/bbl) |
40.91 |
53.04 |
51.92 |
(23%) |
(21%) | ||
AECO ($/mmbtu) |
1.83 |
2.46 |
2.75 |
(26%) |
(33%) |
Sales
Royalties
Transportation
Operating
General and administration
FRANCE BUSINESS UNIT
Overview
Operational review
Three Months Ended |
% change | ||||||||
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | |||||
France business unit |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||||
Production |
|||||||||
Crude oil (bbls/d) |
12,220 |
12,537 |
11,463 |
(3%) |
7% | ||||
Natural gas (mmcf/d) |
0.44 |
1.36 |
- |
(68%) |
100% | ||||
Total (boe/d) |
12,293 |
12,763 |
11,463 |
(4%) |
7% | ||||
Inventory (mbbls) |
|||||||||
Opening crude oil inventory |
243 |
239 |
197 |
||||||
Crude oil production |
1,112 |
1,153 |
1,032 |
||||||
Crude oil sales |
(1,108) |
(1,149) |
(930) |
||||||
Closing crude oil inventory |
247 |
243 |
299 |
||||||
Production mix (% of total) |
|||||||||
Crude oil |
99% |
98% |
100% |
||||||
Natural gas |
1% |
2% |
- |
||||||
Activity |
|||||||||
Capital expenditures ($M) |
13,463 |
24,085 |
34,114 |
(44%) |
(61%) | ||||
Acquisitions ($M) |
- |
79 |
- |
||||||
Gross wells drilled |
- |
- |
4.00 |
||||||
Net wells drilled |
- |
- |
4.00 |
Production
Activity review
Financial review
Three Months Ended |
% change | ||||||
France business unit |
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||
($M except as indicated) |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||
Sales |
48,125 |
63,411 |
59,832 |
(24%) |
(20%) | ||
Royalties |
(6,766) |
(7,198) |
(5,102) |
(6%) |
33% | ||
Transportation |
(3,713) |
(4,275) |
(3,011) |
(13%) |
23% | ||
Operating |
(14,320) |
(15,792) |
(10,826) |
(9%) |
32% | ||
General and administration |
(4,676) |
(4,894) |
(5,111) |
(4%) |
(9%) | ||
Other income |
- |
- |
31,775 |
- |
(100%) | ||
Current income taxes |
(34) |
4,529 |
(14,281) |
(101%) |
(100%) | ||
Fund flows from operations |
18,616 |
35,781 |
53,276 |
(48%) |
(65%) | ||
Netbacks ($/boe) |
|||||||
Sales |
43.16 |
54.20 |
64.33 |
(20%) |
(33%) | ||
Royalties |
(6.07) |
(6.15) |
(5.49) |
(1%) |
11% | ||
Transportation |
(3.33) |
(3.65) |
(3.24) |
(9%) |
3% | ||
Operating |
(12.84) |
(13.50) |
(11.64) |
(5%) |
10% | ||
General and administration |
(4.19) |
(4.18) |
(5.49) |
- |
(24%) | ||
Other income |
- |
- |
34.16 |
- |
(100%) | ||
Current income taxes |
(0.03) |
3.87 |
(15.35) |
(101%) |
(100%) | ||
Fund flows from operations netback |
16.70 |
30.59 |
57.28 |
(45%) |
(71%) | ||
Realized prices |
|||||||
Crude oil ($/bbl) |
43.36 |
54.88 |
64.33 |
(21%) |
(33%) | ||
Natural gas ($/mmbtu) |
1.66 |
2.81 |
- |
(41%) |
100% | ||
Total ($/boe) |
43.16 |
54.20 |
64.33 |
(20%) |
(33%) | ||
Reference prices |
|||||||
Dated Brent (US $/bbl) |
33.89 |
43.69 |
53.97 |
(22%) |
(37%) | ||
Dated Brent ($/bbl) |
46.59 |
58.34 |
66.98 |
(20%) |
(30%) |
Sales
Royalties
Transportation
Operating
General and administration
Current income taxes
NETHERLANDS BUSINESS UNIT
Overview
Operational review
Three Months Ended |
% change | ||||||||
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | |||||
Netherlands business unit |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||||
Production |
|||||||||
Condensate (bbls/d) |
114 |
110 |
63 |
4% |
81% | ||||
Natural gas (mmcf/d) |
53.40 |
56.34 |
36.41 |
(5%) |
47% | ||||
Total (boe/d) |
9,015 |
9,500 |
6,132 |
(5%) |
47% | ||||
Activity |
|||||||||
Capital expenditures ($M) |
2,996 |
18,810 |
4,333 |
(84%) |
(31%) |
Production
Activity review
Financial review
Three Months Ended |
% change | ||||||
Netherlands business unit |
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||
($M except as indicated) |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||
Sales |
27,286 |
37,243 |
26,818 |
(27%) |
2% | ||
Royalties |
(460) |
(224) |
(926) |
105% |
(50%) | ||
Operating |
(5,976) |
(6,263) |
(5,826) |
(5%) |
3% | ||
General and administration |
(773) |
(813) |
(737) |
(5%) |
5% | ||
Current income taxes |
(2,200) |
(2,930) |
(2,388) |
(25%) |
(8%) | ||
Fund flows from operations |
17,877 |
27,013 |
16,941 |
(34%) |
6% | ||
Netbacks ($/boe) |
|||||||
Sales |
33.26 |
42.61 |
48.60 |
(22%) |
(32%) | ||
Royalties |
(0.56) |
(0.26) |
(1.68) |
115% |
(67%) | ||
Operating |
(7.28) |
(7.17) |
(10.56) |
2% |
(31%) | ||
General and administration |
(0.94) |
(0.93) |
(1.34) |
1% |
(30%) | ||
Current income taxes |
(2.68) |
(3.35) |
(4.33) |
(20%) |
(38%) | ||
Fund flows from operations netback |
21.80 |
30.90 |
30.69 |
(29%) |
(29%) | ||
Realized prices |
|||||||
Condensate ($/bbl) |
32.24 |
48.30 |
52.93 |
(33%) |
(39%) | ||
Natural gas ($/mmbtu) |
5.55 |
7.09 |
8.09 |
(22%) |
(31%) | ||
Total ($/boe) |
33.26 |
42.61 |
48.60 |
(22%) |
(32%) | ||
Reference prices |
|||||||
TTF ($/mmbtu) |
5.70 |
7.28 |
8.70 |
(22%) |
(34%) | ||
TTF (€/mmbtu) |
3.76 |
4.98 |
6.23 |
(24%) |
(40%) |
Sales
Royalties
Transportation
Operating
General and administration
Current income taxes
GERMANY BUSINESS UNIT
Overview
Operational review
Three Months Ended |
% change | ||||||||
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | |||||
Germany business unit |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||||
Production |
|||||||||
Natural gas (mmcf/d) |
15.96 |
16.17 |
16.80 |
(1%) |
(5%) | ||||
Total (boe/d) |
2,660 |
2,695 |
2,801 |
(1%) |
(5%) | ||||
Activity |
|||||||||
Capital expenditures ($M) |
539 |
(441) |
968 |
(222%) |
(44%) |
Production
Activity review
Financial review
Three Months Ended |
% change | |||||||
Germany business unit |
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | |||
($M except as indicated) |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | |||
Sales |
7,692 |
9,840 |
11,395 |
(22%) |
(32%) | |||
Royalties |
(867) |
(1,166) |
(1,598) |
(26%) |
(46%) | |||
Transportation |
(887) |
(508) |
(894) |
75% |
(1%) | |||
Operating |
(2,593) |
(4,788) |
(1,999) |
(46%) |
30% | |||
General and administration |
(2,428) |
(3,032) |
(1,608) |
(20%) |
51% | |||
Fund flows from operations |
917 |
346 |
5,296 |
165% |
(83%) | |||
Netbacks ($/boe) |
||||||||
Sales |
31.78 |
39.68 |
45.21 |
(20%) |
(30%) | |||
Royalties |
(3.58) |
(4.70) |
(6.34) |
(24%) |
(44%) | |||
Transportation |
(3.67) |
(2.05) |
(3.55) |
79% |
3% | |||
Operating |
(10.71) |
(19.31) |
(7.93) |
(45%) |
35% | |||
General and administration |
(10.03) |
(12.22) |
(6.38) |
(18%) |
57% | |||
Fund flows from operations netback |
3.79 |
1.40 |
21.01 |
171% |
(82%) | |||
Reference prices |
||||||||
TTF ($/mmbtu) |
5.70 |
7.28 |
8.70 |
(22%) |
(34%) | |||
TTF (€/mmbtu) |
3.76 |
4.98 |
6.23 |
(24%) |
(40%) |
Sales
Royalties
Transportation
Operating
General and administration
Current income taxes
IRELAND BUSINESS UNIT
Overview
Operational and financial review
Three Months Ended | |||||||
Ireland business unit |
Mar 31, |
Dec 31, |
Mar 31, | ||||
($M except as indicated) |
2016 |
2015 |
2015 | ||||
Production |
|||||||
Natural gas (mmcf/d) |
33.90 |
0.12 |
- | ||||
Total (boe/d) |
5,650 |
20 |
- | ||||
Activity |
|||||||
Capital expenditures |
3,076 |
12,493 |
12,955 | ||||
Financial Results |
|||||||
Sales |
17,004 |
57 |
- | ||||
Transportation |
(1,639) |
(1,580) |
(1,693) | ||||
Operating |
(3,626) |
(15) |
- | ||||
General and administration |
(1,188) |
(714) |
(512) | ||||
Fund flows from operations |
10,551 |
(2,252) |
(2,205) | ||||
Netbacks ($/boe) |
|||||||
Sales |
33.07 |
- |
- | ||||
Transportation |
(3.19) |
- |
- | ||||
Operating |
(7.05) |
- |
- | ||||
General and administration |
(2.31) |
- |
- | ||||
Fund flows from operations netback |
20.52 |
- |
- | ||||
Reference prices |
|||||||
NBP ($/mmbtu) |
5.97 |
7.41 |
9.01 | ||||
NBP (€/mmbtu) |
3.94 |
5.07 |
6.45 |
Production
Activity review
Sales
Royalties
Transportation
Operating
General and administration
AUSTRALIA BUSINESS UNIT
Overview
Operational review
Three Months Ended |
% change | |||||||
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||||
Australia business unit |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | |||
Production |
||||||||
Crude oil (bbls/d) |
6,180 |
7,824 |
5,672 |
(21%) |
9% | |||
Inventory (mbbls) |
||||||||
Opening crude oil inventory |
75 |
172 |
37 |
|||||
Crude oil production |
562 |
720 |
511 |
|||||
Crude oil sales |
(424) |
(817) |
(230) |
|||||
Closing crude oil inventory |
213 |
75 |
318 |
|||||
Activity |
||||||||
Capital expenditures ($M) |
7,827 |
40,852 |
6,455 |
(81%) |
21% | |||
Gross wells drilled |
- |
1.00 |
- |
|||||
Net wells drilled |
- |
1.00 |
- |
Production
Activity review
Financial review
Three Months Ended |
% change | |||||||
Australia business unit |
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | |||
($M except as indicated) |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | |||
Sales |
19,935 |
47,952 |
19,284 |
(58%) |
3% | |||
Operating |
(7,491) |
(13,941) |
(5,886) |
(46%) |
27% | |||
General and administration |
(1,325) |
(1,768) |
(1,454) |
(25%) |
(9%) | |||
PRRT |
(128) |
(1,054) |
(2,354) |
(88%) |
(95%) | |||
Corporate income taxes |
(777) |
1,201 |
(577) |
(165%) |
35% | |||
Fund flows from operations |
10,214 |
32,390 |
9,013 |
(68%) |
13% | |||
Netbacks ($/boe) |
||||||||
Sales |
46.93 |
58.74 |
83.80 |
(20%) |
(44%) | |||
Operating |
(17.63) |
(17.08) |
(25.58) |
3% |
(31%) | |||
General and administration |
(3.12) |
(2.17) |
(6.32) |
44% |
(51%) | |||
PRRT |
(0.30) |
(1.29) |
(10.23) |
(77%) |
(97%) | |||
Corporate income taxes |
(1.83) |
1.47 |
(2.51) |
(224%) |
(27%) | |||
Fund flows from operations netback |
24.05 |
39.67 |
39.16 |
(39%) |
(39%) | |||
Reference prices |
||||||||
Dated Brent (US $/bbl) |
33.89 |
43.69 |
53.97 |
(22%) |
(37%) | |||
Dated Brent ($/bbl) |
46.59 |
58.34 |
66.98 |
(20%) |
(30%) |
Sales
Royalties and transportation
Operating
General and administration
PRRT and corporate income taxes
UNITED STATES BUSINESS UNIT
Overview
Operational and financial review
Three Months Ended |
% change | ||||||
United States business unit |
Mar 31, |
Dec 31, |
Mar 31, |
Q1/16 vs. |
Q1/16 vs. | ||
($M except as indicated) |
2016 |
2015 |
2015 |
Q4/15 |
Q1/15 | ||
Production |
|||||||
Crude oil (bbls/d) |
368 |
420 |
153 |
(12%) |
141% | ||
NGLs (bbls/d) |
39 |
29 |
- |
34% |
100% | ||
Natural gas (mmcf/d) |
0.26 |
0.20 |
- |
30% |
100% | ||
Total (boe/d) |
450 |
483 |
153 |
(7%) |
194% | ||
Activity |
|||||||
Capital expenditures |
5,101 |
5,643 |
637 |
(10%) |
701% | ||
Acquisitions |
115 |
(21) |
- |
||||
Gross wells drilled |
- |
2.00 |
- |
||||
Net wells drilled |
- |
2.00 |
- |
||||
Financial Results |
|||||||
Sales |
1,233 |
1,864 |
672 |
(34%) |
83% | ||
Royalties |
(370) |
(551) |
(206) |
(33%) |
80% | ||
Operating |
(279) |
(271) |
(215) |
3% |
30% | ||
General and administration |
(1,132) |
(897) |
(1,080) |
26% |
5% | ||
Fund flows from operations |
(548) |
145 |
(829) |
(478%) |
(34%) | ||
Netbacks ($/boe) |
|||||||
Sales |
30.10 |
41.94 |
48.79 |
(28%) |
(38%) | ||
Royalties |
(9.03) |
(12.40) |
(14.98) |
(27%) |
(40%) | ||
Operating |
(6.82) |
(6.11) |
(15.61) |
12% |
(56%) | ||
General and administration |
(27.65) |
(20.18) |
(78.41) |
37% |
(65%) | ||
Fund flows from operations netback |
(13.40) |
3.25 |
(60.21) |
(512%) |
(78%) | ||
Realized prices |
|||||||
Crude oil ($/bbl) |
35.80 |
47.59 |
48.79 |
(25%) |
(27%) | ||
NGLs ($/bbl) |
4.81 |
5.13 |
- |
(6%) |
100% | ||
Natural gas ($/mmbtu) |
0.67 |
0.52 |
- |
29% |
100% | ||
Total ($/boe) |
30.10 |
41.94 |
48.79 |
(28%) |
(38%) | ||
Reference prices |
|||||||
WTI (US $/bbl) |
33.45 |
42.18 |
48.63 |
(21%) |
(31%) | ||
WTI ($/bbl) |
45.99 |
56.32 |
60.35 |
(18%) |
(24%) | ||
Henry Hub (US $/mmbtu) |
2.09 |
2.27 |
2.98 |
(8%) |
(30%) | ||
Henry Hub ($/mmbtu) |
2.87 |
3.03 |
3.70 |
(5%) |
(22%) |
Production
Activity review
Sales
Royalties
Operating
General and administration
CORPORATE
Overview
Financial review
Three Months Ended | ||||||
CORPORATE |
Mar 31, |
Dec 31, |
Mar 31, | |||
($M) |
2016 |
2015 |
2015 | |||
General and administration recovery |
421 |
3,356 |
957 | |||
Current income taxes |
(149) |
313 |
(377) | |||
Interest expense |
(14,750) |
(16,584) |
(13,298) | |||
Realized gain on derivatives |
28,423 |
21,164 |
6,257 | |||
Realized foreign exchange (loss) gain |
(652) |
(252) |
3,306 | |||
Realized other income |
105 |
243 |
222 | |||
Fund flows from operations |
13,398 |
8,240 |
(2,933) |
General and administration
Current income taxes
Interest expense
Hedging
FINANCIAL PERFORMANCE REVIEW
Three Months Ended | |||||||||
Mar 31, |
Dec 31, |
Sep 30, |
Jun 30, |
Mar 31, |
Dec 31, |
Sep 30, |
Jun 30, | ||
($M except per share) |
2016 |
2015 |
2015 |
2015 |
2015 |
2014 |
2014 |
2014 | |
Petroleum and natural gas sales |
177,385 |
234,319 |
245,051 |
264,331 |
195,885 |
306,073 |
344,688 |
387,684 | |
Net (loss) earnings |
(85,848) |
(142,080) |
(83,310) |
6,813 |
1,275 |
58,642 |
53,903 |
53,993 | |
Net (loss) earnings per share |
|||||||||
Basic |
(0.76) |
(1.28) |
(0.76) |
0.06 |
0.01 |
0.55 |
0.50 |
0.51 | |
Diluted |
(0.76) |
(1.28) |
(0.76) |
0.06 |
0.01 |
0.54 |
0.50 |
0.50 |
The following table shows a reconciliation of the change in net (loss) earnings:
($M) |
Q1/16 vs. Q4/15 |
Q1/16 vs. Q1/15 | ||||
Net (loss) earnings - Comparative period |
(142,080) |
1,275 | ||||
Changes in: |
||||||
Fund flows from operations |
(42,774) |
(27,128) | ||||
Equity based compensation |
696 |
(1,797) | ||||
Unrealized gain or loss on derivative instruments |
(18,339) |
29,024 | ||||
Unrealized foreign exchange gain or loss |
7,927 |
6,415 | ||||
Unrealized other expense or income |
147 |
174 | ||||
Accretion |
215 |
(434) | ||||
Depletion and depreciation |
(17,986) |
(34,841) | ||||
Deferred tax |
9,485 |
(43,774) | ||||
Impairment |
116,861 |
(14,762) | ||||
Net loss - Current period |
(85,848) |
(85,848) |
The fluctuations in net (loss) earnings from period-to-period are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations and include: sales, royalties, operating expenses, transportation, general and administration expense, current tax expense, interest expense, realized gains and losses on derivative instruments, and realized foreign exchange gains and losses. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include amounts resulting from acquisitions or charges resulting from impairment or impairment recoveries.
Equity based compensation
Equity based compensation expense relates primarily to non-cash compensation expense attributable to long-term incentives granted to directors, officers, and employees under the Vermilion Incentive Plan ("VIP"). The expense is recognized over the vesting period based on the grant date fair value of awards, adjusted for the ultimate number of awards that actually vest as determined by the Company's achievement of performance conditions.
Equity based compensation in Q1 2016 was relatively consistent with Q4 2015. The increase of $1.8 million as compared to Q1 2015 is due to the settlement of the employee bonus plan with equity in Q1 2016.
Unrealized gain or loss on derivative instruments
Unrealized gain or loss on derivative instruments arise as a result of changes in forecasted future commodity prices. As Vermilion uses derivative instruments to manage the commodity price exposure of our future crude oil and natural gas production, we will normally recognize unrealized gains on derivative instruments when forecasted future commodity prices decline and vice-versa.
For the three months ended March 31 2016, we recognized an unrealized gain on derivative instruments of $9.1 million, relating primarily to a gain on our global natural gas hedges, partially offset by a decrease in the value of crude oil and interest rate hedges. As at March 31, 2016, we have a net derivative asset position of $77.4 million.
Unrealized foreign exchange gain or loss
As a result of Vermilion's international operations, Vermilion conducts business in currencies other than the Canadian dollar and has monetary assets and liabilities (including cash, receivables, payables, long-term debt, derivative assets and liabilities, and intercompany loans) denominated in such currencies. Vermilion's exposure to foreign currencies includes the US dollar, the Euro, and the Australian Dollar.
Unrealized foreign exchange gains and losses are the result of translating monetary assets and liabilities held in non-functional currencies to the respective functional currencies of Vermilion and its subsidiaries. Unrealized foreign exchange primarily results from the translation of Euro denominated financial assets and US dollar denominated financial liabilities. As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain while an appreciation in the US dollar against the Canadian dollar will result in an unrealized foreign exchange loss (and vice-versa).
For the three months ended March 31, 2016, the Canadian dollar strengthened more significantly against the US dollar than the Euro, resulting in an unrealized foreign exchange gain of $1.6 million.
Accretion
Fluctuations in accretion expense are primarily the result of changes in discount rates applicable to the balance of asset retirement obligations and additions resulting from drilling and acquisitions.
Q1 2016 accretion expense was relatively consistent with all comparative periods.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes.
Depletion and depreciation on a per boe basis for Q1 2016 of $21.65 was higher as compared to $18.88 in Q4 2015. The increase quarter-over-quarter is primarily due to a full quarter of Corrib production in Q1 2016. Depletion and depreciation on a per boe basis for Q1 2016 remained relatively consistent with the $21.90 in Q1 2015 as the impact of a full quarter of Corrib production was offset with higher production from natural gas properties in Canada.
Deferred tax
Deferred tax expense (recovery) arises primarily as a result of changes in the accounting basis and tax basis for capital assets and asset retirement obligations and changes in available tax losses. The deferred tax expense for Q1 2016 largely pertains to the de-recognition of certain deferred tax assets.
Impairment
For the three months ended March 31, 2016, Vermilion recorded a non-cash impairment charge of $14.8 million in Ireland as a result of a decline in the price forecast for European natural gas.
FINANCIAL POSITION REVIEW
Balance sheet strategy
We believe that our balance sheet supports our defined growth initiatives and our focus is on managing and maintaining a conservative balance sheet. To ensure that our balance sheet continues to support our defined growth initiatives, we regularly review whether forecasted fund flows from operations is sufficient to finance planned capital expenditures, dividends, and abandonment and reclamation expenditures. To the extent that forecasted fund flows from operations is not expected to be sufficient to fulfill such expenditures, we will evaluate our ability to finance any excess with debt (including borrowing using the unutilized capacity of our existing revolving credit facility), issue equity, or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.
To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations and typically strive to maintain an internally targeted ratio of approximately 1.0 to 1.5 in a normalized commodity price environment. Where prices trend higher, we may target a lower ratio and conversely, in a lower commodity price environment, the acceptable ratio may be higher. At times, we will use our balance sheet to finance acquisitions and, in these situations, we are prepared to accept a higher ratio in the short term but will implement a strategy to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 24 months. This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.
In the current low commodity price environment, Vermilion's net debt to fund flows ratio is expected to be higher than the internally targeted ratio. During this period, Vermilion will remain focused on maintaining a strong balance sheet by aligning capital expenditures within forecasted fund flows from operations, which is continually monitored for revised forward price estimates, as well as by hedging additional European natural gas volumes to maintain a diversified commodity portfolio.
Long-term debt
Our long-term debt as at March 31, 2016 consists entirely of borrowings against our revolving credit facility. We redeemed the senior unsecured notes that came due on February 10, 2016 using funds drawn against the revolving credit facility. Following the redemption, all of Vermilion's debt is now classified as senior debt pursuant to the terms of the revolving credit facility. As a result, Vermilion requested and received amendments from its lending syndicate to eliminate the consolidated total senior debt to consolidated EBITDA financial covenant and increase the ratio of consolidated total senior debt to total capitalization financial covenant from 50% to 55%. The revolving credit facility limit of $2.0 billion remains unchanged. Vermilion was in compliance with all covenants as of March 31, 2016 and expects to remain in compliance based on 2016 commodity strip pricing as of May 5, 2016.
The applicable annual interest rates and the balances recognized on our balance sheet are as follows:
Annual Interest Rate |
As at | |||||||
Mar 31, |
Dec 31, |
Mar 31, |
Dec 31, | |||||
($M) |
2016 |
2015 |
2016 |
2015 | ||||
Revolving credit facility |
3.3% |
3.1% |
1,429,988 |
1,162,998 | ||||
Senior unsecured notes |
6.5% |
6.5% |
- |
224,901 | ||||
Long-term debt |
3.5% |
3.7% |
1,429,988 |
1,387,899 |
Revolving Credit Facility
The following table outlines the current terms of our revolving credit facility:
As at | |||||||
Mar 31, |
Dec 31, | ||||||
2016 |
2015 | ||||||
Total facility amount |
$2.0 billion |
$2.0 billion | |||||
Amount drawn |
$1.4 billion |
$1.2 billion | |||||
Letters of credit outstanding |
$24.7 million |
$25.2 million | |||||
Facility maturity date |
31-May-19 |
31-May-19 |
In addition, the revolving credit facility was subject to the following covenants:
As at | ||||
Mar 31, |
Dec 31, | |||
Financial covenant |
Limit |
2016 |
2015 | |
Consolidated total debt to consolidated EBITDA |
4.0 |
2.47 |
2.23 | |
Consolidated total senior debt to consolidated EBITDA |
3.0 |
2.42 |
1.83 | |
Consolidated total senior debt to total capitalization |
50% |
45% |
36% |
Our covenants include financial measures defined within our revolving credit facility agreement that are not defined under IFRS. These financial measures are defined by our revolving credit facility agreement as follows:
Net debt
Net debt is reconciled to long-term debt, as follows:
As at | ||||
Mar 31, |
Dec 31, | |||
($M) |
2016 |
2015 | ||
Long-term debt |
1,429,988 |
1,162,998 | ||
Current liabilities (1) |
221,225 |
503,731 | ||
Current assets |
(284,150) |
(284,778) | ||
Net debt |
1,367,063 |
1,381,951 | ||
Ratio of net debt to annualized fund flows from operations |
3.6 |
2.7 |
(1) |
Current liabilities at December 31, 2015 includes $224,901 relating to the current portion of long-term debt. |
As at March 31, 2016, long term debt, including the current portion, increased to $1.43 billion (December 31, 2015 - $1.39 billion) as a result of draws on the revolving credit facility during the current year to fund capital expenditures. The increase in long-term debt was offset by working capital changes, such that net debt remained relatively consistent at $1.37 billion. Weaker commodity prices versus the prior periods decreased fund flows from operations, resulting in the ratio of net debt to annualized fund flows from operations increasing.
Shareholders' capital
During the three months ended March 31, 2016, we maintained monthly dividends at $0.215 per share and declared dividends which totalled $72.8 million.
The following table outlines our dividend payment history:
Date |
Monthly dividend per unit or share | |||
January 2003 to December 2007 |
$0.170 | |||
January 2008 to December 2012 |
$0.190 | |||
January 2013 to December 31, 2013 |
$0.200 | |||
January 2014 to Present |
$0.215 |
Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations. During low commodity price cycles, we will initially maintain dividends and allow the ratio to rise. Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels, and acquisition opportunities.
As a further step to preserve our financial flexibility and conservatively exercise our access to capital, we amended our existing dividend reinvestment plan to include a Premium Dividend™ Component in February 2015. The Premium Dividend™ Component, when combined with our continuing Dividend Reinvestment Component, increases our access to the lowest cost sources of equity capital available. While the Premium Dividend™ results in a modest amount of equity issuance, we believe it represents the most prudent approach to preserving near-term balance sheet strength. We view implementation of a Premium Dividend™ as a short-term measure to maintain our financial flexibility while we continue to lower our unit costs and await further clarity on the direction of commodity prices. Both components of our program can be reduced or eliminated at the company's discretion, offering considerable flexibility. We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate.
Although we expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this low commodity price environment to fund cash dividends, capital expenditures, and asset retirement obligations. We will evaluate our ability to finance any shortfalls with debt, issuances of equity, or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.
The following table reconciles the change in shareholders' capital:
Shareholders' Capital |
Number of Shares ('000s) |
Amount ($M) | ||||
Balance as at December 31, 2015 |
111,991 |
2,181,089 | ||||
Shares issued for the DRIP(1) |
1,354 |
47,990 | ||||
Shares issued for equity based compensation |
106 |
4,128 | ||||
Balance as at March 31, 2016 |
113,451 |
2,233,207 |
(1) |
DRIP Refers to Vermilion's dividend reinvestment and Premium DividendTM plans. |
As at March 31, 2016, there were approximately 1.7 million VIP awards outstanding. As at May 5, 2016, there were approximately 113.9 million common shares issued and outstanding.
ASSET RETIREMENT OBLIGATIONS
As at March 31, 2016, asset retirement obligations were $319.0 million compared to $305.6 million as at December 31, 2015.
The increase in asset retirement obligations is largely attributable to an overall decrease in the discount rates applied to the abandonment obligations, as well as accretion and additions from new wells drilled year-to-date.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are entered into in the normal course of operations, including operating leases for which no asset or liability value has been assigned to the consolidated balance sheet as at March 31, 2016.
We have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.
RISK MANAGEMENT
Vermilion is exposed to various market and operational risks. For a detailed discussion of these risks, please see Vermilion's Annual Report for the year ended December 31, 2015.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on Vermilion's consolidated financial statements. Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions. There have been no material changes to our critical accounting estimates used in applying accounting policies for the three months ended March 31, 2016. Further information, including a discussion of critical accounting estimates, can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2015, available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
INTERNAL CONTROL OVER FINANCIAL REPORTING
There was no change in Vermilion's internal control over financial reporting that occurred during the period covered by this MD&A that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Supplemental Table 1: Netbacks
The following table includes financial statement information on a per unit basis by business unit. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.
Three Months Ended March 31, 2016 |
Three Months Ended March 31, 2015 | ||||||||
Oil, Condensate |
Oil, Condensate |
||||||||
& NGLs |
Natural Gas |
Total |
& NGLs |
Natural Gas |
Total | ||||
$/bbl |
$/mcf |
$/boe |
$/bbl |
$/mcf |
$/boe | ||||
Canada |
|||||||||
Sales |
33.11 |
1.93 |
21.16 |
49.15 |
2.97 |
35.81 | |||
Royalties |
(4.03) |
(0.08) |
(2.07) |
(5.87) |
(0.23) |
(3.95) | |||
Transportation |
(2.30) |
(0.16) |
(1.57) |
(2.42) |
(0.16) |
(1.81) | |||
Operating |
(7.32) |
(1.44) |
(8.05) |
(9.02) |
(1.41) |
(8.78) | |||
Operating netback |
19.46 |
0.25 |
9.47 |
31.84 |
1.17 |
21.27 | |||
General and administration |
(0.94) |
(1.85) | |||||||
Fund flows from operations netback |
8.53 |
19.42 | |||||||
France |
|||||||||
Sales |
43.36 |
1.66 |
43.16 |
64.33 |
- |
64.33 | |||
Royalties |
(6.09) |
(0.29) |
(6.07) |
(5.48) |
- |
(5.49) | |||
Transportation |
(3.35) |
- |
(3.33) |
(3.24) |
- |
(3.24) | |||
Operating |
(12.84) |
(2.24) |
(12.84) |
(11.64) |
- |
(11.64) | |||
Operating netback |
21.08 |
(0.87) |
20.92 |
43.97 |
- |
43.96 | |||
General and administration |
(4.19) |
(5.49) | |||||||
Other income |
- |
34.16 | |||||||
Current income taxes |
(0.03) |
(15.35) | |||||||
Fund flows from operations netback |
16.70 |
57.28 | |||||||
Netherlands |
|||||||||
Sales |
32.24 |
5.55 |
33.26 |
52.93 |
8.09 |
48.60 | |||
Royalties |
- |
(0.09) |
(0.56) |
- |
(0.28) |
(1.68) | |||
Operating |
- |
(1.23) |
(7.28) |
- |
(1.78) |
(10.56) | |||
Operating netback |
32.24 |
4.23 |
25.42 |
52.93 |
6.03 |
36.36 | |||
General and administration |
(0.94) |
(1.34) | |||||||
Current income taxes |
(2.68) |
(4.33) | |||||||
Fund flows from operations netback |
21.80 |
30.69 | |||||||
Germany |
|||||||||
Sales |
- |
5.30 |
31.78 |
- |
7.53 |
45.21 | |||
Royalties |
- |
(0.60) |
(3.58) |
- |
(1.06) |
(6.34) | |||
Transportation |
- |
(0.61) |
(3.67) |
- |
(0.59) |
(3.55) | |||
Operating |
- |
(1.79) |
(10.71) |
- |
(1.32) |
(7.93) | |||
Operating netback |
- |
2.30 |
13.82 |
- |
4.56 |
27.39 | |||
General and administration |
(10.03) |
(6.38) | |||||||
Fund flows from operations netback |
3.79 |
21.01 | |||||||
Ireland |
|||||||||
Sales |
- |
5.51 |
33.07 |
- |
- |
- | |||
Transportation |
- |
(0.53) |
(3.19) |
- |
- |
- | |||
Operating |
- |
(1.18) |
(7.05) |
- |
- |
- | |||
Operating netback |
- |
3.80 |
22.83 |
- |
- |
- | |||
General and administration |
(2.31) |
- | |||||||
Fund flows from operations netback |
20.52 |
- | |||||||
Australia |
|||||||||
Sales |
46.93 |
- |
46.93 |
83.80 |
- |
83.80 | |||
Operating |
(17.63) |
- |
(17.63) |
(25.58) |
- |
(25.58) | |||
PRRT (1) |
(0.30) |
- |
(0.30) |
(10.23) |
- |
(10.23) | |||
Operating netback |
29.00 |
- |
29.00 |
47.99 |
- |
47.99 | |||
General and administration |
(3.12) |
(6.32) | |||||||
Corporate income taxes |
(1.83) |
(2.51) | |||||||
Fund flows from operations netback |
24.05 |
39.16 | |||||||
Three Months Ended March 31, 2016 |
Three Months Ended March 31, 2015 | ||||||||
Oil, Condensate |
Oil, Condensate |
||||||||
& NGLs |
Natural Gas |
Total |
& NGLs |
Natural Gas |
Total | ||||
$/bbl |
$/mcf |
$/boe |
$/bbl |
$/mcf |
$/boe | ||||
United States |
|||||||||
Sales |
32.84 |
0.67 |
30.10 |
48.79 |
- |
48.79 | |||
Royalties |
(9.73) |
(0.40) |
(9.03) |
(14.98) |
- |
(14.98) | |||
Operating |
(7.54) |
- |
(6.82) |
(15.61) |
- |
(15.61) | |||
Operating netback |
15.57 |
0.27 |
14.25 |
18.20 |
- |
18.20 | |||
General and administration |
(27.65) |
(78.41) | |||||||
Fund flows from operations netback |
(13.40) |
(60.21) | |||||||
Total Company |
|||||||||
Sales |
39.35 |
3.76 |
30.53 |
58.25 |
5.26 |
47.17 | |||
Realized hedging gain |
3.18 |
1.07 |
4.89 |
0.75 |
0.43 |
1.51 | |||
Royalties |
(4.30) |
(0.11) |
(2.40) |
(5.21) |
(0.37) |
(3.95) | |||
Transportation |
(2.33) |
(0.22) |
(1.79) |
(2.49) |
(0.34) |
(2.30) | |||
Operating |
(11.10) |
(1.37) |
(9.58) |
(11.61) |
(1.51) |
(10.56) | |||
PRRT (1) |
(0.05) |
- |
(0.02) |
(0.97) |
- |
(0.57) | |||
Operating netback |
24.75 |
3.13 |
21.63 |
38.72 |
3.47 |
31.30 | |||
General and administration |
(2.34) |
(3.27) | |||||||
Interest expense |
(2.54) |
(3.20) | |||||||
Realized foreign exchange (loss) gain |
(0.11) |
0.78 | |||||||
Other income |
0.02 |
7.70 | |||||||
Corporate income taxes (1) |
(0.54) |
(4.24) | |||||||
Fund flows from operations netback |
16.12 |
29.07 |
(1) |
Vermilion considers Australian PRRT to be an operating item and, accordingly, has included PRRT in the calculation of operating netbacks. Current income taxes presented above excludes PRRT. |
Supplemental Table 2: Hedges
The following tables outline Vermilion's outstanding risk management positions as at March 31, 2016:
Note |
Volume |
Strike Price(s) | ||||||
Crude Oil |
||||||||
WTI - Collar |
||||||||
July 2015 - June 2016 |
1 |
500 bbls/d |
75.50 - 85.08 CAD $ | |||||
April 2016 - September 2016 |
1 |
500 bbls/d |
52.25 - 64.40 CAD $ | |||||
April 2016 - September 2016 |
2 |
750 bbls/d |
40.50 - 50.40 US $ | |||||
Dated Brent - Collar |
||||||||
July 2015 - June 2016 |
3 |
1,000 bbls/d |
80.50 - 93.49 CAD $ | |||||
July 2015 - June 2016 |
4 |
500 bbls/d |
64.50 - 75.48 US $ | |||||
October 2015 - June 2016 |
5 |
250 bbls/d |
82.00 - 94.55 CAD $ | |||||
January 2016 - June 2016 |
6 |
250 bbls/d |
84.00 - 93.70 CAD $ | |||||
April 2016 - September 2016 |
5 |
250 bbls/d |
52.00 - 64.80 CAD $ | |||||
North American Natural Gas |
||||||||
AECO - Collar |
||||||||
November 2015 - October 2016 |
10,000 GJ/d |
2.56 - 3.23 CAD $ | ||||||
January 2016 - December 2016 |
10,000 GJ/d |
2.53 - 3.29 CAD $ | ||||||
March 2016 - December 2016 |
7 |
5,000 GJ/d |
2.05 - 2.77 CAD $ | |||||
April 2016 - October 2016 |
5,000 GJ/d |
2.30 - 2.80 CAD $ | ||||||
April 2016 - December 2016 |
8 |
2,500 GJ/d |
2.10 - 2.92 CAD $ | |||||
November 2016 - October 2017 |
7 |
7,500 GJ/d |
2.07 - 2.71 CAD $ | |||||
November 2016 - December 2017 |
10,000 GJ/d |
2.21 - 2.86 CAD $ | ||||||
January 2017 - December 2017 |
5,000 GJ/d |
2.25 - 3.09 CAD $ | ||||||
AECO - Swap |
||||||||
April 2016 - October 2016 |
9 |
5,000 GJ/d |
2.59 CAD $ |
(1) |
The contracted volumes increase to 1,250 bbls/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(2) |
The contracted volumes increase to 2,000 bbls/d for any monthly settlement periods above the contracted ceiling price. |
(3) |
The contracted volumes increase to 2,500 bbls/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(4) |
The contracted volumes increase to 1,000 bbls/d for any monthly settlement periods above the contracted ceiling price. |
(5) |
The contracted volumes increase to 750 bbls/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(6) |
The contracted volumes increase to 500 bbls/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(7) |
The contracted volumes increase to 10,000 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(8) |
The contracted volumes increase to 7,500 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(9) |
On the last business day of each month, the counterparty has the option to increase the contracted volumes to 10,000 GJ/d at the contracted price, for the following month. |
Note |
Volume |
Strike Price(s) | |||||
European Natural Gas |
|||||||
NBP - Call |
|||||||
October 2016 - March 2017 |
2,638 GJ/d |
4.64 GBP £ | |||||
NBP - Collar |
|||||||
April 2016 - March 2017 |
2,638 GJ/d |
3.79 - 4.53 GBP £ | |||||
July 2016 - December 2016 |
1 |
2,638 GJ/d |
2.84 - 4.08 GBP £ | ||||
October 2016 - March 2017 |
2 |
2,638 GJ/d |
3.13 - 3.53 GBP £ | ||||
October 2016 - December 2017 |
2 |
2,638 GJ/d |
2.84 - 3.70 GBP £ | ||||
January 2017 - December 2017 |
1 |
5,275 GJ/d |
3.13 - 3.62 GBP £ | ||||
January 2018 - December 2018 |
2,638 GJ/d |
2.99 - 3.63 GBP £ | |||||
NBP - Put |
|||||||
April 2016 - September 2016 |
2,638 GJ/d |
3.79 GBP £ | |||||
NBP - Swap |
|||||||
January 2016 - June 2016 |
5,184 GJ/d |
6.24 EUR € | |||||
January 2016 - June 2016 |
2,592 GJ/d |
6.82 US $ | |||||
July 2016 - March 2017 |
2,592 GJ/d |
5.43 EUR € | |||||
October 2016 - December 2016 |
2,638 GJ/d |
3.24 GBP £ | |||||
January 2017 - December 2017 |
3 |
2,638 GJ/d |
4.00 GBP £ | ||||
January 2018 - December 2018 |
4 |
2,638 GJ/d |
3.83 GBP £ | ||||
TTF - Call |
|||||||
October 2016 - March 2017 |
2,592 GJ/d |
6.03 EUR € | |||||
TTF - Collar |
|||||||
January 2016 - December 2016 |
5 |
2,592 GJ/d |
5.76 - 6.50 EUR € | ||||
April 2016 - December 2016 |
6 |
12,960 GJ/d |
5.58 - 6.21 EUR € | ||||
April 2016 - March 2017 |
7 |
5,184 GJ/d |
5.28 - 6.35 EUR € | ||||
July 2016 - December 2016 |
2,592 GJ/d |
5.00 - 5.63 EUR € | |||||
July 2016 - March 2017 |
5 |
2,592 GJ/d |
5.07 - 6.56 EUR € | ||||
July 2016 - March 2018 |
5 |
2,592 GJ/d |
5.32 - 6.54 EUR € | ||||
October 2016 - December 2017 |
2,592 GJ/d |
5.00 - 5.89 EUR € | |||||
January 2017 - December 2017 |
8 |
7,776 GJ/d |
5.00 - 6.15 EUR € | ||||
April 2017 - September 2017 |
5 |
2,592 GJ/d |
3.61 - 4.24 EUR € | ||||
January 2018 - December 2018 |
5,184 GJ/d |
4.17 - 5.03 EUR € | |||||
TTF - Put |
|||||||
April 2016 - September 2016 |
2,592 GJ/d |
5.21 EUR € | |||||
TTF - Swap |
|||||||
January 2015 - June 2016 |
2,592 GJ/d |
6.07 EUR € | |||||
January 2016 - June 2016 |
5,184 GJ/d |
5.94 EUR € | |||||
April 2016 - December 2016 |
2,592 GJ/d |
5.91 EUR € | |||||
July 2016 - June 2018 |
2,700 GJ/d |
5.58 EUR € | |||||
October 2016 - December 2016 |
2,592 GJ/d |
5.45 EUR € | |||||
January 2017 - December 2017 |
5 |
2,592 GJ/d |
5.04 EUR € | ||||
Fuel and Electricity |
|||||||
GasOil - Swap |
|||||||
March 2016 - December 2016 |
125 bbls/d |
42.55 US $ | |||||
AESO - Swap |
|||||||
January 2016 - December 2016 |
93.6 MWh/d |
38.58 CAD $ | |||||
Interest Rate |
|||||||
CDOR to fixed - Swap |
|||||||
September 2015 - September 2019 |
100,000,000 CAD $/year |
1.00 % | |||||
October 2015 - October 2019 |
100,000,000 CAD $/year |
1.10 % |
(1) |
The contracted volumes increase to 7,913 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(2) |
The contracted volumes increase to 5,275 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(3) |
On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 2,638 GJ/d at the contracted price, for the following month. |
(4) |
On the last business day of each month, the counterparty has the option to increase the contracted volumes to 7,913 GJ/d at the contracted price, for the following month. |
(5) |
The contracted volumes increase to 5,184 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(6) |
The contracted volumes increase to 15,552 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(7) |
The contracted volumes increase to 10,368 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(8) |
The contracted volumes increase to 18,144 GJ/d for any monthly settlement periods above the contracted ceiling price. |
Supplemental Table 3: Capital Expenditures
Three Months Ended | ||||||||
By classification |
Mar 31, |
Dec 31, |
Mar 31, | |||||
($M) |
2016 |
2015 |
2015 | |||||
Drilling and development |
62,773 |
128,996 |
174,311 | |||||
Exploration and evaluation |
- |
- |
- | |||||
Capital expenditures |
62,773 |
128,996 |
174,311 | |||||
Property acquisition |
870 |
6,227 |
35 | |||||
Acquisitions |
870 |
6,227 |
35 | |||||
Three Months Ended | ||||||||
By category |
Mar 31, |
Dec 31, |
Mar 31, | |||||
($M) |
2016 |
2015 |
2015 | |||||
Land |
1,039 |
819 |
742 | |||||
Seismic |
6,268 |
4,217 |
1,493 | |||||
Drilling and completion |
27,853 |
58,327 |
82,343 | |||||
Production equipment and facilities |
6,238 |
55,662 |
74,755 | |||||
Recompletions |
3,598 |
6,338 |
7,115 | |||||
Other |
17,777 |
3,633 |
7,863 | |||||
Capital expenditures |
62,773 |
128,996 |
174,311 | |||||
Acquisitions |
870 |
6,227 |
35 | |||||
Total capital expenditures and acquisitions |
63,643 |
135,223 |
174,346 | |||||
Three Months Ended | ||||||||
By country |
Mar 31, |
Dec 31, |
Mar 31, | |||||
($M) |
2016 |
2015 |
2015 | |||||
Canada |
30,526 |
33,723 |
114,884 | |||||
France |
13,463 |
24,164 |
34,114 | |||||
Netherlands |
2,996 |
18,810 |
4,333 | |||||
Germany |
539 |
(441) |
968 | |||||
Ireland |
3,076 |
12,493 |
12,955 | |||||
Australia |
7,827 |
40,852 |
6,455 | |||||
United States |
5,216 |
5,622 |
637 | |||||
Total capital expenditures and acquisitions |
63,643 |
135,223 |
174,346 |
Supplemental Table 4: Production
Q1/16 |
Q4/15 |
Q3/15 |
Q2/15 |
Q1/15 |
Q4/14 |
Q3/14 |
Q2/14 |
Q1/14 |
Q4/13 |
Q3/13 |
Q2/13 | ||
Canada |
|||||||||||||
Crude oil & condensate |
|||||||||||||
(bbls/d) |
10,317 |
10,413 |
11,030 |
11,843 |
12,163 |
12,681 |
12,755 |
14,108 |
10,390 |
8,719 |
7,969 |
8,885 | |
NGLs (bbls/d) |
2,633 |
2,710 |
2,678 |
2,094 |
1,706 |
1,444 |
1,005 |
1,364 |
1,118 |
1,699 |
1,897 |
1,725 | |
Natural gas (mmcf/d) |
97.16 |
87.90 |
71.94 |
64.66 |
61.78 |
58.36 |
57.07 |
57.59 |
49.53 |
41.43 |
43.40 |
43.69 | |
Total (boe/d) |
29,141 |
27,773 |
25,698 |
24,713 |
24,165 |
23,851 |
23,272 |
25,070 |
19,763 |
17,322 |
17,099 |
17,892 | |
% of consolidated |
44% |
45% |
47% |
48% |
48% |
49% |
47% |
49% |
42% |
43% |
41% |
42% | |
France |
|||||||||||||
Crude oil (bbls/d) |
12,220 |
12,537 |
12,310 |
12,746 |
11,463 |
11,133 |
11,111 |
11,025 |
10,771 |
11,131 |
11,625 |
10,390 | |
Natural gas (mmcf/d) |
0.44 |
1.36 |
1.47 |
1.03 |
- |
- |
- |
- |
- |
- |
5.23 |
4.19 | |
Total (boe/d) |
12,293 |
12,763 |
12,555 |
12,917 |
11,463 |
11,133 |
11,111 |
11,025 |
10,771 |
11,131 |
12,496 |
11,088 | |
% of consolidated |
19% |
21% |
22% |
25% |
23% |
22% |
22% |
21% |
23% |
27% |
30% |
26% | |
Netherlands |
|||||||||||||
Condensate (bbls/d) |
114 |
110 |
109 |
112 |
63 |
81 |
63 |
96 |
69 |
62 |
48 |
50 | |
Natural gas (mmcf/d) |
53.40 |
56.34 |
53.56 |
32.43 |
36.41 |
31.35 |
38.07 |
40.35 |
43.15 |
37.53 |
28.78 |
38.52 | |
Total (boe/d) |
9,015 |
9,500 |
9,035 |
5,517 |
6,132 |
5,306 |
6,407 |
6,822 |
7,260 |
6,318 |
4,845 |
6,470 | |
% of consolidated |
14% |
16% |
16% |
11% |
12% |
11% |
13% |
13% |
16% |
15% |
12% |
15% | |
Germany |
|||||||||||||
Natural gas (mmcf/d) |
15.96 |
16.17 |
14.00 |
16.18 |
16.80 |
17.71 |
15.38 |
16.13 |
10.64 |
- |
- |
- | |
Total (boe/d) |
2,660 |
2,695 |
2,333 |
2,696 |
2,801 |
2,952 |
2,563 |
2,689 |
1,773 |
- |
- |
- | |
% of consolidated |
4% |
4% |
4% |
5% |
6% |
6% |
5% |
5% |
4% |
- |
- |
- | |
Ireland |
|||||||||||||
Natural gas (mmcf/d) |
33.90 |
0.12 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |
Total (boe/d) |
5,650 |
20 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |
% of consolidated |
9% |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |
Australia |
|||||||||||||
Crude oil (bbls/d) |
6,180 |
7,824 |
6,433 |
5,865 |
5,672 |
6,134 |
6,567 |
6,483 |
7,110 |
6,189 |
7,070 |
7,363 | |
% of consolidated |
9% |
13% |
11% |
11% |
11% |
12% |
13% |
12% |
15% |
15% |
17% |
17% | |
United States |
|||||||||||||
Crude oil (bbls/d) |
368 |
420 |
226 |
123 |
153 |
195 |
- |
- |
- |
- |
- |
- | |
NGLs (bbls/d) |
39 |
29 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |
Natural gas (mmcf/d) |
0.26 |
0.20 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |
Total (boe/d) |
450 |
483 |
226 |
123 |
153 |
195 |
- |
- |
- |
- |
- |
- | |
% of consolidated |
1% |
1% |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- | |
Consolidated |
|||||||||||||
Crude oil, condensate |
|||||||||||||
& NGLs (bbls/d) |
31,871 |
34,043 |
32,786 |
32,783 |
31,220 |
31,668 |
31,501 |
33,076 |
29,458 |
27,800 |
28,609 |
28,413 | |
% of consolidated |
49% |
56% |
58% |
63% |
62% |
64% |
63% |
63% |
63% |
68% |
69% |
66% | |
Natural gas (mmcf/d) |
201.11 |
162.09 |
140.97 |
114.29 |
115.00 |
107.42 |
110.52 |
114.08 |
103.32 |
78.96 |
77.41 |
86.40 | |
% of consolidated |
51% |
44% |
42% |
37% |
38% |
36% |
37% |
37% |
37% |
32% |
31% |
34% | |
Total (boe/d) |
65,389 |
61,058 |
56,280 |
51,831 |
50,386 |
49,571 |
49,920 |
52,089 |
46,677 |
40,960 |
41,510 |
42,813 | |
2016 |
2015 |
2014 |
2013 |
2012 |
2011 | ||||||||
Canada |
|||||||||||||
Crude oil and condensate |
|||||||||||||
(bbls/d) |
10,317 |
11,357 |
12,491 |
8,387 |
7,659 |
4,701 | |||||||
NGLs (bbls/d) |
2,633 |
2,301 |
1,233 |
1,666 |
1,232 |
1,297 | |||||||
Natural gas (mmcf/d) |
97.16 |
71.65 |
55.67 |
42.39 |
37.50 |
43.38 | |||||||
Total (boe/d) |
29,141 |
25,598 |
23,001 |
17,117 |
15,142 |
13,227 | |||||||
% of consolidated |
44% |
46% |
47% |
41% |
40% |
38% | |||||||
France |
|||||||||||||
Crude oil (bbls/d) |
12,220 |
12,267 |
11,011 |
10,873 |
9,952 |
8,110 | |||||||
Natural gas (mmcf/d) |
0.44 |
0.97 |
- |
3.40 |
3.59 |
0.95 | |||||||
Total (boe/d) |
12,293 |
12,429 |
11,011 |
11,440 |
10,550 |
8,269 | |||||||
% of consolidated |
19% |
23% |
22% |
28% |
28% |
23% | |||||||
Netherlands |
|||||||||||||
Condensate (bbls/d) |
114 |
99 |
77 |
64 |
67 |
58 | |||||||
Natural gas (mmcf/d) |
53.40 |
44.76 |
38.20 |
35.42 |
34.11 |
32.88 | |||||||
Total (boe/d) |
9,015 |
7,559 |
6,443 |
5,967 |
5,751 |
5,538 | |||||||
% of consolidated |
14% |
14% |
13% |
15% |
15% |
16% | |||||||
Germany |
|||||||||||||
Natural gas (mmcf/d) |
15.96 |
15.78 |
14.99 |
- |
- |
- | |||||||
Total (boe/d) |
2,660 |
2,630 |
2,498 |
- |
- |
- | |||||||
% of consolidated |
4% |
5% |
5% |
- |
- |
- | |||||||
Ireland |
|||||||||||||
Natural gas (mmcf/d) |
33.90 |
0.03 |
- |
- |
- |
- | |||||||
Total (boe/d) |
5,650 |
5 |
- |
- |
- |
- | |||||||
% of consolidated |
9% |
- |
- |
- |
- |
- | |||||||
Australia |
|||||||||||||
Crude oil (bbls/d) |
6,180 |
6,454 |
6,571 |
6,481 |
6,360 |
8,168 | |||||||
% of consolidated |
9% |
12% |
13% |
16% |
17% |
23% | |||||||
United States |
|||||||||||||
Crude oil (bbls/d) |
368 |
231 |
49 |
- |
- |
- | |||||||
NGLs (bbls/d) |
39 |
7 |
- |
- |
- |
- | |||||||
Natural gas (mmcf/d) |
0.26 |
0.05 |
- |
- |
- |
- | |||||||
Total (boe/d) |
450 |
247 |
49 |
- |
- |
- | |||||||
% of consolidated |
1% |
- |
- |
- |
- |
- | |||||||
Consolidated |
|||||||||||||
Crude oil, condensate & |
|||||||||||||
NGLs (bbls/d) |
31,871 |
32,716 |
31,432 |
27,471 |
25,270 |
22,334 | |||||||
% of consolidated |
49% |
60% |
63% |
67% |
67% |
63% | |||||||
Natural gas (mmcf/d) |
201.11 |
133.24 |
108.85 |
81.21 |
75.20 |
77.21 | |||||||
% of consolidated |
51% |
40% |
37% |
33% |
33% |
37% | |||||||
Total (boe/d) |
65,389 |
54,922 |
49,573 |
41,005 |
37,803 |
35,202 |
Supplemental Table 5: Segmented Financial Results
Three Months Ended March 31, 2016 | |||||||||
($M) |
Canada |
France |
Netherlands |
Germany |
Ireland |
Australia |
United States |
Corporate |
Total |
Total assets |
1,584,947 |
833,145 |
195,413 |
159,522 |
838,240 |
240,352 |
44,585 |
176,136 |
4,072,340 |
Drilling and development |
29,771 |
13,463 |
2,996 |
539 |
3,076 |
7,827 |
5,101 |
- |
62,773 |
Oil and gas sales to external customers |
56,110 |
48,125 |
27,286 |
7,692 |
17,004 |
19,935 |
1,233 |
- |
177,385 |
Royalties |
(5,498) |
(6,766) |
(460) |
(867) |
- |
- |
(370) |
- |
(13,961) |
Revenue from external customers |
50,612 |
41,359 |
26,826 |
6,825 |
17,004 |
19,935 |
863 |
- |
163,424 |
Transportation |
(4,151) |
(3,713) |
- |
(887) |
(1,639) |
- |
- |
- |
(10,390) |
Operating |
(21,343) |
(14,320) |
(5,976) |
(2,593) |
(3,626) |
(7,491) |
(279) |
- |
(55,628) |
General and administration |
(2,476) |
(4,676) |
(773) |
(2,428) |
(1,188) |
(1,325) |
(1,132) |
421 |
(13,577) |
PRRT |
- |
- |
- |
- |
- |
(128) |
- |
- |
(128) |
Corporate income taxes |
- |
(34) |
(2,200) |
- |
- |
(777) |
- |
(149) |
(3,160) |
Interest expense |
- |
- |
- |
- |
- |
- |
- |
(14,750) |
(14,750) |
Realized gain on derivative instruments |
- |
- |
- |
- |
- |
- |
- |
28,423 |
28,423 |
Realized foreign exchange loss |
- |
- |
- |
- |
- |
- |
- |
(652) |
(652) |
Realized other income |
- |
- |
- |
- |
- |
- |
- |
105 |
105 |
Fund flows from operations |
22,642 |
18,616 |
17,877 |
917 |
10,551 |
10,214 |
(548) |
13,398 |
93,667 |
NON-GAAP FINANCIAL MEASURES
This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS and are not disclosed in our consolidated financial statements. As such, these financial measures are considered non-GAAP financial measures and therefore may not be comparable with similar measures presented by other issuers.
Fund flows from operations per basic and diluted share: Management assesses fund flows from operations on a per share basis as we believe this provides a measure of our operating performance after taking into account the issuance and potential future issuance of Vermilion common shares. Fund flows from operations per basic share is calculated by dividing fund flows from operations by the basic weighted average shares outstanding as defined under IFRS. Fund flows from operations per diluted share is calculated by dividing fund flows from operations by the sum of basic weighted average shares outstanding and incremental shares issuable under our equity based compensation plans as determined using the treasury stock method.
Free cash flow: Represents fund flows from operations in excess of drilling and development and exploration and evaluation costs (collectively referred to as capital expenditures). We consider free cash flow to be a key measure as it is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures.
Net dividends: We define net dividends as dividends declared less proceeds received for the issuance of shares pursuant to the dividend reinvestment and Premium Dividend™ plans. Management monitors net dividends and net dividends as a percentage of fund flows from operations to assess our ability to pay dividends.
Payout: We define payout as net dividends plus drilling and development costs, exploration and evaluation costs, dispositions, and asset retirement obligations settled. Management uses payout to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.
Fund flows from operations (excluding Corrib) and Payout (excluding Corrib): Management excludes expenditures relating to the Corrib project in assessing fund flows from operations (a non-GAAP financial measure) and payout in order to assess our ability to generate cash and finance organic growth from our current producing assets. Beginning in Q1 2016, the Corrib project is considered a producing asset, so these financial measures are not applicable for the current period.
Diluted shares outstanding: Is the sum of shares outstanding at the period end plus outstanding awards under the VIP, based on current estimates of future performance factors and forfeiture rates.
Cash dividends per share: Represents cash dividends declared per share.
The following tables reconcile fund flows from operations (and excluding Corrib), net dividends, payout (and excluding Corrib), and diluted shares outstanding to their most directly comparable GAAP measures as presented in our financial statements:
Three Months Ended | ||||
Mar 31, |
Dec 31, |
Mar 31, | ||
($M) |
2016 |
2015 |
2015 | |
Cash flows from operating activities |
73,883 |
164,863 |
22,647 | |
Changes in non-cash operating working capital |
17,760 |
(33,343) |
95,041 | |
Asset retirement obligations settled |
2,024 |
4,921 |
3,107 | |
Fund flows from operations |
93,667 |
136,441 |
120,795 | |
Expenses related to Corrib |
N/A |
2,252 |
2,205 | |
Fund flows from operations (excluding Corrib) |
N/A |
138,693 |
123,000 |
Three Months Ended | ||||||
Mar 31, |
Dec 31, |
Mar 31, | ||||
($M) |
2016 |
2015 |
2015 | |||
Dividends declared |
72,847 |
71,965 |
69,390 | |||
Shares issued for the DRIP(1) |
(47,990) |
(46,764) |
(21,378) | |||
Net dividends |
24,857 |
25,201 |
48,012 | |||
Drilling and development |
62,773 |
128,996 |
174,311 | |||
Asset retirement obligations settled |
2,024 |
4,921 |
3,107 | |||
Payout |
89,654 |
159,118 |
225,430 | |||
Corrib drilling and development |
N/A |
(12,493) |
(12,955) | |||
Payout (excluding Corrib) |
N/A |
146,625 |
212,475 |
(1) |
DRIP Refers to Vermilion's dividend reinvestment and Premium DividendTM plans. |
As at | ||||
Mar 31, |
Dec 31, |
Mar 31, | ||
('000s of shares) |
2016 |
2015 |
2015 | |
Shares outstanding |
113,451 |
111,991 |
107,718 | |
Potential shares issuable pursuant to the VIP |
3,040 |
3,033 |
3,043 | |
Diluted shares outstanding |
116,491 |
115,024 |
110,761 |
CONSOLIDATED BALANCE SHEETS |
||||||
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED) |
||||||
March 31, |
December 31, | |||||
Note |
2016 |
2015 | ||||
ASSETS |
||||||
Current |
||||||
Cash and cash equivalents |
63,246 |
41,676 | ||||
Accounts receivable |
127,531 |
160,499 | ||||
Crude oil inventory |
17,340 |
13,079 | ||||
Derivative instruments |
62,381 |
55,214 | ||||
Prepaid expenses |
13,652 |
14,310 | ||||
284,150 |
284,778 | |||||
Derivative instruments |
15,015 |
13,128 | ||||
Deferred taxes |
6 |
99,174 |
135,753 | |||
Exploration and evaluation assets |
3 |
304,033 |
308,192 | |||
Capital assets |
2 |
3,369,968 |
3,467,369 | |||
4,072,340 |
4,209,220 | |||||
LIABILITIES |
||||||
Current |
||||||
Accounts payable and accrued liabilities |
189,811 |
248,747 | ||||
Current portion of long-term debt |
5 |
- |
224,901 | |||
Dividends payable |
7 |
24,392 |
24,077 | |||
Income taxes payable |
7,022 |
6,006 | ||||
221,225 |
503,731 | |||||
Long-term debt |
5 |
1,429,988 |
1,162,998 | |||
Finance lease obligation |
23,028 |
23,565 | ||||
Asset retirement obligations |
4 |
318,981 |
305,613 | |||
Deferred taxes |
337,657 |
354,654 | ||||
2,330,879 |
2,350,561 | |||||
SHAREHOLDERS' EQUITY |
||||||
Shareholders' capital |
7 |
2,233,207 |
2,181,089 | |||
Contributed surplus |
124,655 |
107,946 | ||||
Accumulated other comprehensive income |
86,317 |
113,647 | ||||
Deficit |
(702,718) |
(544,023) | ||||
1,741,461 |
1,858,659 | |||||
4,072,340 |
4,209,220 |
CONSOLIDATED STATEMENTS OF NET (LOSS) EARNINGS AND COMPREHENSIVE LOSS | ||||||
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED) | ||||||
Three Months Ended | ||||||
March 31, |
March 31, | |||||
Note |
2016 |
2015 | ||||
REVENUE |
||||||
Petroleum and natural gas sales |
177,385 |
195,885 | ||||
Royalties |
(13,961) |
(16,424) | ||||
Petroleum and natural gas revenue |
163,424 |
179,461 | ||||
EXPENSES |
||||||
Operating |
55,628 |
43,851 | ||||
Transportation |
10,390 |
9,540 | ||||
Equity based compensation |
20,837 |
19,040 | ||||
(Gain) loss on derivative instruments |
(37,477) |
13,713 | ||||
Interest expense |
14,750 |
13,298 | ||||
General and administration |
13,577 |
13,560 | ||||
Foreign exchange (gain) loss |
(918) |
1,539 | ||||
Other income |
(18) |
(31,736) | ||||
Accretion |
4 |
6,109 |
5,675 | |||
Depletion and depreciation |
2, 3 |
125,798 |
90,957 | |||
Impairment |
2 |
14,762 |
- | |||
223,438 |
179,437 | |||||
(LOSS) EARNINGS BEFORE INCOME TAXES |
(60,014) |
24 | ||||
INCOME TAXES |
||||||
Deferred |
6 |
22,546 |
(21,228) | |||
Current |
3,288 |
19,977 | ||||
25,834 |
(1,251) | |||||
NET (LOSS) EARNINGS |
(85,848) |
1,275 | ||||
OTHER COMPREHENSIVE LOSS |
||||||
Currency translation adjustments |
(27,330) |
(40,134) | ||||
COMPREHENSIVE LOSS |
(113,178) |
(38,859) | ||||
NET (LOSS) EARNINGS PER SHARE |
||||||
Basic |
(0.76) |
0.01 | ||||
Diluted |
(0.76) |
0.01 | ||||
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s) |
||||||
Basic |
112,725 |
107,513 | ||||
Diluted |
112,725 |
109,305 |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|||||||
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED) |
|||||||
Three Months Ended | |||||||
March 31, |
March 31, | ||||||
Note |
2016 |
2015 | |||||
OPERATING |
|||||||
Net (loss) earnings |
(85,848) |
1,275 | |||||
Adjustments: |
|||||||
Accretion |
4 |
6,109 |
5,675 | ||||
Depletion and depreciation |
2, 3 |
125,798 |
90,957 | ||||
Impairment |
2 |
14,762 |
- | ||||
Unrealized (gain) loss on derivative instruments |
(9,054) |
19,970 | |||||
Equity based compensation |
20,837 |
19,040 | |||||
Unrealized foreign exchange (gain) loss |
(1,570) |
4,845 | |||||
Unrealized other expense |
87 |
261 | |||||
Deferred taxes |
6 |
22,546 |
(21,228) | ||||
Asset retirement obligations settled |
4 |
(2,024) |
(3,107) | ||||
Changes in non-cash operating working capital |
(17,760) |
(95,041) | |||||
Cash flows from operating activities |
73,883 |
22,647 | |||||
INVESTING |
|||||||
Drilling and development |
2 |
(62,773) |
(174,311) | ||||
Property acquisitions |
2 |
(870) |
(35) | ||||
Changes in non-cash investing working capital |
(4,087) |
12,143 | |||||
Cash flows used in investing activities |
(67,730) |
(162,203) | |||||
FINANCING |
|||||||
Increase in long-term debt |
269,560 |
154,914 | |||||
Repayment of senior unsecured notes |
5 |
(225,000) |
- | ||||
Decrease in finance lease obligation |
(895) |
- | |||||
Cash dividends |
(24,542) |
(47,923) | |||||
Cash flows from financing activities |
19,123 |
106,991 | |||||
Foreign exchange (loss) gain on cash held in foreign currencies |
(3,706) |
352 | |||||
Net change in cash and cash equivalents |
21,570 |
(32,213) | |||||
Cash and cash equivalents, beginning of period |
41,676 |
120,405 | |||||
Cash and cash equivalents, end of period |
63,246 |
88,192 | |||||
Supplementary information for operating activities - cash payments |
|||||||
Interest paid |
21,311 |
18,245 | |||||
Income taxes paid |
2,390 |
70,513 |
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY | |||||||||
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED) | |||||||||
Three Months Ended | |||||||||
March 31, |
March 31, | ||||||||
Note |
2016 |
2015 | |||||||
SHAREHOLDERS' CAPITAL |
|||||||||
Balance, beginning of period |
2,181,089 |
1,959,021 | |||||||
Equity based compensation |
4,128 |
532 | |||||||
Shares issued for the DRIP (1) |
47,990 |
21,378 | |||||||
Balance, end of period |
7 |
2,233,207 |
1,980,931 | ||||||
CONTRIBUTED SURPLUS |
|||||||||
Balance, beginning of period |
107,946 |
92,188 | |||||||
Equity based compensation |
16,709 |
18,508 | |||||||
Balance, end of period |
124,655 |
110,696 | |||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME |
|||||||||
Balance, beginning of period |
113,647 |
5,722 | |||||||
Currency translation adjustments |
(27,330) |
(40,134) | |||||||
Balance, end of period |
86,317 |
(34,412) | |||||||
DEFICIT |
|||||||||
Balance, beginning of period |
(544,023) |
(35,585) | |||||||
Net (loss) earnings |
(85,848) |
1,275 | |||||||
Dividends declared |
7 |
(72,847) |
(69,390) | ||||||
Balance, end of period |
(702,718) |
(103,700) | |||||||
TOTAL SHAREHOLDERS' EQUITY |
1,741,461 |
1,953,515 |
(1) |
DRIP Refers to Vermilion's dividend reinvestment and Premium DividendTM plans. |
NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED MARCH 31, 2016 AND 2015
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)
1. BASIS OF PRESENTATION
Vermilion Energy Inc. (the "Company" or "Vermilion") is a corporation governed by the laws of the Province of Alberta and is actively engaged in the business of crude oil and natural gas exploration, development, acquisition and production.
These condensed consolidated interim financial statements are in compliance with IAS 34, "Interim financial reporting" and have been prepared using the same accounting policies and methods of computation as Vermilion's consolidated financial statements for the year ended December 31, 2015.
These condensed consolidated interim financial statements should be read in conjunction with Vermilion's consolidated financial statements for the year ended December 31, 2015, which are contained within Vermilion's Annual Report for the year ended December 31, 2015 and are available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on May 5, 2016.
2. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
($M) |
Capital Assets | |||
Balance at December 31, 2015 |
3,467,369 | |||
Additions |
62,773 | |||
Property acquisitions |
870 | |||
Changes in estimate for asset retirement obligations |
13,312 | |||
Depletion and depreciation |
(124,663) | |||
Recognition of finance lease asset |
708 | |||
Impairment |
(14,762) | |||
Foreign exchange |
(35,639) | |||
Balance at March 31, 2016 |
3,369,968 |
Impairment
On a quarterly basis, Vermilion performs an assessment as to whether any cash generating units ("CGUs") have indicators of impairment. When indicators of impairment are identified, Vermilion assesses the recoverable amount of the applicable CGU based on the higher of the estimated fair value less costs to sell and value in use as at the reporting date. The estimated recoverable amount takes into account commodity price forecasts, expected production, estimated costs and timing of development, and undeveloped land values.
As a result of declines in the European natural gas price forecast, which decreased expected cash flows, Vermilion recorded a non-cash impairment charge of $14.8 million in the Ireland segment for the three months ended March 31, 2016. The recoverable amount of the CGU was determined using a value in use approach based on forecasted reserves and expected cash flows and an after-tax discount rate of 9%.
The determination of impairment is sensitive to changes in key judgments, including reserve revisions, changes in forward commodity prices and exchange rates, and changes in costs and timing of development. Changes in these key judgments would impact the recoverable amount of CGUs, therefore resulting in additional impairment charges or recoveries. For the three months ended March 31, 2016, a one percent increase in the assumed discount rate on expected cash flows of the Ireland CGU would result in an additional impairment of $33.7 million, and a five percent decrease in forward commodity prices would result in an additional impairment of $50.1 million.
The following table outlines the forward commodity price estimates that were used in the calculation of the recoverable amount:
Forward Commodity Price Assumptions (1) | |||||||||||
2016 |
2017 |
2018 |
2019 |
2020 |
2021 |
2022 |
2023 |
2024 |
2025 (2) | ||
NBP (EUR/mmbtu) |
4.55 |
5.39 |
5.95 |
6.47 |
6.68 |
6.81 |
7.03 |
7.10 |
7.18 |
7.37 |
(1) |
Source: Average of GLJ Petroleum Consultants and Sproule price forecasts, effective April 1, 2016. |
(2) |
Escalated at 1.75% per year thereafter. |
3. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and evaluation assets:
($M) |
Exploration and Evaluation Assets | ||
Balance at December 31, 2015 |
308,192 | ||
Changes in estimate for asset retirement obligations |
8 | ||
Depreciation |
(3,343) | ||
Foreign exchange |
(824) | ||
Balance at March 31, 2016 |
304,033 |
4. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset retirement obligations:
($M) |
Asset Retirement Obligations | ||||||
Balance at December 31, 2015 |
305,613 | ||||||
Additional obligations recognized |
176 | ||||||
Obligations settled |
(2,024) | ||||||
Accretion |
6,109 | ||||||
Changes in discount rates |
13,144 | ||||||
Foreign exchange |
(4,037) | ||||||
Balance at March 31, 2016 |
318,981 |
5. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
As at | ||||||||
($M) |
Mar 31, 2016 |
Dec 31, 2015 | ||||||
Revolving credit facility |
1,429,988 |
1,162,998 | ||||||
Senior unsecured notes (1) |
- |
224,901 | ||||||
Long-term debt |
1,429,988 |
1,387,899 |
(1) |
The senior unsecured notes, which had a principal balance of $225.0 million, matured and were repaid on February 10, 2016 and were included in the current portion of long-term debt as at December 31, 2015. |
Revolving Credit Facility
At March 31, 2016, Vermilion had in place a bank revolving credit facility totalling $2 billion, of which approximately $1.43 billion was drawn. The facility, which matures on May 31, 2019, is fully revolving up to the date of maturity.
The facility is extendable from time to time, but not more than once per year, for a period not longer than four years, at the option of the lenders and upon notice from Vermilion. If no extension is granted by the lenders, the amounts owing pursuant to the facility are due at the maturity date. This facility bears interest at a rate applicable to demand loans plus applicable margins. For the three months ended March 31, 2016, the interest rate on the revolving credit facility was approximately 3.3% (2015 – 3.1%).
The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $24.7 million as at March 31, 2016 (December 31, 2015 - $25.2 million).
The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. As at March 31, 2016, under the terms of the facility, Vermilion must maintain:
As at March 31, 2016, Vermilion was in compliance with all financial covenants.
6. DEFERRED INCOME TAXES
For the three months ended March 31, 2016, Vermilion de-recognized an additional $40.3 million (year ended December 31, 2015 - $51.7 million) of deferred tax assets, relating to certain non-capital losses for which there is uncertainty as to the Company's ability to fully utilize such losses when applying forecasted commodity prices in effect as at March 31, 2016.
7. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders' capital:
Shareholders' Capital |
Number of Shares ('000s) |
Amount ($M) | ||||
Balance as at December 31, 2015 |
111,991 |
2,181,089 | ||||
Shares issued for the DRIP |
1,354 |
47,990 | ||||
Shares issued for equity based compensation |
106 |
4,128 | ||||
Balance as at March 31, 2016 |
113,451 |
2,233,207 |
Dividends declared to shareholders for the three months ended March 31, 2016 were $72.8 million (2015 - $69.4 million).
Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue, Vermilion declared dividends totalling $24.5 million or $0.215 per share.
8. SEGMENTED INFORMATION
Vermilion's operating activities in each business unit relate solely to the exploration, development and production of petroleum and natural gas. Vermilion has a Corporate head office located in Calgary, Alberta. Costs incurred in the Corporate segment relate to Vermilion's global hedging program and expenses incurred in financing and managing the Company's operating business units.
Vermilion's chief operating decision maker reviews the financial performance of the Company by assessing the fund flows from operations of each business unit individually. Fund flows from operations provides a measure of each business unit's ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, fund asset retirement obligations, and make capital investments.
Three Months Ended March 31, 2016 | |||||||||
($M) |
Canada |
France |
Netherlands |
Germany |
Ireland |
Australia |
United States |
Corporate |
Total |
Total assets |
1,584,947 |
833,145 |
195,413 |
159,522 |
838,240 |
240,352 |
44,585 |
176,136 |
4,072,340 |
Drilling and development |
29,771 |
13,463 |
2,996 |
539 |
3,076 |
7,827 |
5,101 |
- |
62,773 |
Oil and gas sales to external |
|||||||||
customers |
56,110 |
48,125 |
27,286 |
7,692 |
17,004 |
19,935 |
1,233 |
- |
177,385 |
Royalties |
(5,498) |
(6,766) |
(460) |
(867) |
- |
- |
(370) |
- |
(13,961) |
Revenue from external customers |
50,612 |
41,359 |
26,826 |
6,825 |
17,004 |
19,935 |
863 |
- |
163,424 |
Transportation |
(4,151) |
(3,713) |
- |
(887) |
(1,639) |
- |
- |
- |
(10,390) |
Operating |
(21,343) |
(14,320) |
(5,976) |
(2,593) |
(3,626) |
(7,491) |
(279) |
- |
(55,628) |
General and administration |
(2,476) |
(4,676) |
(773) |
(2,428) |
(1,188) |
(1,325) |
(1,132) |
421 |
(13,577) |
PRRT |
- |
- |
- |
- |
- |
(128) |
- |
- |
(128) |
Corporate income taxes |
- |
(34) |
(2,200) |
- |
- |
(777) |
- |
(149) |
(3,160) |
Interest expense |
- |
- |
- |
- |
- |
- |
- |
(14,750) |
(14,750) |
Realized gain on derivative |
|||||||||
instruments |
- |
- |
- |
- |
- |
- |
- |
28,423 |
28,423 |
Realized foreign exchange loss |
- |
- |
- |
- |
- |
- |
- |
(652) |
(652) |
Realized other income |
- |
- |
- |
- |
- |
- |
- |
105 |
105 |
Fund flows from operations |
22,642 |
18,616 |
17,877 |
917 |
10,551 |
10,214 |
(548) |
13,398 |
93,667 |
Three Months Ended March 31, 2015 | |||||||||
($M) |
Canada |
France |
Netherlands |
Germany |
Ireland |
Australia |
United States |
Corporate |
Total |
Total assets |
1,968,024 |
905,476 |
202,428 |
161,455 |
817,638 |
256,003 |
15,317 |
136,057 |
4,462,398 |
Drilling and development |
114,849 |
34,114 |
4,333 |
968 |
12,955 |
6,455 |
637 |
- |
174,311 |
Oil and gas sales to external |
|||||||||
customers |
77,884 |
59,832 |
26,818 |
11,395 |
- |
19,284 |
672 |
- |
195,885 |
Royalties |
(8,592) |
(5,102) |
(926) |
(1,598) |
- |
- |
(206) |
- |
(16,424) |
Revenue from external customers |
69,292 |
54,730 |
25,892 |
9,797 |
- |
19,284 |
466 |
- |
179,461 |
Transportation |
(3,942) |
(3,011) |
- |
(894) |
(1,693) |
- |
- |
- |
(9,540) |
Operating |
(19,099) |
(10,826) |
(5,826) |
(1,999) |
- |
(5,886) |
(215) |
- |
(43,851) |
General and administration |
(4,015) |
(5,111) |
(737) |
(1,608) |
(512) |
(1,454) |
(1,080) |
957 |
(13,560) |
PRRT |
- |
- |
- |
- |
- |
(2,354) |
- |
- |
(2,354) |
Corporate income taxes |
- |
(14,281) |
(2,388) |
- |
- |
(577) |
- |
(377) |
(17,623) |
Interest expense |
- |
- |
- |
- |
- |
- |
- |
(13,298) |
(13,298) |
Realized gain on derivative |
|||||||||
instruments |
- |
- |
- |
- |
- |
- |
- |
6,257 |
6,257 |
Realized foreign exchange gain |
- |
- |
- |
- |
- |
- |
- |
3,306 |
3,306 |
Realized other income |
- |
31,775 |
- |
- |
- |
- |
- |
222 |
31,997 |
Fund flows from operations |
42,236 |
53,276 |
16,941 |
5,296 |
(2,205) |
9,013 |
(829) |
(2,933) |
120,795 |
Reconciliation of fund flows from operations to net (loss) earnings
Three Months Ended | |||||
Mar 31, |
Mar 31, | ||||
($M) |
2016 |
2015 | |||
Fund flows from operations |
93,667 |
120,795 | |||
Equity based compensation |
(20,837) |
(19,040) | |||
Unrealized gain (loss) on derivative instruments |
9,054 |
(19,970) | |||
Unrealized foreign exchange gain (loss) |
1,570 |
(4,845) | |||
Unrealized other expense |
(87) |
(261) | |||
Accretion |
(6,109) |
(5,675) | |||
Depletion and depreciation |
(125,798) |
(90,957) | |||
Deferred taxes |
(22,546) |
21,228 | |||
Impairment |
(14,762) |
- | |||
Net (loss) earnings |
(85,848) |
1,275 |
9. FINANCIAL INSTRUMENTS
Determination of Fair Values
The level in the fair value hierarchy into which the fair value measurements are categorized is determined on the basis of the lowest level input that is significant to the fair value measurement. Transfers between levels on the fair value hierarchy are deemed to have occurred at the end of the reporting period.
Level 1 – Fair value measurement is determined by reference to unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 – Fair value measurement is determined based on inputs other than unadjusted quoted prices that are observable, either directly or indirectly.
Level 3 – Fair value measurement is based on inputs for the asset or liability that are not based on observable market data.
Cash and cash equivalents are classified as Level 1 measurements. Cash and cash equivalents, receivables, and payables approximate their value due to the short-term nature of those instruments.
Derivative assets, derivative liabilities, and the fair value of long-term debt outstanding on the revolving credit facility are classified as Level 2 measurements. The fair value for derivative assets and derivative liabilities are determined using pricing models incorporating future prices that are based on assumptions which are supported by prices from observable market transactions and are adjusted for credit risk. The fair value of long-term debt on the revolving credit facility approximates carrying value due to the use of short-term borrowing instruments at market rates of interest.
Vermilion does not have any financial instruments classified as Level 3 measurements.
Nature and Extent of Risks Arising from Financial Instruments
Market risk:
Vermilion's financial instruments are exposed to currency risk related to changes in foreign currency denominated financial instruments and commodity price risk related to outstanding derivatives. The following table summarizes the impact on comprehensive income before tax for the three months ended March 31, 2016 given changes in the relevant risk variables that Vermilion considers reasonably possible at the balance sheet date. The impact on comprehensive income before tax associated with changes in these risk variables for assets and liabilities that are not considered financial instruments are excluded from this analysis. This analysis does not attempt to reflect any interdependencies between the relevant risk variables.
Before tax effect on comprehensive | ||
income - increase (decrease) | ||
Risk ($M) |
Description of change in risk variable |
March 31, 2016 |
Currency risk - Euro to Canadian |
5% increase in strength of the Canadian dollar against the Euro |
(3,535) |
5% decrease in strength of the Canadian dollar against the Euro |
3,535 | |
Currency risk - US $ to Canadian |
5% increase in strength of the Canadian dollar against the US $ |
2,323 |
5% decrease in strength of the Canadian dollar against the US $ |
(2,323) | |
Commodity price risk |
US $5.00/bbl increase in crude oil price used to determine the fair value of derivatives |
(3,330) |
US $5.00/bbl decrease in crude oil price used to determine the fair value of derivatives |
3,330 | |
€ 0.5/GJ increase in European natural gas price used to determine the fair value of derivatives |
(23,184) | |
€ 0.5/GJ decrease in European natural gas price used to determine the fair value of derivatives |
23,184 | |
Interest rate risk |
1% increase in average Canadian prime interest rate |
(2,329) |
1% decrease in average Canadian prime interest rate |
2,329 |
SOURCE Vermilion Energy Inc.
CALGARY, April 11, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on May 16, 2016 to all shareholders of record on April 22, 2016. The ex-dividend date for this payment is April 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, March 11, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on April 15, 2016 to all shareholders of record on March 22, 2016. The ex-dividend date for this payment is March 18, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Feb. 29, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2015 year-end reserves and resource information. The estimates of reserves and resources and other oil and gas information contained in this news release has been estimated by GLJ Petroleum Consultants Ltd. ("GLJ") and prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGEH"). For additional information about Vermilion, including Vermilion's statement of reserves data and other information in Form 51-101F1, report on reserves data by independent qualified reserves evaluator or auditor in Form 51-101F2 and report of management and directors on oil and gas disclosure in Form 51-101F3, please review the Company's Annual Information Form for the year ended December 31, 2015, to be filed on March 4, 2016 and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov.
HIGHLIGHTS
(1) | As evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 8, 2016 with an effective date of December 31, 2015. |
(2) | F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital costs for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period. |
(3) | Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ 2015 Resource Assessment"). The associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 83%, 82% and 81%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
DISCLAIMER
Certain statements included or incorporated by reference in this news release may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this news release may include, but are not limited to:
Such forward-looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things:
Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding the Company's financial strength and business objectives and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward looking statements or information. These risks and uncertainties include but are not limited to:
The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
RESERVES, FUTURE NET REVENUE AND OTHER OIL AND GAS INFORMATION
The following is a summary of the oil and natural gas reserves and the value of future net revenue of Vermilion as evaluated by GLJ, independent petroleum engineering consultants in Calgary in a report dated February 8, 2016 with an effective date of December 31, 2015 (the "GLJ 2015 Reserves Evaluation"). The GLJ 2015 Reserves Evaluation was prepared in accordance with National Instrument 51-101 and COGEH.
Reserves and other oil and gas information in this news release is effective December 31, 2015 unless otherwise stated.
All evaluations of future net production revenue set forth in the tables below are stated after overriding and lessor royalties, Crown royalties, freehold royalties, mineral taxes, direct lifting costs, normal allocated overhead and future capital investments, including abandonment and reclamation obligations. Future net production revenues estimated by the GLJ 2015 Reserves Evaluation do not represent the fair market value of the reserves. Other assumptions relating to the costs, prices for future production and other matters are included in the GLJ 2015 Reserve Evaluation. There is no assurance that the future price and cost assumptions used in the GLJ 2015 Reserves Evaluation will prove accurate and variances could be material.
Reserves for Australia, Canada, France, Germany, Ireland, the Netherlands and the United States are established using deterministic methodology. Total proved reserves are established at the 90 percent probability (P90) level. There is a 90 percent probability that the actual reserves recovered will be equal to or greater than the P90 reserves. Total proved plus probable reserves are established at the 50 percent probability (P50) level. There is a 50 percent probability that the actual reserves recovered will be equal to or greater than the P50 reserves.
Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development.
With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
Pricing used in the forecast price estimates is set forth in the table below and referenced in the notes to subsequent tables.
Table 1: Forecast Prices used in Estimates (1)
Light Crude Oil and | Natural Gas | Natural Gas | Natural Gas | Inflation | Exchange | Exchange | ||||||||||||||
& Medium Crude Oil | Crude Oil | Canada | Europe | Liquids | Rate | Rate | Rate | |||||||||||||
WTI | Edmonton | Cromer | Brent Blend | National Balancing | ||||||||||||||||
Cushing | Par Price | Medium | FOB | AECO | Point | FOB | ||||||||||||||
Oklahoma | 40˚ API | 29.3˚ API | North Sea | Gas Price | (UK) | Field Gate | Percent | |||||||||||||
Year | ($US/bbl) | ($Cdn/bbl) | ($Cdn/bbl) | ($US/bbl) | ($Cdn/MMBtu) | ($US/MMBtu) | ($Cdn/bbl) | Per Year | ($US/$Cdn) | ($CdnEUR) | ||||||||||
2015 | 48.82 | 57.23 | 51.91 | 53.75 | 2.70 | 6.55 | 34.59 | 1.1 | 0.783 | 1.419 | ||||||||||
Forecast | ||||||||||||||||||||
2016 | 44.00 | 55.86 | 50.80 | 45.00 | 2.76 | 5.55 | 30.27 | 2.0 | 0.725 | 1.517 | ||||||||||
2017 | 52.00 | 64.00 | 59.52 | 54.00 | 3.27 | 5.68 | 35.76 | 2.0 | 0.750 | 1.467 | ||||||||||
2018 | 58.00 | 68.39 | 63.60 | 61.00 | 3.45 | 6.10 | 39.04 | 2.0 | 0.775 | 1.419 | ||||||||||
2019 | 64.00 | 73.75 | 68.59 | 67.00 | 3.63 | 6.70 | 42.96 | 2.0 | 0.800 | 1.375 | ||||||||||
2020 | 70.00 | 78.79 | 73.27 | 73.00 | 3.81 | 7.30 | 45.85 | 2.0 | 0.825 | 1.333 | ||||||||||
2021 | 75.00 | 82.35 | 76.59 | 78.00 | 3.90 | 7.80 | 47.86 | 2.0 | 0.850 | 1.294 | ||||||||||
2022 | 80.00 | 88.24 | 82.06 | 83.00 | 4.10 | 8.30 | 51.23 | 2.0 | 0.850 | 1.294 | ||||||||||
2023 | 85.00 | 94.12 | 87.53 | 88.00 | 4.30 | 8.80 | 54.59 | 2.0 | 0.850 | 1.294 | ||||||||||
2024 | 87.88 | 96.48 | 89.73 | 91.39 | 4.50 | 9.14 | 57.18 | 2.0 | 0.850 | 1.294 | ||||||||||
Thereafter | 2.0% | 2.0% | 2.0% | 2.0% | 2.0% | 2.0% | 2.0% | 2.0% | 0.850 | 1.294 |
Note: | |
(1) | The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
All forecast prices in the tables above are provided by GLJ. For 2015, the price of Vermilion's natural gas in the Netherlands is based on the TTF day-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees. GasTerra, a state owned entity purchases all natural gas produced by Vermilion in the Netherlands. The price of Vermilion's natural gas in Germany is based on the TTF month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees. The benchmark price for Australia and France crude oil is Dated Brent. The benchmark price for Canadian crude oil is Edmonton Par and Canadian natural gas is priced against AECO. For the year ended December 31, 2015, the average realized sales prices before hedging were $70.22 per bbl (Australia), $7.79 per Mcf (Netherlands), $7.18 per Mcf (Germany), $63.31 per bbl (France) for Brent-based crude oil, $49.10 per bbl (United States) for WTI, $49.73 per bbl for Canadian-based crude oil and NGLs and $2.78 per Mcf for Canadian natural gas.
The following table summarizes the capital expenditures made by Vermilion on oil and natural gas properties for the year ended December 31, 2015:
Table 2: Capital Costs Incurred
Acquisition Costs | ||||||||||
Proved | Unproved | Exploration | Development | Total | ||||||
(M$) | Properties | Properties | Costs | Costs | Costs | |||||
Australia | - | - | - | 61,741 | 61,741 | |||||
Canada | 14,650 | - | - | 201,508 | 216,158 | |||||
France | 317 | - | - | 92,265 | 92,582 | |||||
Germany | - | - | - | 5,363 | 5,363 | |||||
Hungary | - | - | 1,166 | - | 1,166 | |||||
Ireland | - | - | - | 66,409 | 66,409 | |||||
Netherlands | - | - | - | 47,325 | 47,325 | |||||
United States | 12,764 | - | - | 12,250 | 25,014 | |||||
Total | 27,731 | - | 1,166 | 486,861 | 515,758 |
The following table sets forth the reserve life index based on total proved and proved plus probable reserve and fourth quarter 2015 production of 61,058 boe/d.
Table 3: Reserve Life Index
Commodity | Production | Reserve Life Index (years) | |||||||
Fourth Quarter 2015 | Total Proved | Proved Plus Probable | |||||||
Oil and natural gas liquids (bbl/d) | 34,043 | 7.6 | 12.2 | ||||||
Natural gas (mmcf/d) | 162.09 | 6.7 | 11.1 | ||||||
Oil Equivalent (boe/d) | 61,058 | 7.2 | 11.7 |
The following tables provide reserves data and a breakdown of future net revenue by component and production group using forecast prices and costs. For Canada, the tables following include Alberta gas cost allowance.
The following tables may not total due to rounding.
Table 4: Oil and Gas Reserves - Based on Forecast Prices and Costs (1)
Light Crude Oil & Medium Crude Oil | Heavy Oil | Tight Oil | Conventional Natural Gas | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | |||||||||
Proved Developed Producing (3) (5) (6) | ||||||||||||||||
Australia | 11,465 | 11,465 | - | - | - | - | - | - | ||||||||
Canada | 13,528 | 11,785 | 9 | 9 | 10 | 8 | 98,840 | 89,253 | ||||||||
France | 34,866 | 32,097 | - | - | - | - | 7,835 | 7,309 | ||||||||
Germany | - | - | - | - | - | - | 20,876 | 18,148 | ||||||||
Ireland | - | - | - | - | - | - | 94,976 | 94,976 | ||||||||
Netherlands | - | - | - | - | - | - | 29,961 | 27,236 | ||||||||
United States | 384 | 314 | - | - | - | - | 372 | 304 | ||||||||
Total Proved Developed Producing | 60,243 | 55,661 | 9 | 9 | 10 | 8 | 252,860 | 237,226 | ||||||||
Shale Gas | Coal Bed Methane | Natural Gas Liquids | BOE | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross | Net | |||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | |||||||||
Proved Developed Producing (3) (5) (6) | ||||||||||||||||
Australia | - | - | - | - | - | - | 11,465 | 11,465 | ||||||||
Canada | 1,942 | 1,832 | 3,100 | 2,883 | 7,052 | 5,383 | 37,913 | 32,846 | ||||||||
France | - | - | - | - | - | - | 36,172 | 33,315 | ||||||||
Germany | - | - | - | - | - | - | 3,479 | 3,025 | ||||||||
Ireland | - | - | - | - | - | - | 15,829 | 15,829 | ||||||||
Netherlands | - | - | - | - | 66 | 60 | 5,060 | 4,599 | ||||||||
United States | - | - | - | - | 59 | 49 | 505 | 414 | ||||||||
1,942 | 1,832 | 3,100 | 2,883 | 7,177 | 5,492 | 110,423 | 101,493 | |||||||||
Light Crude Oil & Medium Crude Oil | Heavy Oil | Tight Oil | Conventional Natural Gas | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | |||||||||
Proved Developed Non-Producing | ||||||||||||||||
Australia | - | - | - | - | - | - | - | - | ||||||||
Canada | 1,032 | 940 | - | - | - | - | 17,090 | 14,633 | ||||||||
France | 1,914 | 1,754 | - | - | - | - | - | - | ||||||||
Germany | - | - | - | - | - | - | 8,263 | 7,157 | ||||||||
Ireland | - | - | - | - | - | - | 10,845 | 10,845 | ||||||||
Netherlands | - | - | - | - | - | - | 18,238 | 18,238 | ||||||||
United States | 313 | 254 | - | - | - | - | 318 | 258 | ||||||||
Total Proved Developed Non-Producing | 3,259 | 2,948 | - | - | - | - | 54,754 | 51,131 | ||||||||
Shale Gas | Coal Bed Methane | Natural Gas Liquids | BOE | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross | Net | |||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | |||||||||
Proved Developed Non-Producing | ||||||||||||||||
Australia | - | - | - | - | - | - | - | - | ||||||||
Canada | - | - | 1,743 | 1,643 | 692 | 490 | 4,863 | 4,143 | ||||||||
France | - | - | - | - | - | - | 1,914 | 1,754 | ||||||||
Germany | - | - | - | - | - | - | 1,377 | 1,193 | ||||||||
Ireland | - | - | - | - | - | - | 1,808 | 1,808 | ||||||||
Netherlands | - | - | - | - | 22 | 22 | 3,062 | 3,062 | ||||||||
United States | - | - | - | - | 51 | 41 | 417 | 338 | ||||||||
Total Proved Developed Non-Producing | - | - | 1,743 | 1,643 | 765 | 553 | 13,441 | 12,298 | ||||||||
Light Crude Oil & Medium Crude Oil | Heavy Oil | Tight Oil | Conventional Natural Gas | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | |||||||||
Proved Undeveloped (3) (8) | ||||||||||||||||
Australia | 2,300 | 2,300 | - | - | - | - | - | - | ||||||||
Canada | 8,411 | 7,357 | - | - | - | - | 74,181 | 68,479 | ||||||||
France | 3,941 | 3,693 | - | - | - | - | - | - | ||||||||
Germany | - | - | - | - | - | - | 2,361 | 1,684 | ||||||||
Ireland | - | - | - | - | - | - | - | - | ||||||||
Netherlands | - | - | - | - | - | - | - | - | ||||||||
United States | 1,337 | 1,087 | - | - | - | - | 1,480 | 1,204 | ||||||||
Total Proved Undeveloped | 15,989 | 14,437 | - | - | - | - | 78,022 | 71,367 | ||||||||
Shale Gas | Coal Bed Methane | Natural Gas Liquids | BOE | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross | Net | |||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | |||||||||
Proved Undeveloped | ||||||||||||||||
Australia | - | - | - | - | - | - | 2,300 | 2,300 | ||||||||
Canada | - | - | 3,367 | 3,114 | 7,051 | 5,955 | 28,387 | 25,244 | ||||||||
France | - | - | - | - | - | - | 3,941 | 3,693 | ||||||||
Germany | - | - | - | - | - | - | 394 | 281 | ||||||||
Ireland | - | - | - | - | - | - | - | - | ||||||||
Netherlands | - | - | - | - | - | - | - | - | ||||||||
United States | - | - | - | - | 236 | 192 | 1,820 | 1,480 | ||||||||
Total Proved Undeveloped | - | - | 3,367 | 3,114 | 7,287 | 6,147 | 36,842 | 32,998 | ||||||||
Light Crude Oil & Medium Crude Oil | Heavy Oil | Tight Oil | Conventional Natural Gas | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | |||||||||
Proved (3) | ||||||||||||||||
Australia | 13,765 | 13,765 | - | - | - | - | - | - | ||||||||
Canada | 22,971 | 20,082 | 9 | 9 | 10 | 8 | 190,111 | 172,365 | ||||||||
France | 40,721 | 37,544 | - | - | - | - | 7,835 | 7,309 | ||||||||
Germany | - | - | - | - | - | - | 31,500 | 26,989 | ||||||||
Ireland | - | - | - | - | - | - | 105,821 | 105,821 | ||||||||
Netherlands | - | - | - | - | - | - | 48,199 | 45,474 | ||||||||
United States | 2,034 | 1,655 | - | - | - | - | 2,170 | 1,766 | ||||||||
Total Proved | 79,491 | 73,046 | 9 | 9 | 10 | 8 | 385,637 | 359,724 | ||||||||
Shale Gas | Coal Bed Methane | Natural Gas Liquids | BOE | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross | Net | |||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | |||||||||
Proved | ||||||||||||||||
Australia | - | - | - | - | - | - | 13,765 | 13,765 | ||||||||
Canada | 1,942 | 1,832 | 8,210 | 7,640 | 14,795 | 11,828 | 71,163 | 62,233 | ||||||||
France | - | - | - | - | - | - | 42,027 | 38,762 | ||||||||
Germany | - | - | - | - | - | - | 5,250 | 4,499 | ||||||||
Ireland | - | - | - | - | - | - | 17,637 | 17,637 | ||||||||
Netherlands | - | - | - | - | 88 | 82 | 8,122 | 7,661 | ||||||||
United States | - | - | - | - | 346 | 282 | 2,742 | 2,232 | ||||||||
Total Proved | 1,942 | 1,832 | 8,210 | 7,640 | 15,229 | 12,192 | 160,706 | 146,789 | ||||||||
Light Crude Oil & Medium Crude Oil | Heavy Oil | Tight Oil | Conventional Natural Gas | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | |||||||||
Probable (4) | ||||||||||||||||
Australia | 3,700 | 3,700 | - | - | - | - | - | - | ||||||||
Canada | 14,786 | 12,565 | 3 | 3 | 3 | 2 | 132,676 | 120,460 | ||||||||
France | 21,325 | 19,814 | - | - | - | - | 1,559 | 1,505 | ||||||||
Germany | - | - | - | - | - | - | 17,999 | 14,999 | ||||||||
Ireland | - | - | - | - | - | - | 47,405 | 47,405 | ||||||||
Netherlands | - | - | - | - | - | - | 48,688 | 43,700 | ||||||||
United States | 3,818 | 3,131 | - | - | - | - | 4,378 | 3,590 | ||||||||
Total Probable | 43,629 | 39,210 | 3 | 3 | 3 | 2 | 252,705 | 231,659 | ||||||||
Shale Gas | Coal Bed Methane | Natural Gas Liquids | BOE | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross | Net | |||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | |||||||||
Probable | ||||||||||||||||
Australia | - | - | - | - | - | - | 3,700 | 3,700 | ||||||||
Canada | 475 | 447 | 4,917 | 4,628 | 12,751 | 10,144 | 50,554 | 43,637 | ||||||||
France | - | - | - | - | - | - | 21,585 | 20,065 | ||||||||
Germany | - | - | - | - | - | - | 3,000 | 2,500 | ||||||||
Ireland | - | - | - | - | - | - | 7,901 | 7,901 | ||||||||
Netherlands | - | - | - | - | 83 | 66 | 8,198 | 7,349 | ||||||||
United States | - | - | - | - | 698 | 572 | 5,246 | 4,301 | ||||||||
Total Probable | 475 | 447 | 4,917 | 4,628 | 13,532 | 10,782 | 100,184 | 89,453 | ||||||||
Light Crude Oil & Medium Crude Oil | Heavy Oil | Tight Oil | Conventional Natural Gas | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | |||||||||
(Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | |||||||||
Proved Plus Probable (3) (4) | ||||||||||||||||
Australia | 17,465 | 17,465 | - | - | - | - | - | - | ||||||||
Canada | 37,757 | 32,647 | 12 | 12 | 13 | 10 | 322,787 | 292,825 | ||||||||
France | 62,046 | 57,358 | - | - | - | - | 9,394 | 8,814 | ||||||||
Germany | - | - | - | - | - | - | 49,499 | 41,988 | ||||||||
Ireland | - | - | - | - | - | - | 153,226 | 153,226 | ||||||||
Netherlands | - | - | - | - | - | - | 96,887 | 89,174 | ||||||||
United States | 5,852 | 4,786 | - | - | - | - | 6,548 | 5,356 | ||||||||
Total Proved Plus Probable | 123,120 | 112,256 | 12 | 12 | 13 | 10 | 638,342 | 591,383 | ||||||||
Shale Gas | Coal Bed Methane | Natural Gas Liquids | BOE | |||||||||||||
Gross (2) | Net (2) | Gross (2) | Net (2) | Gross (2) | Net (2) | Gross | Net | |||||||||
(MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | |||||||||
Proved Plus Probable (3) (4) | ||||||||||||||||
Australia | - | - | - | - | - | - | 17,465 | 17,465 | ||||||||
Canada | 2,417 | 2,279 | 13,127 | 12,268 | 27,546 | 21,972 | 121,717 | 105,870 | ||||||||
France | - | - | - | - | - | - | 63,612 | 58,827 | ||||||||
Germany | - | - | - | - | - | - | 8,250 | 6,999 | ||||||||
Ireland | - | - | - | - | - | - | 25,538 | 25,538 | ||||||||
Netherlands | - | - | - | - | 171 | 148 | 16,320 | 15,010 | ||||||||
United States | - | - | - | - | 1,044 | 854 | 7,988 | 6,533 | ||||||||
Total Proved Plus Probable | 2,417 | 2,279 | 13,127 | 12,268 | 28,761 | 22,974 | 260,890 | 236,242 |
Notes: | |
(1) | The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) | "Gross Reserves" are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net Reserves" are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in reserves. |
(3) | "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(4) | "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(5) | "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. |
(6) | "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
(7) | "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. |
(8) | "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. |
Table 5: Net Present Values of Future Net Revenue - Based on Forecast Prices and Costs (1)
Before Deducting Future Income Taxes Discounted At | After Deducting Future Income Taxes Discounted At | |||||||||||||||||||
(M$) | 0% | 5% | 10% | 15% | 20% | 0% | 5% | 10% | 15% | 20% | ||||||||||
Proved Developed Producing (2) (4) (5) | ||||||||||||||||||||
Australia | 2,347 | 129,206 | 168,558 | 175,898 | 171,717 | 124,988 | 173,769 | 178,900 | 170,295 | 158,300 | ||||||||||
Canada | 949,037 | 750,567 | 619,559 | 528,638 | 462,575 | 949,037 | 750,567 | 619,559 | 528,638 | 462,575 | ||||||||||
France | 1,798,973 | 1,255,682 | 953,329 | 767,459 | 643,532 | 1,517,541 | 1,074,705 | 821,780 | 664,015 | 557,940 | ||||||||||
Germany | 43,971 | 38,938 | 34,820 | 31,467 | 28,720 | 43,971 | 38,938 | 34,820 | 31,467 | 28,720 | ||||||||||
Ireland | 552,363 | 501,468 | 439,666 | 387,319 | 345,603 | 552,363 | 501,468 | 439,666 | 387,319 | 345,603 | ||||||||||
Netherlands | 83,154 | 94,117 | 99,646 | 102,200 | 103,013 | 64,192 | 75,617 | 81,576 | 84,532 | 85,720 | ||||||||||
United States | 16,290 | 12,359 | 9,959 | 8,387 | 7,290 | 16,290 | 12,359 | 9,959 | 8,387 | 7,290 | ||||||||||
Total Proved Developed Producing | 3,446,135 | 2,782,337 | 2,325,537 | 2,001,368 | 1,762,450 | 3,268,382 | 2,627,423 | 2,186,260 | 1,874,653 | 1,646,148 | ||||||||||
Proved Developed Non-Producing (2) (4) (6) | ||||||||||||||||||||
Australia | - | - | - | - | - | - | - | - | - | - | ||||||||||
Canada | 104,042 | 71,099 | 54,809 | 45,013 | 38,420 | 104,042 | 71,099 | 54,809 | 45,013 | 38,420 | ||||||||||
France | 90,457 | 62,628 | 45,934 | 35,314 | 28,159 | 58,901 | 40,465 | 29,248 | 22,088 | 17,265 | ||||||||||
Germany | 25,871 | 19,029 | 14,433 | 11,275 | 9,044 | 25,871 | 19,029 | 14,433 | 11,275 | 9,044 | ||||||||||
Ireland | 92,735 | 62,194 | 44,189 | 32,997 | 25,688 | 92,735 | 62,194 | 44,189 | 32,997 | 25,688 | ||||||||||
Netherlands | 49,823 | 39,122 | 30,708 | 24,196 | 19,156 | 41,346 | 30,978 | 22,865 | 16,628 | 11,839 | ||||||||||
United States | 9,355 | 5,641 | 3,488 | 2,150 | 1,264 | 9,355 | 5,641 | 3,488 | 2,150 | 1,264 | ||||||||||
Total Proved Developed Non-Producing | 372,283 | 259,713 | 193,561 | 150,945 | 121,731 | 332,250 | 229,406 | 169,032 | 130,151 | 103,520 | ||||||||||
Proved Undeveloped (2) (7) | ||||||||||||||||||||
Australia | 90,351 | 65,761 | 47,675 | 34,243 | 24,141 | 54,095 | 38,796 | 27,698 | 19,530 | 13,425 | ||||||||||
Canada | 489,912 | 322,128 | 216,629 | 147,559 | 100,575 | 394,990 | 268,530 | 185,169 | 128,464 | 88,643 | ||||||||||
France | 195,493 | 141,793 | 105,874 | 81,079 | 63,249 | 126,807 | 88,335 | 62,501 | 44,867 | 32,357 | ||||||||||
Germany | 6,456 | 3,478 | 1,746 | 724 | 117 | 6,456 | 3,478 | 1,746 | 724 | 117 | ||||||||||
Ireland | - | - | - | - | - | - | - | - | - | - | ||||||||||
Netherlands | - | - | - | - | - | - | - | - | - | - | ||||||||||
United States | 33,881 | 15,244 | 5,265 | (415) | (3,816) | 33,881 | 15,244 | 5,265 | (415) | (3,816) | ||||||||||
Total Proved Undeveloped | 816,093 | 548,404 | 377,189 | 263,190 | 184,266 | 616,229 | 414,383 | 282,379 | 193,170 | 130,726 | ||||||||||
Proved (2) | ||||||||||||||||||||
Australia | 92,698 | 194,967 | 216,233 | 210,141 | 195,858 | 179,083 | 212,565 | 206,598 | 189,825 | 171,725 | ||||||||||
Canada | 1,542,991 | 1,143,794 | 890,997 | 721,210 | 601,570 | 1,448,069 | 1,090,196 | 859,537 | 702,115 | 589,638 | ||||||||||
France | 2,084,923 | 1,460,103 | 1,105,137 | 883,852 | 734,940 | 1,703,249 | 1,203,505 | 913,529 | 730,970 | 607,562 | ||||||||||
Germany | 76,298 | 61,445 | 50,999 | 43,466 | 37,881 | 76,298 | 61,445 | 50,999 | 43,466 | 37,881 | ||||||||||
Ireland | 645,098 | 563,662 | 483,855 | 420,316 | 371,291 | 645,098 | 563,662 | 483,855 | 420,316 | 371,291 | ||||||||||
Netherlands | 132,977 | 133,239 | 130,354 | 126,396 | 122,169 | 105,538 | 106,595 | 104,441 | 101,160 | 97,559 | ||||||||||
United States | 59,526 | 33,244 | 18,712 | 10,122 | 4,738 | 59,526 | 33,244 | 18,712 | 10,122 | 4,738 | ||||||||||
Total Proved | 4,634,511 | 3,590,454 | 2,896,287 | 2,415,503 | 2,068,447 | 4,216,861 | 3,271,212 | 2,637,671 | 2,197,974 | 1,880,394 | ||||||||||
Probable (3) | ||||||||||||||||||||
Australia | 233,918 | 195,941 | 160,242 | 132,868 | 112,579 | 131,359 | 109,293 | 88,489 | 72,597 | 60,886 | ||||||||||
Canada | 1,259,521 | 782,374 | 525,575 | 374,090 | 277,970 | 925,820 | 572,010 | 383,568 | 273,386 | 203,911 | ||||||||||
France | 1,368,130 | 737,715 | 464,855 | 321,653 | 235,825 | 898,657 | 464,533 | 277,847 | 181,362 | 124,539 | ||||||||||
Germany | 58,777 | 38,397 | 26,546 | 19,305 | 14,655 | 58,777 | 38,397 | 26,546 | 19,305 | 14,655 | ||||||||||
Ireland | 444,344 | 271,776 | 182,158 | 131,596 | 100,818 | 444,344 | 271,776 | 182,158 | 131,596 | 100,818 | ||||||||||
Netherlands | 259,073 | 192,535 | 149,984 | 121,255 | 100,904 | 213,280 | 150,798 | 111,666 | 85,850 | 68,004 | ||||||||||
United States | 169,572 | 89,698 | 51,373 | 30,603 | 18,222 | 111,879 | 59,733 | 33,482 | 18,708 | 9,648 | ||||||||||
Total Probable | 3,793,335 | 2,308,436 | 1,560,733 | 1,131,370 | 860,973 | 2,784,116 | 1,666,540 | 1,103,756 | 782,804 | 582,461 | ||||||||||
Proved Plus Probable (2) (3) | ||||||||||||||||||||
Australia | 326,616 | 390,908 | 376,475 | 343,009 | 308,437 | 310,442 | 321,858 | 295,087 | 262,422 | 232,611 | ||||||||||
Canada | 2,802,512 | 1,926,168 | 1,416,572 | 1,095,300 | 879,540 | 2,373,889 | 1,662,206 | 1,243,105 | 975,501 | 793,549 | ||||||||||
France | 3,453,053 | 2,197,818 | 1,569,992 | 1,205,505 | 970,765 | 2,601,906 | 1,668,038 | 1,191,376 | 912,332 | 732,101 | ||||||||||
Germany | 135,075 | 99,842 | 77,545 | 62,771 | 52,536 | 135,075 | 99,842 | 77,545 | 62,771 | 52,536 | ||||||||||
Ireland | 1,089,442 | 835,438 | 666,013 | 551,912 | 472,109 | 1,089,442 | 835,438 | 666,013 | 551,912 | 472,109 | ||||||||||
Netherlands | 392,050 | 325,774 | 280,338 | 247,651 | 223,073 | 318,818 | 257,393 | 216,107 | 187,010 | 165,563 | ||||||||||
United States | 229,098 | 122,942 | 70,085 | 40,725 | 22,960 | 171,405 | 92,977 | 52,194 | 28,830 | 14,386 | ||||||||||
Total Proved Plus Probable | 8,427,846 | 5,898,890 | 4,457,020 | 3,546,873 | 2,929,420 | 7,000,977 | 4,937,752 | 3,741,427 | 2,980,778 | 2,462,855 |
Notes: | |
(1) | The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) | "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(3) | "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(4) | "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. |
(5) | "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. |
(6) | "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. |
(7) | "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. |
Table 6: Total Future Net Revenue (Undiscounted) Based on Forecast Prices and Costs (1)
Abandonment | Future Net | Future Net | ||||||||||||||
Capital | and | Revenue | Revenue | |||||||||||||
Operating | Development | Reclamation | Before | Future | After | |||||||||||
(M$) | Revenue | Royalties | Costs | Costs | Costs | Income Taxes | Income Taxes | Income Taxes | ||||||||
Proved (2) | ||||||||||||||||
Australia | 1,279,689 | - | 765,611 | 164,897 | 256,483 | 92,698 | (86,385) | 179,083 | ||||||||
Canada | 3,444,744 | 430,994 | 956,472 | 429,587 | 84,700 | 1,542,991 | 94,922 | 1,448,069 | ||||||||
France | 3,739,055 | 286,952 | 1,054,237 | 142,825 | 170,118 | 2,084,923 | 381,674 | 1,703,249 | ||||||||
Germany | 243,200 | 34,472 | 121,828 | 7,557 | 3,045 | 76,298 | - | 76,298 | ||||||||
Ireland | 945,039 | - | 196,807 | 29,121 | 74,013 | 645,098 | - | 645,098 | ||||||||
Netherlands | 419,120 | 20,930 | 153,011 | 38,411 | 73,791 | 132,977 | 27,439 | 105,538 | ||||||||
United States | 193,175 | 53,303 | 33,559 | 44,764 | 2,023 | 59,526 | - | 59,526 | ||||||||
Total Proved | 10,264,022 | 826,651 | 3,281,525 | 857,162 | 664,173 | 4,634,511 | 417,650 | 4,216,861 | ||||||||
Proved Plus Probable (2) (3) | ||||||||||||||||
Australia | 1,660,324 | - | 901,981 | 164,950 | 266,777 | 326,616 | 16,174 | 310,442 | ||||||||
Canada | 6,173,958 | 832,588 | 1,597,976 | 830,126 | 110,756 | 2,802,512 | 428,623 | 2,373,889 | ||||||||
France | 6,025,272 | 448,246 | 1,560,955 | 340,273 | 222,745 | 3,453,053 | 851,147 | 2,601,906 | ||||||||
Germany | 408,139 | 61,573 | 199,859 | 7,594 | 4,038 | 135,075 | - | 135,075 | ||||||||
Ireland | 1,487,330 | - | 294,754 | 29,121 | 74,013 | 1,089,442 | - | 1,089,442 | ||||||||
Netherlands | 908,049 | 67,612 | 274,464 | 87,472 | 86,451 | 392,050 | 73,232 | 318,818 | ||||||||
United States | 596,459 | 162,300 | 91,475 | 109,001 | 4,585 | 229,098 | 57,693 | 171,405 | ||||||||
Total Proved Plus Probable | 17,259,531 | 1,572,319 | 4,921,464 | 1,568,537 | 769,365 | 8,427,846 | 1,426,869 | 7,000,977 |
Notes: | |
(1) | The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) | "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(3) | "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
Table 7: Future Net Revenue by Production Group Based on Forecast Prices and Costs (1)
Future Net Revenue | ||||||
Before Income Taxes (2) | ||||||
(Discounted at 10% Per Year) | Unit Value | |||||
Proved Developed Producing | (M$) | ($/boe) | ||||
Light crude oil & medium crude oil (3) | 1,587,327 | 25.88 | ||||
Heavy Oil (3) | 216 | 12.36 | ||||
Natural gas (4) | 733,875 | 18.69 | ||||
Shale Gas | 2,860 | 7.26 | ||||
Coal Bed Methane | 1,259 | 2.62 | ||||
Total Proved Developed Producing | 2,325,537 | 22.91 | ||||
Proved Developed Non-Producing | ||||||
Light crude oil & medium crude oil (3) | 66,158 | 20.41 | ||||
Heavy Oil (3) | - | - | ||||
Natural gas (4) | 126,536 | 14.41 | ||||
Shale Gas | - | - | ||||
Coal Bed Methane | 867 | 3.17 | ||||
Total Proved Developed Non-Producing | 193,561 | 15.74 | ||||
Proved Undeveloped | ||||||
Light crude oil & medium crude oil (3) | 259,816 | 13.92 | ||||
Heavy Oil (3) | - | - | ||||
Natural gas (4) | 116,627 | 8.44 | ||||
Shale Gas | - | - | ||||
Coal Bed Methane | 746 | 1.44 | ||||
Total Proved Undeveloped | 377,189 | 11.43 | ||||
Proved | ||||||
Light crude oil & medium crude oil (3) | 1,913,301 | 22.97 | ||||
Heavy Oil (3) | 216 | 12.42 | ||||
Natural gas (4) | 977,038 | 15.81 | ||||
Shale Gas | 2,860 | 7.28 | ||||
Coal Bed Methane | 2,872 | 2.26 | ||||
Total Proved | 2,896,287 | 19.73 | ||||
Probable | ||||||
Light crude oil & medium crude oil (3) | 992,703 | 20.85 | ||||
Heavy Oil (3) | 87 | 15.91 | ||||
Natural gas (4) | 565,389 | 13.80 | ||||
Shale Gas | 691 | 7.26 | ||||
Coal Bed Methane | 1,863 | 2.26 | ||||
Total Probable | 1,560,733 | 19.73 | ||||
Proved Plus Probable | ||||||
Light crude oil & medium crude oil (3) | 2,906,004 | 22.21 | ||||
Heavy Oil (3) | 303 | 13.30 | ||||
Natural gas (4) | 1,542,427 | 15.00 | ||||
Shale Gas | 3,551 | 7.33 | ||||
Coal Bed Methane | 4,735 | 2.31 | ||||
Total Proved Plus Probable | 4,457,020 | 18.87 |
Notes: | |
(1) | The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(2) | Other Company revenue and costs not related to a specific production group have been allocated proportionately to production groups. Unit values are based on Company Net Reserves. Net present value of reserves categories are an approximation based on major products. |
(3) | Including solution gas and other by-products. |
(4) | Including by-products but excluding solution gas. |
Reconciliations of Changes in Reserves
The following tables set forth a reconciliation of the changes in Vermilion's gross light and medium crude oil, heavy oil and associated and non-associated gas (combined) reserves as at December 31, 2015 compared to such reserves as at December 31, 2014.
Table 8: Reconciliation of Company Gross Reserves by Principal Product Type - Based on Forecast Prices and Costs (3)
Light Crude Oil & | ||||||||||||||||||||||||
AUSTRALIA | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | 12,534 | 5,449 | 17,983 | 12,534 | 5,449 | 17,983 | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 500 | 50 | 550 | 500 | 50 | 550 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 3,087 | (1,799) | 1,288 | 3,087 | (1,799) | 1,288 | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | (2,356) | - | (2,356) | (2,356) | - | (2,356) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 13,765 | 3,700 | 17,465 | 13,765 | 3,700 | 17,465 | - | - | - | - | - | - | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Technical Revisions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | - | - | - | 12,534 | 5,449 | 17,983 | ||||||||||||||||||
Discoveries | - | - | - | - | - | - | ||||||||||||||||||
Extensions & Improved Recovery | - | - | - | 500 | 50 | 550 | ||||||||||||||||||
Technical Revisions | - | - | - | 3,087 | (1,799) | 1,288 | ||||||||||||||||||
Acquisitions | - | - | - | - | - | - | ||||||||||||||||||
Dispositions | - | - | - | - | - | - | ||||||||||||||||||
Economic Factors | - | - | - | - | - | - | ||||||||||||||||||
Production | - | - | - | (2,356) | - | (2,356) | ||||||||||||||||||
At December 31, 2015 | - | - | - | 13,765 | 3,700 | 17,465 | ||||||||||||||||||
Light Crude Oil & | ||||||||||||||||||||||||
CANADA | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | 27,488 | 14,799 | 42,287 | 27,478 | 14,797 | 42,275 | 10 | 2 | 12 | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 1,245 | 2,541 | 3,786 | 1,245 | 2,541 | 3,786 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | (283) | (825) | (1,108) | (295) | (828) | (1,123) | (1) | 1 | - | 13 | 3 | 16 | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | (9) | (4) | (13) | (9) | (4) | (13) | - | - | - | - | - | - | ||||||||||||
Economic Factors | (1,970) | (1,720) | (3,690) | (1,970) | (1,720) | (3,690) | - | - | - | - | - | - | ||||||||||||
Production | (3,481) | - | (3,481) | (3,478) | - | (3,478) | - | - | - | (3) | - | (3) | ||||||||||||
At December 31, 2015 | 22,990 | 14,792 | 37,782 | 22,971 | 14,786 | 37,757 | 9 | 3 | 12 | 10 | 3 | 13 | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | 177,414 | 141,032 | 318,446 | 153,592 | 130,581 | 284,173 | 22,260 | 10,031 | 32,291 | 1,562 | 420 | 1,982 | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 56,482 | 22,244 | 78,726 | 56,482 | 22,244 | 78,726 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 4,325 | (7,773) | (3,448) | 3,505 | (7,828) | (4,323) | - | - | - | 820 | 55 | 875 | ||||||||||||
Acquisitions | 1,933 | 10,824 | 12,757 | 1,933 | 10,824 | 12,757 | - | - | - | - | - | - | ||||||||||||
Dispositions | (39) | (8,944) | (8,983) | (39) | (8,944) | (8,983) | - | - | - | - | - | - | ||||||||||||
Economic Factors | (13,736) | (19,315) | (33,051) | (2,350) | (14,201) | (16,551) | (11,386) | (5,114) | (16,500) | - | - | - | ||||||||||||
Production | (26,116) | - | (26,116) | (23,012) | - | (23,012) | (2,664) | - | (2,664) | (440) | - | (440) | ||||||||||||
At December 31, 2015 | 200,263 | 138,068 | 338,331 | 190,111 | 132,676 | 322,787 | 8,210 | 4,917 | 13,127 | 1,942 | 475 | 2,417 | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | 13,550 | 11,331 | 24,881 | 70,608 | 49,635 | 120,243 | ||||||||||||||||||
Discoveries | - | - | - | - | - | - | ||||||||||||||||||
Extensions & Improved Recovery | 3,059 | 2,749 | 5,808 | 13,718 | 8,997 | 22,715 | ||||||||||||||||||
Technical Revisions | (410) | (2,077) | (2,487) | 28 | (4,197) | (4,169) | ||||||||||||||||||
Acquisitions | 187 | 1,538 | 1,725 | 509 | 3,342 | 3,851 | ||||||||||||||||||
Dispositions | (2) | (193) | (195) | (18) | (1,688) | (1,705) | ||||||||||||||||||
Economic Factors | (95) | (597) | (692) | (4,354) | (5,536) | (9,891) | ||||||||||||||||||
Production | (1,494) | - | (1,494) | (9,328) | - | (9,328) | ||||||||||||||||||
At December 31, 2015 | 14,795 | 12,751 | 27,546 | 71,162 | 50,554 | 121,717 | ||||||||||||||||||
Light Crude Oil & | ||||||||||||||||||||||||
FRANCE | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | 35,602 | 20,288 | 55,890 | 35,602 | 20,288 | 55,890 | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 4,328 | 2,466 | 6,794 | 4,328 | 2,466 | 6,794 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 5,268 | (1,429) | 3,839 | 5,268 | (1,429) | 3,839 | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | (4,477) | - | (4,477) | (4,477) | - | (4,477) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 40,721 | 21,325 | 62,046 | 40,721 | 21,325 | 62,046 | - | - | - | - | - | - | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | 9,875 | 2,582 | 12,457 | 9,875 | 2,582 | 12,457 | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Technical Revisions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | (1,686) | (1,023) | (2,709) | (1,686) | (1,023) | (2,709) | - | - | - | - | - | - | ||||||||||||
Production | (354) | - | (354) | (354) | - | (354) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 7,835 | 1,559 | 9,394 | 7,835 | 1,559 | 9,394 | - | - | - | - | - | - | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | - | - | - | 37,249 | 20,719 | 57,967 | ||||||||||||||||||
Discoveries | - | - | - | - | - | - | ||||||||||||||||||
Extensions & Improved Recovery | - | - | - | 4,328 | 2,465 | 6,794 | ||||||||||||||||||
Technical Revisions | - | - | - | 5,268 | (1,429) | 3,839 | ||||||||||||||||||
Acquisitions | - | - | - | - | - | - | ||||||||||||||||||
Dispositions | - | - | - | - | - | - | ||||||||||||||||||
Economic Factors | - | - | - | (281) | (171) | (452) | ||||||||||||||||||
Production | - | - | - | (4,537) | - | (4,537) | ||||||||||||||||||
At December 31, 2015 | - | - | - | 42,027 | 21,585 | 63,612 | ||||||||||||||||||
Light Crude Oil & | ||||||||||||||||||||||||
GERMANY | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Technical Revisions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | 40,258 | 21,301 | 61,559 | 40,258 | 21,301 | 61,559 | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 2,546 | (2,546) | - | 2,546 | (2,546) | - | - | - | - | - | - | - | ||||||||||||
Technical Revisions | (5,543) | (756) | (6,299) | (5,543) | (756) | (6,299) | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | (5,761) | - | (5,761) | (5,761) | - | (5,761) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 31,500 | 17,999 | 49,499 | 31,500 | 17,999 | 49,499 | - | - | - | - | - | - | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | - | - | - | 6,710 | 3,550 | 10,260 | ||||||||||||||||||
Discoveries | - | - | - | - | - | - | ||||||||||||||||||
Extensions & Improved Recovery | - | - | - | 424 | (424) | - | ||||||||||||||||||
Technical Revisions | - | - | - | (924) | (126) | (1,050) | ||||||||||||||||||
Acquisitions | - | - | - | - | - | - | ||||||||||||||||||
Dispositions | - | - | - | - | - | - | ||||||||||||||||||
Economic Factors | - | - | - | - | - | - | ||||||||||||||||||
Production | - | - | - | (960) | - | (960) | ||||||||||||||||||
At December 31, 2015 | - | - | - | 5,250 | 3,000 | 8,250 | ||||||||||||||||||
Light Crude Oil & | ||||||||||||||||||||||||
IRELAND | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Technical Revisions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | 105,931 | 38,707 | 144,638 | 105,931 | 38,707 | 144,638 | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Technical Revisions | (99) | 8,698 | 8,599 | (99) | 8,698 | 8,599 | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | (11) | - | (11) | (11) | - | (11) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 105,821 | 47,405 | 153,226 | 105,821 | 47,405 | 153,226 | - | - | - | - | - | - | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | - | - | - | 17,655 | 6,451 | 24,106 | ||||||||||||||||||
Discoveries | - | - | - | - | - | - | ||||||||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | ||||||||||||||||||
Technical Revisions | - | - | - | (17) | 1,450 | 1,434 | ||||||||||||||||||
Acquisitions | - | - | - | - | - | - | ||||||||||||||||||
Dispositions | - | - | - | - | - | - | ||||||||||||||||||
Economic Factors | - | - | - | - | - | - | ||||||||||||||||||
Production | - | - | - | (2) | - | (2) | ||||||||||||||||||
At December 31, 2015 | - | - | - | 17,637 | 7,901 | 25,538 | ||||||||||||||||||
Light Crude Oil & | ||||||||||||||||||||||||
NETHERLANDS | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Technical Revisions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | 37,155 | 47,076 | 84,231 | 37,155 | 47,076 | 84,231 | - | - | - | - | - | - | ||||||||||||
Discoveries | 17,405 | 2,880 | 20,285 | 17,405 | 2,880 | 20,285 | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 5,736 | 4,366 | 10,102 | 5,736 | 4,366 | 10,102 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 4,242 | (5,634) | (1,392) | 4,242 | (5,634) | (1,392) | - | - | - | - | - | - | ||||||||||||
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | (16,339) | - | (16,339) | (16,339) | - | (16,339) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 48,199 | 48,688 | 96,887 | 48,199 | 48,688 | 96,887 | - | - | - | - | - | - | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | 54 | 103 | 157 | 6,247 | 7,949 | 14,196 | ||||||||||||||||||
Discoveries | 39 | 7 | 46 | 2,940 | 487 | 3,427 | ||||||||||||||||||
Extensions & Improved Recovery | 7 | 6 | 13 | 963 | 734 | 1,697 | ||||||||||||||||||
Technical Revisions | 24 | (33) | (9) | 731 | (972) | (241) | ||||||||||||||||||
Acquisitions | - | - | - | - | - | - | ||||||||||||||||||
Dispositions | - | - | - | - | - | - | ||||||||||||||||||
Economic Factors | - | - | - | - | - | - | ||||||||||||||||||
Production | (36) | - | (36) | (2,759) | - | (2,758) | ||||||||||||||||||
At December 31, 2015 | 88 | 83 | 171 | 8,122 | 8,198 | 16,320 | ||||||||||||||||||
Light Crude Oil & | ||||||||||||||||||||||||
UNITED STATES | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | 449 | 1,338 | 1,787 | 449 | 1,338 | 1,787 | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 1,367 | 1,324 | 2,691 | 1,367 | 1,324 | 2,691 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 106 | 370 | 476 | 106 | 370 | 476 | - | - | - | - | - | - | ||||||||||||
Acquisitions | 196 | 786 | 982 | 196 | 786 | 982 | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | (84) | - | (84) | (84) | - | (84) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 2,034 | 3,818 | 5,852 | 2,034 | 3,818 | 5,852 | - | - | - | - | - | - | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | 243 | 1,402 | 1,645 | 243 | 1,402 | 1,645 | - | - | - | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 1,453 | 1,569 | 3,022 | 1,453 | 1,569 | 3,022 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 274 | 507 | 781 | 274 | 507 | 781 | - | - | - | - | - | - | ||||||||||||
Acquisitions | 220 | 900 | 1,120 | 220 | 900 | 1,120 | - | - | - | - | - | - | ||||||||||||
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Production | (18) | - | (18) | (18) | - | (18) | - | - | - | - | - | - | ||||||||||||
At December 31, 2015 | 2,170 | 4,378 | 6,548 | 2,170 | 4,378 | 6,548 | - | - | - | - | - | - | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | 10 | 58 | 68 | 500 | 1,630 | 2,129 | ||||||||||||||||||
Discoveries | - | - | - | - | - | - | ||||||||||||||||||
Extensions & Improved Recovery | 233 | 250 | 483 | 1,842 | 1,836 | 3,678 | ||||||||||||||||||
Technical Revisions | 72 | 247 | 319 | 223 | 702 | 925 | ||||||||||||||||||
Acquisitions | 35 | 143 | 178 | 267 | 1,079 | 1,346 | ||||||||||||||||||
Dispositions | - | - | - | - | - | - | ||||||||||||||||||
Economic Factors | - | - | - | - | - | - | ||||||||||||||||||
Production | (3) | - | (3) | (90) | - | (90) | ||||||||||||||||||
At December 31, 2015 | 346 | 698 | 1,044 | 2,742 | 5,246 | 7,988 | ||||||||||||||||||
Light Crude Oil & | ||||||||||||||||||||||||
TOTAL COMPANY | Total Oil (4) | Medium Crude Oil | Heavy Oil | Tight Oil | ||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | ||||||||||||
At December 31, 2014 | 76,073 | 41,874 | 117,947 | 76,063 | 41,872 | 117,935 | 10 | 2 | 12 | - | - | - | ||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 7,440 | 6,381 | 13,821 | 7,440 | 6,381 | 13,821 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 8,178 | (3,683) | 4,496 | 8,166 | (3,686) | 4,480 | (1) | 1 | - | 13 | 3 | 16 | ||||||||||||
Acquisitions | 196 | 786 | 982 | 196 | 786 | 982 | - | - | - | - | - | - | ||||||||||||
Dispositions | (9) | (4) | (13) | (9) | (4) | (13) | - | - | - | - | - | - | ||||||||||||
Economic Factors | (1,970) | (1,720) | (3,690) | (1,970) | (1,720) | (3,690) | - | - | - | - | - | - | ||||||||||||
Production | (10,398) | - | (10,398) | (10,395) | - | (10,395) | - | - | - | (3) | - | (3) | ||||||||||||
At December 31, 2015 | 79,510 | 43,635 | 123,145 | 79,491 | 43,629 | 123,120 | 9 | 3 | 12 | 10 | 3 | 13 | ||||||||||||
Total Gas (4) | Conventional Natural Gas | Coal Bed Methane (5) | Shale Natural Gas (5) | |||||||||||||||||||||
Proved + | Proved + | Proved + | Proved + | |||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||
Factors | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | ||||||||||||
At December 31, 2014 | 370,876 | 252,100 | 622,976 | 347,054 | 241,649 | 588,703 | 22,260 | 10,031 | 32,291 | 1,562 | 420 | 1,982 | ||||||||||||
Discoveries | 17,405 | 2,880 | 20,285 | 17,405 | 2,880 | 20,285 | - | - | - | - | - | - | ||||||||||||
Extensions & Improved Recovery | 66,217 | 25,633 | 91,850 | 66,218 | 25,633 | 91,851 | - | - | - | - | - | - | ||||||||||||
Technical Revisions | 3,199 | (4,958) | (1,760) | 2,379 | (5,013) | (2,635) | - | - | - | 820 | 55 | 875 | ||||||||||||
Acquisitions | 2,153 | 11,724 | 13,877 | 2,153 | 11,724 | 13,877 | - | - | - | - | - | - | ||||||||||||
Dispositions | (39) | (8,944) | (8,983) | (39) | (8,944) | (8,983) | - | - | - | - | - | - | ||||||||||||
Economic Factors | (15,422) | (20,338) | (35,760) | (4,036) | (15,224) | (19,260) | (11,386) | (5,114) | (16,500) | - | - | - | ||||||||||||
Production | (48,599) | - | (48,599) | (45,495) | - | (45,495) | (2,664) | - | (2,664) | (440) | - | (440) | ||||||||||||
At December 31, 2015 | 395,788 | 258,097 | 653,885 | 385,637 | 252,705 | 638,342 | 8,210 | 4,917 | 13,127 | 1,942 | 475 | 2,417 | ||||||||||||
Natural Gas Liquids | BOE | |||||||||||||||||||||||
Proved + | Proved + | |||||||||||||||||||||||
Proved Probable P+P (1) (2) | Proved | Probable | Probable | Proved | Probable | Probable | ||||||||||||||||||
Factors | (Mbbl) | (Mbbl) | (Mbbl) | (Mboe) | (Mboe) | (Mboe) | ||||||||||||||||||
At December 31, 2014 | 13,614 | 11,492 | 25,106 | 151,503 | 95,383 | 246,884 | ||||||||||||||||||
Discoveries | 39 | 7 | 46 | 2,940 | 487 | 3,427 | ||||||||||||||||||
Extensions & Improved Recovery | 3,299 | 3,005 | 6,304 | 21,775 | 13,659 | 35,433 | ||||||||||||||||||
Technical Revisions | (315) | (1,863) | (2,178) | 8,397 | (6,372) | 2,026 | ||||||||||||||||||
Acquisitions | 222 | 1,681 | 1,903 | 776 | 4,421 | 5,197 | ||||||||||||||||||
Dispositions | (2) | (193) | (195) | (18) | (1,688) | (1,705) | ||||||||||||||||||
Economic Factors | (95) | (597) | (692) | (4,635) | (5,707) | (10,342) | ||||||||||||||||||
Production | (1,533) | - | (1,533) | (20,032) | - | (20,031) | ||||||||||||||||||
At December 31, 2015 | 15,229 | 13,532 | 28,761 | 160,706 | 100,184 | 260,889 | . |
Notes: | |
(1) | "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. |
(2) | "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. |
(3) | The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
(4) | For reporting purposes, "Total Oil" is the sum of Light Crude oil and Medium Crude Oil, Heavy Oil and Tight Oil. For reporting purposes, "Total Gas" is the sum of Conventional Natural Gas, Coal Bed Methane and Shale Natural Gas. |
(5) | "Coal Bed Methane" and "Shale Natural Gas" were considered "Unconventional Natural Gas" in previous years. NI 51-5101 no longer differentiates between conventional and unconventional activities. |
The table below sets out the future development costs deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).
Table 9: Future Development Costs(1)
Total Proved | Total Proved Plus Probable | |||||
(M$) | Estimated Using Forecast Prices and Costs | Estimated Using Forecast Prices and Costs | ||||
Australia | ||||||
2016 | 52,820 | 52,820 | ||||
2017 | 6,701 | 6,701 | ||||
2018 | 51,052 | 51,052 | ||||
2019 | 2,993 | 2,993 | ||||
2020 | 3,052 | 3,052 | ||||
Remainder | 48,279 | 48,332 | ||||
Total for all years undiscounted | 164,897 | 164,950 | ||||
Canada | ||||||
2016 | 120,559 | 152,322 | ||||
2017 | 98,902 | 170,944 | ||||
2018 | 89,432 | 189,394 | ||||
2019 | 45,342 | 136,985 | ||||
2020 | 51,326 | 127,236 | ||||
Remainder | 24,026 | 53,245 | ||||
Total for all years undiscounted | 429,587 | 830,126 | ||||
France | ||||||
2016 | 47,099 | 79,711 | ||||
2017 | 41,380 | 77,270 | ||||
2018 | 12,751 | 76,088 | ||||
2019 | 7,300 | 49,803 | ||||
2020 | 15,570 | 24,985 | ||||
Remainder | 18,725 | 32,416 | ||||
Total for all years undiscounted | 142,825 | 340,273 | ||||
Germany | ||||||
2016 | 210 | 210 | ||||
2017 | 159 | 159 | ||||
2018 | 141 | 141 | ||||
2019 | 6,936 | 6,936 | ||||
2020 | 110 | 147 | ||||
Remainder | 1 | 1 | ||||
Total for all years undiscounted | 7,557 | 7,594 | ||||
Ireland | ||||||
2016 | 8,862 | 8,862 | ||||
2017 | 1,321 | 1,321 | ||||
2018 | - | - | ||||
2019 | 1,826 | 1,826 | ||||
2020 | - | - | ||||
Remainder | 17,112 | 17,112 | ||||
Total for all years undiscounted | 29,121 | 29,121 | ||||
Netherlands | ||||||
2016 | 1,487 | 5,150 | ||||
2017 | 28,416 | 48,788 | ||||
2018 | 1,076 | 15,274 | ||||
2019 | 424 | 11,254 | ||||
2020 | 433 | 433 | ||||
Remainder | 6,575 | 6,573 | ||||
Total for all years undiscounted | 38,411 | 87,472 | ||||
United States | ||||||
2016 | 11,034 | 30,362 | ||||
2017 | 24,333 | 37,820 | ||||
2018 | 9,397 | 40,819 | ||||
2019 | - | - | ||||
2020 | - | - | ||||
Remainder | - | - | ||||
Total for all years undiscounted | 44,764 | 109,001 | ||||
Total Company | ||||||
2016 | 242,071 | 329,437 | ||||
2017 | 201,212 | 343,003 | ||||
2018 | 163,849 | 372,768 | ||||
2019 | 64,821 | 209,797 | ||||
2020 | 70,491 | 155,853 | ||||
Remainder | 114,718 | 157,679 | ||||
Total for all years undiscounted | 857,162 | 1,568,537 |
Note: | |
(1) | The pricing assumptions used in the GLJ Report with respect to net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above. See "Forecast Prices used in Estimates". The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101. |
Vermilion expects to source its capital expenditure requirements from internally generated cash flow and, as appropriate, from Vermilion's existing credit facility or equity or debt financing. It is anticipated that costs of funding the future development costs will not impact development of its properties or Vermilion's reserves or future net revenue.
CONTINGENT RESOURCES
Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ Resources Assessment"). All contingent resources evaluated in the GLJ Resources Assessment were deemed economic at the effective date of December 31, 2015.
A range of contingent resources estimates (low, best and high) were prepared by GLJ. See notes 6 to 8 of the tables below for a description of low estimate, best estimate and high estimate.
The GLJ Resources Assessment estimated contingent resources of 95.1 million boe (low estimate) to 254.7 million boe (high estimate), with a best estimate of 160.7 million boe. Contingent resources are in addition to reserves estimated in the GLJ Report.
An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
Summary information regarding contingent resources and net present value of future net revenues from contingent resources are set forth below and are derived, in each case, from the GLJ Resources Assessment. The GLJ Resources Assessment was prepared in accordance with COGEH and NI-51-101 by GLJ, an independent qualified reserve evaluator.
Table 10: Summary of Risked Oil and Gas Contingent Resources as at December 31, 2015 (1) (2) - Forecast Prices and Costs (3) (4)
Unrisked | |||||||||||||||||||||||||||||||
Light Crude Oil & | Conventional | Coal Bed | Natural Gas | Oil | Oil | ||||||||||||||||||||||||||
Resources | Medium Crude Oil | Natural Gas | Methane | Liquids | Equivalent | Equivalent | |||||||||||||||||||||||||
Project | Chance | ||||||||||||||||||||||||||||||
Maturity | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | of Dev. | Gross | Net | ||||||||||||||||||
Sub-Class | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (%) (9) | (Mbbl) | (Mbbl) | ||||||||||||||||||
Contingent (1C) - Low Estimate | |||||||||||||||||||||||||||||||
Development Pending | |||||||||||||||||||||||||||||||
Australia(10) | - | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||
Canada(11) | 15,733 | 11,470 | 216,245 | 186,486 | 3,537 | 3,360 | 15,457 | 11,988 | 67,820 | 55,099 | 81.5% | 83,218 | 67,516 | ||||||||||||||||||
France(12) | 12,604 | 11,853 | 1,020 | 1,020 | - | - | - | - | 12,774 | 12,023 | 87.8% | 14,542 | 13,687 | ||||||||||||||||||
Germany | - | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||
Ireland(13) | - | - | 4,475 | 4,475 | - | - | - | - | 746 | 746 | 70.0% | 1,065 | 1,065 | ||||||||||||||||||
Netherlands(14) | - | - | 215 | 215 | - | - | - | - | 36 | 36 | 60.0% | 60 | 60 | ||||||||||||||||||
USA(15) | 10,099 | 8,314 | 11,178 | 9,202 | - | - | 1,782 | 1,467 | 13,744 | 11,315 | 90.0% | 15,272 | 12,571 | ||||||||||||||||||
Total | 38,436 | 31,637 | 233,133 | 201,398 | 3,537 | 3,360 | 17,239 | 13,455 | 95,120 | 79,219 | 83.3% | 114,157 | 94,899 | ||||||||||||||||||
Contingent (2C) - Best Estimate | |||||||||||||||||||||||||||||||
Development Pending | |||||||||||||||||||||||||||||||
Australia(10) | 3,000 | 3,000 | - | - | - | - | - | - | 3,000 | 3,000 | 80.0% | 3,750 | 3,750 | ||||||||||||||||||
Canada(11) | 24,685 | 17,637 | 361,733 | 312,655 | 6,445 | 6,009 | 24,018 | 18,485 | 110,066 | 89,233 | 79.8% | 138,003 | 111,976 | ||||||||||||||||||
France(12) | 25,611 | 24,007 | 1,300 | 1,300 | - | - | - | - | 25,828 | 24,224 | 85.7% | 30,138 | 28,255 | ||||||||||||||||||
Germany | - | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||
Ireland(13) | - | - | 6,859 | 6,859 | - | - | - | - | 1,143 | 1,143 | 70.0% | 1,633 | 1,633 | ||||||||||||||||||
Netherlands(14) | - | - | 4,739 | 4,739 | - | - | 3 | 3 | 793 | 793 | 60.0% | 1,321 | 1,321 | ||||||||||||||||||
USA(15) | 14,470 | 11,912 | 16,449 | 13,540 | - | - | 2,622 | 2,159 | 19,834 | 16,328 | 90.0% | 22,038 | 18,141 | ||||||||||||||||||
Total | 67,766 | 56,556 | 391,080 | 339,093 | 6,445 | 6,009 | 26,643 | 20,647 | 160,664 | 134,721 | 81.6% | 196,883 | 165,076 | ||||||||||||||||||
Contingent (3C) - High Estimate | |||||||||||||||||||||||||||||||
Development Pending | |||||||||||||||||||||||||||||||
Australia(10) | 4,040 | 4,040 | - | - | - | - | - | - | 4,040 | 4,040 | 80.0% | 5,050 | 5,050 | ||||||||||||||||||
Canada(11) | 51,590 | 36,716 | 537,685 | 461,047 | 8,843 | 8,270 | 34,482 | 25,750 | 177,160 | 140,686 | 78.6% | 225,319 | 179,007 | ||||||||||||||||||
France(12) | 41,455 | 38,784 | 1,670 | 1,670 | - | - | - | - | 41,733 | 39,062 | 85.0% | 49,114 | 45,950 | ||||||||||||||||||
Germany | - | - | - | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||
Ireland(13) | - | - | 10,671 | 10,671 | - | - | - | - | 1,779 | 1,779 | 70.0% | 2,541 | 2,541 | ||||||||||||||||||
Netherlands(14) | - | - | 9,294 | 9,294 | - | - | 6 | 6 | 1,555 | 1,555 | 60.0% | 2,592 | 2,592 | ||||||||||||||||||
USA(15) | 20,592 | 16,951 | 23,987 | 19,746 | - | - | 3,824 | 3,148 | 28,414 | 23,390 | 90.0% | 31,571 | 25,988 | ||||||||||||||||||
Total | 117,677 | 96,491 | 583,307 | 502,428 | 8,843 | 8,270 | 38,312 | 28,904 | 254,681 | 210,512 | 80.5% | 316,187 | 261,128 |
Table 11: Summary of Risked Net Present Value of Future Net Revenues as at December 31, 2015 - Forecast Prices and Costs (3)
Resources Project | ||||||||||||||||||||
Maturity Sub-Class | Before Income Taxes, Discounted at (5) | After Income Taxes, Discounted at (5) | ||||||||||||||||||
(M$) | 0% | 5% | 10% | 15% | 20% | 0% | 5% | 10% | 15% | 20% | ||||||||||
Contingent (1C) -Low Estimate (6) | ||||||||||||||||||||
Development Pending | ||||||||||||||||||||
Australia | - | - | - | - | - | - | - | - | - | - | ||||||||||
Canada | 1,263,475 | 696,994 | 404,377 | 244,496 | 152,795 | 917,336 | 485,559 | 266,767 | 150,423 | 85,918 | ||||||||||
France | 764,172 | 412,773 | 234,791 | 138,408 | 83,554 | 500,593 | 255,152 | 135,124 | 72,474 | 38,285 | ||||||||||
Germany | - | - | - | - | - | - | - | - | - | - | ||||||||||
Ireland | 10,759 | 6,832 | 3,908 | 1,827 | 388 | 10,759 | 6,832 | 3,908 | 1,827 | 388 | ||||||||||
Netherlands | 321 | 288 | 235 | 183 | 139 | (111) | (31) | (4) | 1 | (1) | ||||||||||
USA | 402,480 | 183,006 | 86,860 | 41,587 | 19,010 | 257,913 | 112,016 | 47,760 | 18,068 | 3,877 | ||||||||||
Total | 2,441,207 | 1,299,893 | 730,171 | 426,501 | 255,886 | 1,686,490 | 859,528 | 453,555 | 242,793 | 128,467 | ||||||||||
Contingent (2C) -Best Estimate (7) | ||||||||||||||||||||
Development Pending | ||||||||||||||||||||
Australia | 112,493 | 76,004 | 51,782 | 35,416 | 24,186 | 8,804 | (933) | (6,457) | (9,465) | (10,961) | ||||||||||
Canada | 2,320,917 | 1,231,251 | 711,661 | 438,235 | 283,381 | 1,690,519 | 869,129 | 482,208 | 282,696 | 172,627 | ||||||||||
France | 1,596,937 | 861,198 | 493,517 | 295,075 | 181,775 | 1,046,955 | 534,621 | 286,991 | 157,949 | 87,111 | ||||||||||
Germany | - | - | - | - | - | - | - | - | - | - | ||||||||||
Ireland | 34,337 | 24,293 | 16,560 | 11,029 | 7,171 | 25,752 | 18,634 | 12,872 | 8,618 | 5,581 | ||||||||||
Netherlands | 17,580 | 12,005 | 8,041 | 5,233 | 3,236 | 8,618 | 5,315 | 2,916 | 1,218 | 28 | ||||||||||
USA | 761,511 | 347,466 | 175,611 | 95,123 | 53,819 | 490,733 | 219,043 | 105,532 | 52,935 | 26,574 | ||||||||||
Total | 4,843,775 | 2,552,217 | 1,457,172 | 880,111 | 553,568 | 3,271,381 | 1,645,809 | 884,062 | 493,951 | 280,960 | ||||||||||
Contingent (3C) -High Estimate (8) | ||||||||||||||||||||
Development Pending | ||||||||||||||||||||
Australia | 213,428 | 151,220 | 109,414 | 80,640 | 60,405 | 40,896 | 22,363 | 11,003 | 3,988 | (347) | ||||||||||
Canada | 4,528,849 | 2,254,759 | 1,249,423 | 745,486 | 469,386 | 3,301,748 | 1,601,403 | 857,791 | 491,549 | 295,260 | ||||||||||
France | 2,789,003 | 1,489,072 | 858,593 | 521,966 | 329,664 | 1,828,488 | 934,880 | 512,726 | 293,550 | 172,056 | ||||||||||
Germany | - | - | - | - | - | - | - | - | - | - | ||||||||||
Ireland | 73,725 | 48,565 | 32,219 | 21,620 | 14,641 | 55,100 | 36,396 | 24,132 | 16,127 | 10,830 | ||||||||||
Netherlands | 54,851 | 37,676 | 26,539 | 19,104 | 13,995 | 29,079 | 19,328 | 12,926 | 8,658 | 5,754 | ||||||||||
USA | 1,306,063 | 569,626 | 289,610 | 162,255 | 96,886 | 844,550 | 363,515 | 179,660 | 96,592 | 54,589 | ||||||||||
Total | 8,965,919 | 4,550,918 | 2,565,798 | 1,551,071 | 984,977 | 6,099,861 | 2,977,885 | 1,598,238 | 910,464 | 538,142 |
Notes: | |
(1) | The contingent resource assessments were prepared by GLJ in accordance with the definitions, standards and procedures contained in the COGEH and NI 51-101. Contingent resource is defined in the COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated, as at a given date, and that the resources can be profitably produced in the future. The risked net present value of the future net revenue from the contingent resources does not necessarily represent the fair market value of the contingent resources. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein. |
(2) | GLJ prepared the estimates of contingent resources shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. |
(3) | The forecast price and cost assumptions utilized in the year-end 2015 reserves report were also utilized by GLJ in preparing the contingent resource assessments. See "GLJ December 31, 2015 Forecast Prices" in Vermilion's Annual Information Form for the year ended December 31, 2015. |
(4) | "Gross" Contingent Resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion. "Net" Contingent Resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in Contingent Resources. |
(5) | The risked net present value of future net revenue attributable to the contingent resources does not necessarily represent the fair market value of the contingent resources. Estimated abandonment and reclamation costs have been included in the evaluation. |
(6) | This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. |
(7) | This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. |
(8) | This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. |
(9) | The Chance of Development (CoDev) is the estimated probability that, once discovered, a known accumulation will be commercially developed. Five factors have been considered in determining the CoDev as follows: |
|
|
(10) | Contingent resources for Australia have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $171 MM and the expected timeline is between two and six years. The specific contingencies for these resources are Corporate Commitment and Development Timing. |
(11) | Contingent resources for Canada have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $1,234 MM and the expected timeline is between one and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing. |
(12) | Contingent resources for France have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $542 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing. |
(13) | Contingent resources for Ireland have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $31 MM and the expected timeline is between three and four years. The specific contingencies for these resources are Corporate Commitment and Development Timing. |
(14) | Contingent resources for Netherlands have been estimated based on the continued drilling in our active core assets (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $14 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing. |
(15) | Contingent resources for USA have been estimated based on the continued drilling in our active core asset (see "Description of Properties" section of this AIF) using established recovery technologies. The estimated cost to bring these Contingent resources on commercial production is $278 MM and the expected timeline is between two and 10 years. The specific contingencies for these resources are Corporate Commitment and Development Timing. |
ABOUT VERMILION
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel equivalent of oil. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Fund flows from operations, netbacks and recycle ratio are measures that do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculations of similar measures for other entities. "Fund flows from operations" represents cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management considers fund flows from operations and fund flows from operations per share to be key measures as they demonstrate Vermilion's ability to generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a useful measure of Vermilion's ability to generate cash that is not subject to short-term movements in non-cash operating working capital. "Recycle Ratio" means a measure of capital efficiency calculated by dividing the operating netback of production by the cost of adding reserves. "Netbacks" are per boe and per Mcf measures used in operational and capital allocation decisions. After-tax cash flow netbacks are calculated as cash flow from operating activities (determined in accordance with IFRS) expressed on a per boe basis.
SOURCE Vermilion Energy Inc.
PDF available at: http://stream1.newswire.ca/media/2016/02/29/20160229_C9877_DOC_EN_44637.pdf
CALGARY, Feb. 29, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and audited financial results for the year ended December 31, 2015.
HIGHLIGHTS
(1) | Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) | Estimated proved and proved plus probable reserves attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 8, 2016 with an effective date of December 31, 2015 (the "2015 GLJ Reserves Evaluation") |
(3) | F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure of capital efficiency and are calculated by dividing the applicable capital costs for the period, including the change in undiscounted future development capital ("FDC"), by the change in the reserves, incorporating revisions and production, for the same period. |
(4) | Vermilion retained GLJ to conduct an independent resource evaluation dated February 8, 2016 to assess contingent resources across all of the Company's key operating regions with an effective date of December 31, 2015 (the "GLJ 2015 Resource Assessment"). The associated chance of development for each of the low, best, and high estimate for contingent resources in the Development Pending category are 83%, 82%, and 81%, respectively. There is uncertainty that it will be commercially viable to produce any portion of the resources. |
(5) | Recycle ratio is Operating Netback divided by F&D (including FDC) |
ORGANIZATIONAL UPDATE
As announced on November 30, 2015, Mr. Lorenzo Donadeo will be retiring as Chief Executive Officer ("CEO"), effective March 1, 2016, at which time he will become Chair of the Board of Directors. Mr. Anthony Marino, currently President and Chief Operating Officer ("COO"), will assume the role of President and CEO. Mr. Larry Macdonald, the Board of Director's current Chair, will transition to the newly created role of Lead Independent Director.
Concurrent with those changes, Vermilion is pleased to announce the appointments of Mr. Michael Kaluza to the position of Executive Vice President and COO, and Mr. Dion Hatcher to the position of Vice President of our Canadian Business Unit.
Mr. Kaluza joined Vermilion in February 2013 as Director of our Canadian Business Unit, and was promoted to Vice President of our Canadian Business Unit in May 2014. Mr. Kaluza has over 30 years of operations and executive management experience, and has a Bachelor of Science in Petroleum Engineering (Honors) from the Montana College of Mineral, Science and Technology.
Mr. Hatcher joined Vermilion in 2006 and has over 18 years of industry experience focused on operations engineering and project management. He has a Bachelor of Science in Mechanical Engineering (Honors) from Memorial University of Newfoundland.
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on Monday, February 29, 2016 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 21667130. The replay will be available until midnight mountain time on March 7, 2016.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=1117164&s=1&k=1F2188A24FF5A3DA8F83BE1F0C213F7B or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
HIGHLIGHTS | ||||||||||||
Three Months Ended | Year Ended | |||||||||||
($M except as indicated) | Dec 31, | Sep 30, | Dec 31, | Dec 31, | Dec 31, | |||||||
Financial | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||
Petroleum and natural gas sales | 234,319 | 245,051 | 306,073 | 939,586 | 1,419,628 | |||||||
Fund flows from operations | 136,441 | 129,435 | 185,528 | 516,167 | 804,865 | |||||||
Fund flows from operations ($/basic share) (1) | 1.22 | 1.17 | 1.73 | 4.71 | 7.63 | |||||||
Fund flows from operations ($/diluted share) (1) | 1.21 | 1.16 | 1.71 | 4.65 | 7.51 | |||||||
Net earnings (loss) | (142,080) | (83,310) | 58,642 | (217,302) | 269,326 | |||||||
Net earnings (loss) ($/basic share) | (1.28) | (0.76) | 0.55 | (1.98) | 2.55 | |||||||
Capital expenditures | 128,996 | 93,381 | 166,243 | 486,861 | 687,724 | |||||||
Acquisitions | 6,227 | 22,155 | 1,652 | 28,897 | 601,865 | |||||||
Asset retirement obligations settled | 4,921 | 2,123 | 6,247 | 11,369 | 15,956 | |||||||
Cash dividends ($/share) | 0.645 | 0.645 | 0.645 | 2.580 | 2.580 | |||||||
Dividends declared | 71,965 | 71,244 | 69,119 | 283,575 | 272,732 | |||||||
% of fund flows from operations | 53% | 55% | 37% | 55% | 34% | |||||||
Net dividends (1) | 25,201 | 26,654 | 48,139 | 128,542 | 193,302 | |||||||
% of fund flows from operations | 18% | 21% | 26% | 25% | 24% | |||||||
Payout (1) | 159,118 | 122,158 | 220,629 | 626,772 | 896,982 | |||||||
% of fund flows from operations | 117% | 94% | 119% | 121% | 111% | |||||||
% of fund flows from operations (excluding the Corrib project) (1) | 106% | 77% | 106% | 107% | 99% | |||||||
Net debt | 1,381,951 | 1,363,043 | 1,265,650 | 1,381,951 | 1,265,650 | |||||||
Ratio of net debt to annualized fund flows from operations | 2.5 | 2.6 | 1.7 | 2.7 | 1.6 | |||||||
Operational | ||||||||||||
Production | ||||||||||||
Crude oil (bbls/d) | 28,745 | 28,164 | 28,846 | 28,502 | 28,879 | |||||||
NGLs (bbls/d) | 5,298 | 4,622 | 2,822 | 4,214 | 2,553 | |||||||
Natural gas (mmcf/d) | 162.09 | 140.97 | 107.42 | 133.24 | 108.85 | |||||||
Total (boe/d) | 61,058 | 56,280 | 49,571 | 54,922 | 49,573 | |||||||
Average realized prices | ||||||||||||
Crude oil and NGLs ($/bbl) | 51.64 | 56.57 | 78.64 | 58.80 | 100.06 | |||||||
Natural gas ($/mcf) | 4.55 | 5.36 | 5.90 | 4.98 | 6.42 | |||||||
Production mix (% of production) | ||||||||||||
% priced with reference to WTI | 21% | 24% | 28% | 25% | 28% | |||||||
% priced with reference to AECO | 24% | 22% | 20% | 22% | 18% | |||||||
% priced with reference to TTF | 20% | 20% | 16% | 19% | 18% | |||||||
% priced with reference to Dated Brent | 35% | 34% | 36% | 34% | 36% | |||||||
Netbacks ($/boe) | ||||||||||||
Operating netback | 28.44 | 32.25 | 45.85 | 32.09 | 55.50 | |||||||
Fund flows from operations netback | 23.91 | 24.58 | 38.67 | 25.86 | 44.09 | |||||||
Operating expenses | 11.50 | 10.99 | 12.48 | 11.32 | 12.72 | |||||||
Average reference prices | ||||||||||||
WTI (US $/bbl) | 42.18 | 46.43 | 73.15 | 48.80 | 93.00 | |||||||
Edmonton Sweet index (US $/bbl) | 39.72 | 43.01 | 66.79 | 44.91 | 85.83 | |||||||
Dated Brent (US $/bbl) | 43.69 | 50.26 | 76.27 | 52.46 | 98.99 | |||||||
AECO ($/mmbtu) | 2.46 | 2.90 | 3.60 | 2.69 | 4.50 | |||||||
TTF ($/mmbtu) | 7.28 | 8.48 | 9.16 | 8.23 | 8.96 | |||||||
Average foreign currency exchange rates | ||||||||||||
CDN $/US $ | 1.34 | 1.31 | 1.14 | 1.28 | 1.10 | |||||||
CDN $/Euro | 1.46 | 1.46 | 1.42 | 1.42 | 1.47 | |||||||
Share information ('000s) | ||||||||||||
Shares outstanding - basic | 111,991 | 110,818 | 107,303 | 111,991 | 107,303 | |||||||
Shares outstanding - diluted (1) | 115,025 | 113,643 | 110,334 | 115,025 | 110,334 | |||||||
Weighted average shares outstanding - basic | 111,393 | 110,293 | 107,102 | 109,642 | 105,448 | |||||||
Weighted average shares outstanding - diluted (1) | 112,543 | 111,193 | 108,646 | 111,051 | 107,187 |
(1) |
The above table includes non-GAAP financial measures which may not be
comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted net present value of future net revenue from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; estimated contingent resources; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; and the timing of regulatory proceedings and approvals.
Such forward looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids and natural gas prices, foreign currency exchange rates and interest rates; health, safety and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of crude oil and natural gas reserves does not represent the fair market value of these reserves.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
ABBREVIATIONS
$M | thousand dollars | ||
$MM | million dollars | ||
AECO | the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta | ||
bbl(s) | barrel(s) | ||
bbls/d | barrels per day | ||
bcf | billion cubic feet | ||
boe | barrel of oil equivalent, including: crude oil, natural gas liquids and natural gas (converted on the basis of one boe for six mcf of natural gas) | ||
boe/d | barrel of oil equivalent per day | ||
btu | British thermal units | ||
GJ | gigajoules | ||
HH | Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana | ||
mbbls | thousand barrels | ||
mboe | thousand barrel of oil equivalent | ||
mcf | thousand cubic feet | ||
mcf/d | thousand cubic feet per day | ||
mmboe | million barrel of oil equivalent | ||
mmbtu | million British thermal units | ||
mmcf | million cubic feet | ||
mmcf/d | million cubic feet per day | ||
MWh | megawatt hour | ||
NBP | the reference price paid for natural gas in the United Kingdom, quoted in pence per therm, at the National Balancing Point Virtual Trading Point operated by National Grid. Our production in Ireland is priced with reference to NBP. | ||
NGLs | natural gas liquids | ||
PRRT | Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia | ||
TTF | the day-ahead price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services | ||
WTI | West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma | ||
CGU | Cash generating unit, the basis upon which Vermilions assets are evaluated for potential impairments | ||
DRIP | Dividend Reinvestment Plan |
MESSAGE TO SHAREHOLDERS
Commodity price volatility continued unabated through 2015, and it does not appear that 2016 will provide any immediate relief. Although the current economic environment poses significant challenges for all industry participants, including Vermilion, we believe that continued adherence to our long-term strategy will enable us to emerge from this price cycle stronger than ever.
Our long-term strategy is focused on three main priorities, presented in order of importance:
1) | Preserving the strength of our balance sheet; | |||
2) | Protecting our dividend; and | |||
3) | Investing to fund production growth. |
Preserving the Strength of Our Balance Sheet
We have always been highly disciplined in the management of our balance sheet, historically maintaining leverage ratios that are significantly more conservative than most of our peers. This has allowed us to effectively manage through prior low commodity price environments. We entered the current commodity downturn in a position of relative financial strength, and we took a number of purposeful actions throughout 2015 to preserve our balance sheet.
We have significantly reduced capital investment to support our sustainability in this price environment. Our 2016 E&D budget is now $235 million, representing a decrease of over 50% from 2015 levels and a decrease of more than 65% from 2014 levels. Our intent is to balance cash outlays in 2016 for net dividends and E&D capital investment with our fund flows from operations.
During 2015 we increased our credit facility capacity by $500 million to $2.0 billion and extended the term to May 2019, providing additional financial certainty. At year-end 2015, we had $837 million of undrawn capacity which allowed us to retire the $225 million of 6.5% Senior Unsecured Notes that came due on February 10, 2016 with funds from the credit facility. While we are continuing to assess opportunities to diversify our debt structure, our credit facility is currently our most cost-effective method of borrowing.
In early 2015 we amended our existing Dividend Reinvestment Plan ("DRIP") to include a Premium Dividend™ Component. The Premium Dividend™ Component, when combined with our legacy Dividend Reinvestment Plan, significantly expands our access to the lowest cost source of equity capital available. The program can be suspended or prorated at our discretion, offering considerable flexibility. We view the implementation of the Premium Dividend™ as a short-term measure and we will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate. In the event of a commodity price recovery, it is our intent to reduce, and ultimately eliminate, the Premium Dividend™ Component.
We have hedged a meaningful component of our natural gas production, particularly European natural gas, which remains a significantly stronger market than North American natural gas. At present, we have 25% of our total 2016 net-of-royalty production hedged, including 44% of our anticipated natural gas volumes.
Protecting Our Dividend
We have never reduced our dividend since it was initiated in 2003. We are constantly monitoring both our dividend and accompanying capital program, taking into consideration prevailing and expected commodity prices and equity issued under our DRIP program. Although this commodity downturn has been more pronounced than we anticipated when it began in mid-2014, we believe that our existing dividend remains manageable with the actions we have taken to date. We remain committed to first prioritizing our balance sheet and preserving our financial flexibility. To safeguard our long-term sustainability, we are managing our business based on the current commodity price strip, with the objective that our funds from operations will approximately balance or exceed our cash outflows for net dividends and capital expenditures. Should commodity conditions arise under which we can no longer expect to balance outflows and inflows over longer periods of time, we would protect our balance sheet through further modifications of our capital investment and dividend programs.
Investing to Fund Production Growth
We believe our inventory of organic growth projects is strong and each of our business units is capable of delivering production growth. The diversity of our asset base and commodity and currency exposures allows us to select and fund projects that will generate the highest return in a given economic environment. This advantage is even more pronounced in a low commodity price environment in which available capital funding is highly restricted. Our improved recycle ratio at year-end 2015, despite lower commodity prices, is indicative of the improvement of our project inventory and execution over the past few years.
With the start-up of production at Corrib in Ireland in late 2015, we are positioned to provide strong per share production growth of approximately 10% for our shareholders in 2016. We expect Corrib to meaningfully contribute to production growth in 2017 as well, with a full year of production following the ramp-up to peak rates during the first half of 2016. With production commencing at Corrib plus the improvement in capital efficiencies in our other business units, we have been able to significantly reduce our planned capital investment program to preserve the strength of our balance sheet and protect our dividend. These structural advantages in our production profile position Vermilion to achieve all three priorities outlined above despite the commodity downturn. At such time as commodity market fundamentals warrant additional capital investment, we have the project inventory to provide long-term organic production growth.
2015 Review
We delivered 11% year-over-year production growth, despite a nearly 4,000 boe/d shortfall in anticipated Corrib volumes associated with regulatory delays. We believe that this accomplishment demonstrates the depth of our operational and project capacity. In addition, despite the prevailing commodity price environment, we continued to deliver extremely strong performance across all segments of our business, achieving a number of important milestones.
Europe
Following the receipt of final regulatory approval, first gas production started at Corrib on December 30, 2015. Corrib is expected to provide significant high-margin production growth and generate meaningful free cash flow(1) in 2016 - unique attributes in our industry in the current price environment. To date, Corrib has been producing in-line with expectations, with well deliverability better than anticipated and no significant downtime events. Production initially started with one well before year-end, and a second well was brought on-line in early January 2016. Current production levels are approximately 33 mmcf/d (5,500 boe/d) net to Vermilion. Production levels at Corrib are expected to rise over a period of approximately six months to a peak rate estimated at 58 mmcf/d (9,700 boe/d), net to Vermilion.
In France, we completed a successful four (4.0 net) well drilling program at Champotran during Q1 2015. This was our third successive drilling campaign at Champotran since 2013. We have achieved 100% drilling success across a cumulative 13 wells during that period. Incorporating the impact of our waterflood program, our 2015 drilling program delivered incremental exit production of approximately 1,000 boe/d. Our other activities in France during the year centered around workovers and optimization projects, as well as infrastructure and facility maintenance. In 2016, we intend to continue with workover and optimization activities in France.
In the Netherlands, we drilled two (1.9 net) wells during Q2 2015 on the Slootdorp concession in the province of North Holland. Both wells were successful and encountered more natural gas pay than expected. The wells are currently on sales during an extended production test to size permanent production equipment and are currently producing at a facility-restricted combined rate of 25.8 mmcf/d (4,300 boe/d) net to Vermilion. The Diever-02 exploration well (45% working interest), drilled in 2014, came on production in late October 2015 for an extended production test and continues to produce at a gross rate of 28.5 mmcf/d (4,750 boe/d). Our net incremental production increase from this well is presently limited to approximately 6 mmcf/d (1,000 boe/d) due to current pipeline constraints in the multi-well system that Diever-02 produces into. Activity in the Netherlands during 2016 will focus on permitting and the optimization of existing assets.
In Germany, our partner ExxonMobil Production Deutschland GmbH drilled and completed the Burgmoor Z3a well (25% net interest to Vermilion) in the first half of 2015, which began producing at a sales gas rate of approximately 1.7 mmcf/d (280 boe/d) net to Vermilion. In July 2015, we entered into a farm-in agreement that provides us with participating interest in 19 onshore exploration licenses in northwest Germany and associated proprietary data. The licenses comprise approximately 850,000 net acres of undeveloped oil and natural gas rights in the prolific North German Basin. More recently, we were awarded two additional exploration licenses in Germany adding approximately 110,000 net acres to our land position. Further bolstering our presence in the country, we have taken over the drilling operatorship for the Burgmoor Z5 well in our Dumersee-Uchte producing concession, which is scheduled to be drilled in 2017. The majority of our capital in 2016 will be directed to permitting and pre-drill activities for Burgmoor Z5 and two exploration prospects. In addition, we will continue our ongoing analysis of the geologic and geophysical data acquired with the farm-in assets.
North America
During 2015, we drilled or participated in nine (3.4 net) Cardium wells, 28 (18.5 net) Mannville wells, and five (4.1 net) Midale wells. Overall activity levels in Canada were significantly lower than in prior years as a result of reduced capital availability. Nevertheless, we achieved a number of successes in our Mannville play. One such success was the drilling of a two-mile well that targeted the Notikewin formation and came on production at an infrastructure limited rate of approximately 14 mmcf/d (2,300 boe/d). The productive capability demonstrated by this well ranks it among the top natural gas wells currently producing in Alberta.
In Q2 2015, we completed an infrastructure project that included the expansion of a compressor station as well as the construction of a 22 km pipeline. This infrastructure will play a critical role in supporting the continued growth of our Mannville play over the next few years.
Throughout 2015, we made significant progress in addressing the impact of third-party plant capacity and transportation restrictions on our production volumes. At the end of December, total volumes impacted by capacity issues had been reduced to 1,600 boe/d.
Canadian drilling activities in 2016 will be limited to operated expiry wells and capital commitments on non-operated wells.
In the United States, we completed and began testing one (1 net) Turner Shurley Sand well in the eastern Powder River Basin of Wyoming in Q3 2015. During the year, we consolidated our ownership of this project area to 100% working interest through the acquisition of the remaining 30% interest. We also drilled two additional wells in Q4 2015 which will be completed and tied-in in 2016. We intend to drill one (1.0 net) additional expiry well in 2016. We expect to increase our investment in this play when commodity prices improve.
Australia
In Q4 2015 we completed and placed on production the horizontal sidetrack well that was drilled at the Wandoo A platform. Well performance has been strong at approximately 3,900 boe/d over the last six weeks of 2015. Following this success, we are planning a two-well drilling program in Australia for 2016. Offshore drilling in Australia requires a great deal of advance contracting and logistical planning, which means that full-cycle costs are minimized by proceeding with this program in 2016 despite current oil price weakness. Furthermore, we expect service costs to be near their lows in 2016 at the time of drilling, making this a desirable time to drill these high-quality sidetrack locations.
External Recognition
Vermilion's Board of Directors was recently recognized as a TopGun Board in Canada for 2015/2016 by Brendan Wood International ("BWI") reflecting the high degree of confidence major institutional investors have in Vermilion's Board. The voting panel, which was comprised of over 500 institutional investors and sell-side professionals considered a short-list of 323 potential companies and awarded TopGun status to only 27 companies, less than 10% of those nominated.
Lorenzo Donadeo, Chief Executive Officer and Curtis W. Hicks, Executive Vice President and Chief Financial Officer were also recognized in BWI's Shareholder Confidence survey as a Top Gun CEO and CFO, respectively, reflecting continuing institutional investor confidence in Vermilion's strategic execution, financial practices and investor communications.
During Q4 2015, we were named to the CDP Climate Disclosure Leadership Index ("CDLI"), recognizing the depth and quality of our climate-related disclosure as compared to the 200 largest companies listed on the TSX. CDP (formerly Carbon Disclosure Project), is a global, not-for-profit organization that manages the world's only global environmental disclosure system. To be named to the CDLI, a company must have a disclosure score within the top 10% of surveyed companies. We have voluntarily reported to CDP since 2012. We believe that by measuring and understanding our current environmental profile, we can direct our business strategy to operate in an even more environmentally and socially sustainable manner in the future.
As previously announced, we have been recognized by the Great Place to Work® Institute as a Best Workplace in Canada and France for a sixth consecutive year. We were also recognized for a second consecutive year as a Best Workplace in the Netherlands in 2015, after becoming eligible for ranking in 2014. We are the only energy company in our category to rank on the Best Workplaces lists in Canada and the Netherlands, and the highest scoring energy company on the Best Workplaces list in France.
During 2015, we were ranked 15th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list (the highest ranking for an oil and gas company, and improved from our debut ranking of 32nd last year). We were also named Top International Producer of the year by the Explorers and Producers Association of Canada. This recognition reflects our continued focus on achieving robust shareholder returns combined with environmental, social and governance performance.
Outlook
This is an extraordinarily challenging time for the energy industry. The commodity downturn was largely unexpected, has been breathtaking in its depth and breadth and will leave an impact on the industry that will be felt for years to come. At Vermilion, we are committed to maintaining our focus on delivering a capital markets model that benefits our shareholders over the long-term. We believe that our diversified asset portfolio and operational capabilities position us to protect our balance sheet, defend our dividend, and continue long-term growth. Our management and directors hold approximately 6% of the outstanding shares of Vermilion, ensuring alignment of interests with our shareholders. We look forward to meeting the current challenges, and believe that this business environment will illustrate the differentiating benefits of our global operating, capital markets and cultural model.
CEO Succession
As announced in November 2015, I will be retiring as CEO on March 1, 2016 at which time I will become Chair of the Board of Directors. Since co-founding Vermilion some 22 years ago, we have had great success and it has been an exciting and personally rewarding experience. I want to thank our staff, our executive team, our Board of Directors and our shareholders for their contributions and support over the years. I look forward to working with Anthony Marino as our new CEO, the executive team, and the Board of Directors in taking Vermilion to new and exciting heights.
(1) | The above discussion includes non-GAAP measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
(2) | Corrib P2 well produces from the Sherwood sandstones. The production test was performed over a 12-hour period at a maximum choke of 80/64", achieving a peak production rate of 113 mmcf/d and a stabilized flow rate of 107 mmcf/d with approximately 30% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery. |
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis ("MD&A"), dated February 25, 2016, of Vermilion Energy Inc.'s ("Vermilion", "we", "our", "us" or the "Company") operating and financial results as at and for the three months and year ended December 31, 2015 compared with the corresponding periods in the prior year.
This discussion should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2015 and 2014, together with the accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, will be available on or after March 4, 2016 on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
The audited consolidated financial statements for the year ended December 31, 2015 and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") as issued by the International Accounting Standards Board.
This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS. These financial measures include:
In addition, this MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS and are not disclosed in our audited financial statements. As such, these financial measures are considered non-GAAP financial measures and therefore are unlikely to be comparable with similar financial measures presented by other issuers. For a full description of these non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "NON-GAAP FINANCIAL MEASURES".
VERMILION'S BUSINESS
Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, development and optimization of producing properties in North America, Europe, and Australia. We manage our business through our Calgary head office and our international business unit offices.
This MD&A separately discusses each of our business units in addition to our corporate segment.
2015 REVIEW AND 2016 GUIDANCE
We first issued 2015 capital expenditure guidance of $525 million on December 8, 2014. We subsequently adjusted our 2015 capital expenditure guidance to $415 million on February 27, 2015, in response to the continued weakness in commodity prices. That reduction reflected lower planned activity levels, including the deferral of our Australian drilling program. On August 10, 2015 we announced an increase in our capital expenditure guidance of $70 million to $485 million following the reinstatement of the Australian drilling program as well as additional funding for projects in Canada, France and Ireland. We maintained our previous production guidance of 55,000-57,000 boe/d, albeit towards the lower end of our guidance range due to later-than-originally expected first gas from Corrib. Actual 2015 capital spending of $486.9 million was within 1% of guidance. Production for 2015 proved to be within 0.1% of the guidance range.
On November 9, 2015 we announced preliminary 2016 capital expenditure guidance of $350 million and affirmed production guidance of between 63,000-65,000 boe/d. On January 5, 2016, in response to the continued weakness in commodity prices we adjusted our 2016 capital expenditure guidance to $285 million with corresponding production guidance of 62,500-63,500 boe/d. On February 29, 2016, we further revised our 2016 capital expenditure guidance to $235 million as a result of continued commodity price deterioration. We maintained our production guidance of 62,500-63,500 boe/d. The February 29, 2016 reduction primarily reflects lower expected non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands drilling and pipeline twinning programs.
The following table summarizes our 2015 and 2016 guidance:
Date | Capital Expenditures ($MM) | Production (boe/d) | ||||||||||||||
2015 - Guidance | ||||||||||||||||
2015 Guidance | December 8, 2014 | 525 | 55,000 to 57,000 | |||||||||||||
2015 Guidance | February 27, 2015 | 415 | 55,000 to 57,000 | |||||||||||||
2015 Guidance | August 10, 2015 | 485 | 55,000 to 57,000 | |||||||||||||
2016 - Guidance | ||||||||||||||||
2016 Guidance | November 9, 2015 | 350 | 63,000 to 65,000 | |||||||||||||
2016 Guidance | January 5, 2016 | 285 | 62,500 to 63,500 | |||||||||||||
2016 Guidance | February 29, 2016 | 235 | 62,500 to 63,500 |
SHAREHOLDER RETURN
Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth. The following table, as of December 31, 2015, reflects our trailing one, three, and five year performance:
Total return (1) | Trailing One Year | Trailing Three Year | Trailing Five Year | |||||||||
Dividends per Vermilion share | $2.58 | $7.56 | $12.12 | |||||||||
Capital appreciation per Vermilion share | ($19.39) | ($14.36) | ($8.61) | |||||||||
Total return per Vermilion share | (29.5%) | (13.1%) | 7.6% | |||||||||
Annualized total return per Vermilion share | (29.5%) | (4.6%) | 1.5% | |||||||||
Annualized total return on the S&P TSX High Income Energy Index | (31.2%) | (13.1%) | (8.5%) |
(1) | The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of this MD&A. |
CONSOLIDATED RESULTS OVERVIEW
Three Months Ended | % change | Year Ended | % change | ||||||||||||||
Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | ||||||||||
2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | ||||||||||
Production | |||||||||||||||||
Crude oil (bbls/d) | 28,745 | 28,164 | 28,846 | 2% | - | 28,502 | 28,879 | (1%) | |||||||||
NGLs (bbls/d) | 5,298 | 4,622 | 2,822 | 15% | 88% | 4,214 | 2,553 | 65% | |||||||||
Natural gas (mmcf/d) | 162.09 | 140.97 | 107.42 | 15% | 51% | 133.24 | 108.85 | 22% | |||||||||
Total (boe/d) | 61,058 | 56,280 | 49,571 | 8% | 23% | 54,922 | 49,573 | 11% | |||||||||
Build (draw) in inventory (mbbl) | (93) | (85) | (238) | 84 | (165) | ||||||||||||
Financial metrics | |||||||||||||||||
Fund flows from operations ($M) | 136,441 | 129,435 | 185,528 | 5% | (26%) | 516,167 | 804,865 | (36%) | |||||||||
Per share ($/basic share) | 1.22 | 1.17 | 1.73 | 4% | (29%) | 4.71 | 7.63 | (38%) | |||||||||
Net earnings (loss) | (142,080) | (83,310) | 58,642 | 71% | (342%) | (217,302) | 269,326 | (181%) | |||||||||
Per share ($/basic share) | (1.28) | (0.76) | 0.55 | 68% | (333%) | (1.98) | 2.55 | (178%) | |||||||||
Cash flows from operating activities ($M) | 164,863 | 122,230 | 229,146 | 35% | (28%) | 444,408 | 791,986 | (44%) | |||||||||
Net debt ($M) | 1,381,951 | 1,363,043 | 1,265,650 | 1% | 9% | 1,381,951 | 1,265,650 | 9% | |||||||||
Cash dividends ($/share) | 0.645 | 0.645 | 0.645 | - | - | 2.580 | 2.580 | - | |||||||||
Activity | |||||||||||||||||
Capital expenditures ($M) | 128,996 | 93,381 | 166,243 | 38% | (22%) | 486,861 | 687,724 | (29%) | |||||||||
Acquisitions ($M) | 6,227 | 22,155 | 1,652 | (72%) | 277% | 28,897 | 601,865 | (95%) | |||||||||
Gross wells drilled | 8.00 | 11.00 | 26.00 | 53.00 | 89.00 | ||||||||||||
Net wells drilled | 5.56 | 6.91 | 16.58 | 36.12 | 62.43 |
Operational review
Financial review
Net earnings (loss)
Cash flows from operating activities
Fund flows from operations
Net debt
Dividends
COMMODITY PRICES
Three Months Ended | % change | Year Ended | % change | |||||||||||||||||
Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||||||||||
2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||||||||||
Average reference prices | ||||||||||||||||||||
Crude oil | ||||||||||||||||||||
WTI (US $/bbl) | 42.18 | 46.43 | 73.15 | (9%) | (42%) | 48.80 | 93.00 | (48%) | ||||||||||||
Edmonton Sweet index (US $/bbl) | 39.72 | 43.01 | 66.79 | (8%) | (41%) | 44.91 | 85.83 | (48%) | ||||||||||||
Dated Brent (US $/bbl) | 43.69 | 50.26 | 76.27 | (13%) | (43%) | 52.46 | 98.99 | (47%) | ||||||||||||
Natural gas | ||||||||||||||||||||
AECO ($/mmbtu) | 2.46 | 2.90 | 3.60 | (15%) | (32%) | 2.69 | 4.50 | (40%) | ||||||||||||
TTF ($/mmbtu) | 7.28 | 8.48 | 9.16 | (14%) | (21%) | 8.23 | 8.96 | (8%) | ||||||||||||
TTF (€/mmbtu) | 4.98 | 5.82 | 6.46 | (14%) | (23%) | 5.80 | 6.11 | (5%) | ||||||||||||
NBP ($/mmbtu) | 7.41 | 8.40 | 9.52 | (12%) | (22%) | 8.33 | 9.10 | (8%) | ||||||||||||
NBP (€/mmbtu) | 5.07 | 5.77 | 6.71 | (12%) | (24%) | 5.87 | 6.20 | (5%) | ||||||||||||
Henry Hub ($/mmbtu) | 3.03 | 3.62 | 4.54 | (16%) | (33%) | 3.41 | 4.88 | (30%) | ||||||||||||
Henry Hub (US $/mmbtu) | 2.27 | 2.77 | 4.00 | (18%) | (43%) | 2.66 | 4.41 | (40%) | ||||||||||||
Average foreign currency exchange rates |
||||||||||||||||||||
CDN $/US $ | 1.34 | 1.31 | 1.14 | 2% | 18% | 1.28 | 1.10 | 16% | ||||||||||||
CDN $/Euro | 1.46 | 1.46 | 1.42 | - | 3% | 1.42 | 1.47 | (3%) | ||||||||||||
Average realized prices ($/boe) | ||||||||||||||||||||
Canada | 28.94 | 32.78 | 51.27 | (12%) | (44%) | 34.32 | 64.06 | (46%) | ||||||||||||
France | 54.20 | 60.96 | 79.25 | (11%) | (32%) | 62.67 | 105.43 | (41%) | ||||||||||||
Netherlands | 42.61 | 49.42 | 52.07 | (14%) | (18%) | 46.77 | 52.65 | (11%) | ||||||||||||
Germany | 39.68 | 44.36 | 49.19 | (11%) | (19%) | 43.10 | 46.03 | (6%) | ||||||||||||
Australia | 58.74 | 68.20 | 90.37 | (14%) | (35%) | 70.22 | 113.80 | (38%) | ||||||||||||
United States | 41.94 | 51.60 | 74.08 | (19%) | (43%) | 47.53 | 74.08 | (36%) | ||||||||||||
Consolidated | 41.04 | 46.56 | 63.79 | (12%) | (36%) | 47.07 | 77.75 | (39%) | ||||||||||||
Production mix (% of production) | ||||||||||||||||||||
% priced with reference to WTI | 22% | 24% | 28% | 25% | 28% | |||||||||||||||
% priced with reference to AECO | 24% | 22% | 20% | 22% | 18% | |||||||||||||||
% priced with reference to TTF | 20% | 20% | 16% | 19% | 18% | |||||||||||||||
% priced with reference to Dated Brent | 34% | 34% | 36% | 34% | 36% |
Reference prices
Realized prices
FUND FLOWS FROM OPERATIONS
Three Months Ended | Year Ended | ||||||||||||||||||||||||
Dec 31, 2015 | Sep 30, 2015 | Dec 31, 2014 | Dec 31, 2015 | Dec 31, 2014 | |||||||||||||||||||||
$M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | ||||||||||||||||
Petroleum and natural gas sales | 234,319 | 41.04 | 245,051 | 46.56 | 306,073 | 63.79 | 939,586 | 47.07 | 1,419,628 | 77.75 | |||||||||||||||
Royalties | (16,285) | (2.85) | (17,100) | (3.25) | (25,963) | (5.41) | (65,920) | (3.30) | (108,000) | (5.92) | |||||||||||||||
Petroleum and natural gas revenues | 218,034 | 38.19 | 227,951 | 43.31 | 280,110 | 58.38 | 873,666 | 43.77 | 1,311,628 | 71.83 | |||||||||||||||
Transportation expense | (10,147) | (1.78) | (11,090) | (2.11) | (9,489) | (1.98) | (41,660) | (2.09) | (42,361) | (2.32) | |||||||||||||||
Operating expense | (65,645) | (11.50) | (57,826) | (10.99) | (59,881) | (12.48) | (225,938) | (11.32) | (232,307) | (12.72) | |||||||||||||||
General and administration | (12,431) | (2.18) | (13,088) | (2.49) | (13,236) | (2.76) | (53,584) | (2.68) | (61,727) | (3.38) | |||||||||||||||
PRRT | (1,054) | (0.18) | (99) | (0.02) | (13,568) | (2.83) | (6,878) | (0.34) | (60,340) | (3.30) | |||||||||||||||
Corporate income taxes | 3,113 | 0.55 | (12,383) | (2.35) | (8,304) | (1.73) | (44,237) | (2.22) | (96,996) | (5.31) | |||||||||||||||
Interest expense | (16,584) | (2.90) | (15,420) | (2.93) | (12,943) | (2.70) | (59,852) | (3.00) | (49,655) | (2.72) | |||||||||||||||
Realized gain on derivative instruments | 21,164 | 3.71 | 10,854 | 2.06 | 22,816 | 4.76 | 41,356 | 2.07 | 36,712 | 2.01 | |||||||||||||||
Realized foreign exchange (loss) gain | (252) | (0.04) | 309 | 0.06 | (179) | (0.03) | 623 | 0.03 | (821) | (0.04) | |||||||||||||||
Realized other income | 243 | 0.04 | 227 | 0.04 | 202 | 0.04 | 32,671 | 1.64 | 732 | 0.04 | |||||||||||||||
Fund flows from operations | 136,441 | 23.91 | 129,435 | 24.58 | 185,528 | 38.67 | 516,167 | 25.86 | 804,865 | 44.09 |
The following table shows a reconciliation of the change in fund flows from operations:
($M) | Q4/15 vs. Q3/15 | Q4/15 vs. Q4/14 | 2015 vs. 2014 | |||||||||||||
Fund flows from operations - Comparative period | 129,435 | 185,528 | 804,865 | |||||||||||||
Sales volume variance: | ||||||||||||||||
Canada | 1,779 | 3,636 | 24,239 | |||||||||||||
France | (5,232) | 8,916 | 36,817 | |||||||||||||
Netherlands | 2,104 | 20,038 | 21,601 | |||||||||||||
Germany | 1,478 | (1,153) | 2,245 | |||||||||||||
Ireland | 57 | 57 | 57 | |||||||||||||
Australia | 16,350 | 2,802 | (19,697) | |||||||||||||
United States | 1,051 | 524 | 2,948 | |||||||||||||
Pricing variance on sold volumes: | ||||||||||||||||
WTI | (3,075) | (32,707) | (195,644) | |||||||||||||
AECO | (2,507) | (9,461) | (45,760) | |||||||||||||
Dated Brent | (15,632) | (53,825) | (287,666) | |||||||||||||
TTF | (7,105) | (10,581) | (19,182) | |||||||||||||
Changes in: | ||||||||||||||||
Royalties | 815 | 9,678 | 42,080 | |||||||||||||
Transportation | 943 | (658) | 701 | |||||||||||||
Operating expense | (7,819) | (5,764) | 6,369 | |||||||||||||
General and administration | 657 | 805 | 8,143 | |||||||||||||
PRRT | (955) | 12,514 | 53,462 | |||||||||||||
Corporate income taxes | 15,496 | 11,417 | 52,759 | |||||||||||||
Interest | (1,164) | (3,641) | (10,197) | |||||||||||||
Realized derivatives | 10,310 | (1,652) | 4,644 | |||||||||||||
Realized foreign exchange | (561) | (73) | 1,444 | |||||||||||||
Realized other income | 16 | 41 | 31,939 | |||||||||||||
Fund flows from operations - Current period | 136,441 | 136,441 | 516,167 |
Fund flows from operations of $136.4 million during Q4 2015 represented an increase of 5% versus Q3 2015. Quarter-over-quarter, the increase was achieved, despite significant commodity price declines, as a result of higher sold volumes driven by production growth in every business unit, lower current taxes, and increased receipts from commodity hedges.
Fund flows from operations decreased 26% and 36% for the three months and year ended December 31, 2015, respectively, versus the comparable periods in 2014. The 2015 decreases were primarily driven by unfavourable crude oil and natural gas price variances, partially offset by higher sold volumes resulting from significant production growth and global cost reductions, most notably in per unit operating expense which decreased 8% and 11% for the quarter and full year, respectively. The full year decrease in fund flows from operations was partially offset by the previously mentioned recovery of costs in France.
Fluctuations in fund flows from operations (and correspondingly net earnings (loss) and cash flows from operating activities) may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas. In addition, fund flows from operations may be highly affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the consolidated balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized in income.
CANADA BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Year Ended | % change | ||||||||||||||||||
Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | ||||||||||||||
Canada business unit | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||||||||||
Production | |||||||||||||||||||||
Crude oil (bbls/d) | 7,964 | 9,195 | 11,384 | (13%) | (30%) | 9,550 | 11,248 | (15%) | |||||||||||||
NGLs (bbls/d) | 5,159 | 4,513 | 2,741 | 14% | 88% | 4,108 | 2,476 | 66% | |||||||||||||
Natural gas (mmcf/d) | 87.90 | 71.94 | 58.36 | 22% | 51% | 71.65 | 55.67 | 29% | |||||||||||||
Total (boe/d) | 27,773 | 25,698 | 23,851 | 8% | 16% | 25,598 | 23,001 | 11% | |||||||||||||
Production mix (% of total) | |||||||||||||||||||||
Crude oil | 29% | 36% | 48% | 37% | 49% | ||||||||||||||||
NGLs | 19% | 18% | 11% | 16% | 11% | ||||||||||||||||
Natural gas | 52% | 46% | 41% | 47% | 40% | ||||||||||||||||
Activity | |||||||||||||||||||||
Capital expenditures ($M) | 27,554 | 37,224 | 85,442 | (26%) | (68%) | 201,508 | 334,742 | (40%) | |||||||||||||
Acquisitions ($M) | 6,169 | 8,062 | 1,671 | 14,650 | 415,648 | ||||||||||||||||
Gross wells drilled | 5.00 | 11.00 | 23.00 | 42.00 | 74.00 | ||||||||||||||||
Net wells drilled | 2.56 | 6.91 | 15.16 | 26.01 | 50.27 |
Production
Activity review
Cardium
Mannville
Saskatchewan
Financial review
Three Months Ended | % change | Year Ended | % change | ||||||||||||||||||
Canada business unit | Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||||||||||
($M except as indicated) | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||||||||||
Sales | 73,952 | 77,493 | 112,494 | (5%) | (34%) | 320,613 | 537,788 | (40%) | |||||||||||||
Royalties | (7,146) | (6,638) | (15,626) | 8% | (54%) | (28,144) | (65,563) | (57%) | |||||||||||||
Transportation expense | (3,784) | (4,131) | (3,455) | (8%) | 10% | (16,326) | (14,625) | 12% | |||||||||||||
Operating expense | (24,575) | (23,877) | (19,315) | 3% | 27% | (89,085) | (76,178) | 17% | |||||||||||||
General and administration | (3,669) | (3,694) | (2,840) | (1%) | 29% | (16,888) | (16,791) | 1% | |||||||||||||
Fund flows from operations | 34,778 | 39,153 | 71,258 | (11%) | (51%) | 170,170 | 364,631 | (53%) | |||||||||||||
Netbacks ($/boe) | |||||||||||||||||||||
Sales | 28.94 | 32.78 | 51.27 | (12%) | (44%) | 34.32 | 64.06 | (46%) | |||||||||||||
Royalties | (2.80) | (2.81) | (7.12) | - | (61%) | (3.01) | (7.81) | (61%) | |||||||||||||
Transportation expense | (1.48) | (1.75) | (1.57) | (15%) | (6%) | (1.75) | (1.74) | 1% | |||||||||||||
Operating expense | (9.62) | (10.10) | (8.80) | (5%) | 9% | (9.54) | (9.07) | 5% | |||||||||||||
General and administration | (1.44) | (1.56) | (1.29) | (8%) | 12% | (1.81) | (2.00) | (10%) | |||||||||||||
Fund flows from operations netback | 13.60 | 16.56 | 32.49 | (18%) | (58%) | 18.21 | 43.44 | (58%) | |||||||||||||
Reference prices | |||||||||||||||||||||
WTI (US $/bbl) | 42.18 | 46.43 | 73.15 | (9%) | (42%) | 48.80 | 93.00 | (48%) | |||||||||||||
Edmonton Sweet index (US $/bbl) | 39.72 | 43.01 | 66.79 | (8%) | (41%) | 44.91 | 85.83 | (48%) | |||||||||||||
Edmonton Sweet index ($/bbl) | 53.04 | 56.32 | 75.85 | (6%) | (30%) | 57.43 | 94.82 | (39%) | |||||||||||||
AECO ($/mcf) | 2.46 | 2.90 | 3.60 | (15%) | (32%) | 2.69 | 4.50 | (40%) |
Sales
Royalties
Transportation
Operating expense
General and administration
Impairment
FRANCE BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Year Ended | % change | ||||||||||
Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | ||||||
France business unit | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Production | |||||||||||||
Crude oil (bbls/d) | 12,537 | 12,310 | 11,133 | 2% | 13% | 12,267 | 11,011 | 11% | |||||
Natural gas (mmcf/d) | 1.36 | 1.47 | - | (7%) | 100% | 0.97 | - | 100% | |||||
Total (boe/d) | 12,763 | 12,555 | 11,133 | 2% | 15% | 12,429 | 11,011 | 13% | |||||
Inventory (mbbls) | |||||||||||||
Opening crude oil inventory | 239 | 340 | 214 | 197 | 269 | ||||||||
Crude oil production | 1,153 | 1,133 | 1,024 | 4,477 | 4,019 | ||||||||
Crude oil sales | (1,149) | (1,234) | (1,041) | (4,431) | (4,091) | ||||||||
Closing crude oil inventory | 243 | 239 | 197 | 243 | 197 | ||||||||
Production mix (% of total) | |||||||||||||
Crude oil | 98% | 98% | 100% | 99% | 100% | ||||||||
Natural gas | 2% | 2% | - | 1% | - | ||||||||
Activity | |||||||||||||
Capital expenditures ($M) | 24,085 | 17,369 | 37,189 | 39% | (35%) | 92,265 | 147,852 | (38%) | |||||
Acquisitions ($M) | 79 | 142 | - | 317 | - | ||||||||
Gross wells drilled | - | - | 1.00 | 4.00 | 8.00 | ||||||||
Net wells drilled | - | - | 0.50 | 4.00 | 7.50 |
Production
Activity review
Financial review
Three Months Ended | % change | Year Ended | % change | ||||||||||
France business unit | Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||
($M except as indicated) | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Sales | 63,411 | 76,552 | 82,499 | (17%) | (23%) | 281,422 | 431,252 | (35%) | |||||
Royalties | (7,198) | (8,038) | (6,319) | (10%) | 14% | (26,958) | (28,444) | (5%) | |||||
Transportation expense | (4,275) | (4,566) | (4,096) | (6%) | 4% | (15,378) | (18,975) | (19%) | |||||
Operating expense | (15,792) | (11,998) | (13,544) | 32% | 17% | (50,718) | (61,729) | (18%) | |||||
General and administration | (4,894) | (5,338) | (3,765) | (8%) | 30% | (20,217) | (20,929) | (3%) | |||||
Other income | - | - | - | - | - | 31,775 | - | 100% | |||||
Current income taxes | 4,529 | (4,696) | (6,132) | (196%) | (174%) | (23,764) | (66,901) | (64%) | |||||
Fund flows from operations | 35,781 | 41,916 | 48,643 | (15%) | (26%) | 176,162 | 234,274 | (25%) | |||||
Netbacks ($/boe) | |||||||||||||
Sales | 54.20 | 60.96 | 79.25 | (11%) | (32%) | 62.67 | 105.43 | (41%) | |||||
Royalties | (6.15) | (6.40) | (6.07) | (4%) | 1% | (6.00) | (6.95) | (14%) | |||||
Transportation expense | (3.65) | (3.64) | (3.94) | - | (7%) | (3.42) | (4.64) | (26%) | |||||
Operating expense | (13.50) | (9.55) | (13.01) | 41% | 4% | (11.30) | (15.09) | (25%) | |||||
General and administration | (4.18) | (4.25) | (3.62) | (2%) | 15% | (4.50) | (5.12) | (12%) | |||||
Other income | - | - | - | - | - | 7.08 | - | 100% | |||||
Current income taxes | 3.87 | (3.74) | (5.89) | (203%) | (166%) | (5.29) | (16.36) | (68%) | |||||
Fund flows from operations netback | 30.59 | 33.38 | 46.72 | (8%) | (35%) | 39.24 | 57.27 | (31%) | |||||
Reference prices | |||||||||||||
Dated Brent (US $/bbl) | 43.69 | 50.26 | 76.27 | (13%) | (43%) | 52.46 | 98.99 | (47%) | |||||
Dated Brent ($/bbl) | 58.34 | 65.81 | 86.62 | (11%) | (33%) | 67.09 | 109.36 | (39%) |
Sales
Royalties
Transportation
Operating expense
General and administration
Other income
Current income taxes
NETHERLANDS BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Year Ended | % change | ||||||||||
Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | ||||||
Netherlands business unit | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Production | |||||||||||||
NGLs (bbls/d) | 110 | 109 | 81 | 1% | 36% | 99 | 77 | 29% | |||||
Natural gas (mmcf/d) | 56.34 | 53.56 | 31.35 | 5% | 80% | 44.76 | 38.20 | 17% | |||||
Total (boe/d) | 9,500 | 9,035 | 5,306 | 5% | 79% | 7,559 | 6,443 | 17% | |||||
Activity | |||||||||||||
Capital expenditures ($M) | 18,810 | 5,297 | 10,022 | 255% | 88% | 47,325 | 61,740 | (23%) | |||||
Gross wells drilled | - | - | 2.00 | 2.00 | 7.00 | ||||||||
Net wells drilled | - | - | 0.92 | 1.86 | 4.66 |
Production
Activity review
Financial review
Three Months Ended | % change | Year Ended | % change | ||||||||||
Netherlands business unit | Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||
($M except as indicated) | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Sales | 37,243 | 41,083 | 25,420 | (9%) | 47% | 129,057 | 123,815 | 4% | |||||
Royalties | (224) | (638) | (1,171) | (65%) | (81%) | (3,082) | (5,014) | (39%) | |||||
Operating expense | (6,263) | (5,243) | (6,200) | 19% | 1% | (22,746) | (24,041) | (5%) | |||||
General and administration | (813) | (2,154) | (2,489) | (62%) | (67%) | (4,158) | (3,617) | 15% | |||||
Current income taxes | (2,930) | (4,487) | 2,124 | (35%) | (238%) | (12,152) | (4,154) | 193% | |||||
Fund flows from operations | 27,013 | 28,561 | 17,684 | (5%) | 53% | 86,919 | 86,989 | - | |||||
Netbacks ($/boe) | |||||||||||||
Sales | 42.61 | 49.42 | 52.07 | (14%) | (18%) | 46.77 | 52.65 | (11%) | |||||
Royalties | (0.26) | (0.77) | (2.40) | (66%) | (89%) | (1.12) | (2.13) | (47%) | |||||
Operating expense | (7.17) | (6.31) | (12.70) | 14% | (44%) | (8.24) | (10.22) | (19%) | |||||
General and administration | (0.93) | (2.59) | (5.10) | (64%) | (82%) | (1.51) | (1.54) | (2%) | |||||
Current income taxes | (3.35) | (5.40) | 4.35 | (38%) | (177%) | (4.40) | (1.77) | 149% | |||||
Fund flows from operations netback | 30.90 | 34.35 | 36.22 | (10%) | (15%) | 31.50 | 36.99 | (15%) | |||||
Reference prices | |||||||||||||
TTF ($/mmbtu) | 7.28 | 8.48 | 9.16 | (14%) | (21%) | 8.23 | 8.96 | (8%) | |||||
TTF (€/mmbtu) | 4.98 | 5.82 | 6.46 | (14%) | (23%) | 5.80 | 6.11 | (5%) |
Sales
Royalties
Transportation expense
Operating expense
General and administration
Current income taxes
GERMANY BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Year Ended | % change | ||||||||||
Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | ||||||
Germany business unit | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Production | |||||||||||||
Natural gas (mmcf/d) | 16.17 | 14.00 | 17.71 | 16% | (9%) | 15.78 | 14.99 | 5% | |||||
Total (boe/d) | 2,695 | 2,333 | 2,952 | 16% | (9%) | 2,630 | 2,498 | 5% | |||||
Activity | |||||||||||||
Capital expenditures ($M) | (441) | 1,605 | 563 | (127%) | (178%) | 5,363 | 2,747 | 95% | |||||
Acquisitions ($M) | - | - | - | - | 172,871 | ||||||||
Gross wells drilled | - | - | - | 1.00 | - | ||||||||
Net wells drilled | - | - | - | 0.25 | - |
Production
Activity review
Financial review
Three Months Ended | % change | Year Ended | % change | ||||||||||
Germany business unit | Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||
($M except as indicated) | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Sales | 9,840 | 9,523 | 13,359 | 3% | (26%) | 41,384 | 41,962 | (1%) | |||||
Royalties | (1,166) | (1,477) | (2,481) | (21%) | (53%) | (6,479) | (8,613) | (25%) | |||||
Transportation expense | (508) | (627) | (218) | (19%) | 133% | (3,269) | (2,367) | 38% | |||||
Operating expense | (4,788) | (2,796) | (2,862) | 71% | 67% | (10,956) | (8,686) | 26% | |||||
General and administration | (3,032) | (1,311) | (2,200) | 131% | 38% | (7,386) | (4,688) | 58% | |||||
Current income taxes | - | - | 1,145 | - | (100%) | - | (44) | (100%) | |||||
Fund flows from operations | 346 | 3,312 | 6,743 | (90%) | (95%) | 13,294 | 17,564 | (24%) | |||||
Netbacks ($/boe) | |||||||||||||
Sales | 39.68 | 44.36 | 49.19 | (11%) | (19%) | 43.10 | 46.03 | (6%) | |||||
Royalties | (4.70) | (6.88) | (9.13) | (32%) | (49%) | (6.75) | (9.45) | (29%) | |||||
Transportation expense | (2.05) | (2.92) | (0.80) | (30%) | 156% | (3.41) | (2.60) | 31% | |||||
Operating expense | (19.31) | (13.03) | (10.54) | 48% | 83% | (11.41) | (9.53) | 20% | |||||
General and administration | (12.22) | (6.11) | (8.10) | 100% | 51% | (7.69) | (5.14) | 50% | |||||
Current income taxes | - | - | 4.21 | - | (100%) | - | (0.05) | (100%) | |||||
Fund flows from operations netback | 1.40 | 15.42 | 24.83 | (91%) | (94%) | 13.84 | 19.26 | (28%) | |||||
Reference prices | |||||||||||||
TTF ($/mmbtu) | 7.28 | 8.48 | 9.16 | (14%) | (21%) | 8.23 | 8.96 | (8%) | |||||
TTF (€/mmbtu) | 4.98 | 5.82 | 6.46 | (14%) | (23%) | 5.80 | 6.11 | (5%) |
Sales
Royalties
Transportation expense
Operating expense
General and administration
Current income taxes
IRELAND BUSINESS UNIT
Overview
Operational and financial review
Three Months Ended | % change | Year Ended | % change | ||||||||||
Ireland business unit | Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||
($M except as indicated) | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Sales | 57 | - | - | 100% | 100% | 57 | - | 100% | |||||
Transportation expense | (1,580) | (1,766) | (1,720) | (11%) | (8%) | (6,687) | (6,394) | 5% | |||||
Operating expense | (15) | - | - | 100% | 100% | (15) | - | 100% | |||||
General and administration | (714) | (663) | (579) | 8% | 23% | (2,517) | (1,447) | 74% | |||||
Fund flows from operations | (2,252) | (2,429) | (2,299) | (7%) | (2%) | (9,162) | (7,841) | 17% | |||||
Reference prices | |||||||||||||
NBP ($/mmbtu) | 7.41 | 8.40 | 9.52 | (12%) | (22%) | 8.33 | 9.10 | (8%) | |||||
NBP (€/mmbtu) | 5.07 | 5.77 | 6.71 | (12%) | (24%) | 5.87 | 6.20 | (5%) | |||||
Activity | |||||||||||||
Capital expenditures | 12,493 | 20,694 | 20,932 | (40%) | (40%) | 66,409 | 94,439 | (30%) |
Activity review
Transportation expense
AUSTRALIA BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Year Ended | % change | |||||||||
Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||
Australia business unit | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | ||||
Production | ||||||||||||
Crude oil (bbls/d) | 7,824 | 6,433 | 6,134 | 22% | 28% | 6,454 | 6,571 | (2%) | ||||
Inventory (mbbls) | ||||||||||||
Opening crude oil inventory | 172 | 156 | 258 | 37 | 130 | |||||||
Crude oil production | 720 | 592 | 564 | 2,356 | 2,398 | |||||||
Crude oil sales | (817) | (576) | (785) | (2,318) | (2,491) | |||||||
Closing crude oil inventory | 75 | 172 | 37 | 75 | 37 | |||||||
Activity | ||||||||||||
Capital expenditures ($M) | 40,852 | 7,966 | 11,616 | 413% | 252% | 61,741 | 44,283 | 39% | ||||
Gross wells drilled | 1.00 | - | - | 1.00 | - | |||||||
Net wells drilled | 1.00 | - | - | 1.00 | - |
Production
Activity review
Financial review
Three Months Ended | % change | Year Ended | % change | ||||||||||
Australia business unit | Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||||
($M except as indicated) | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||||
Sales | 47,952 | 39,325 | 70,971 | 22% | (32%) | 162,765 | 283,481 | (43%) | |||||
Operating expense | (13,941) | (13,766) | (17,719) | 1% | (21%) | (51,676) | (61,432) | (16%) | |||||
General and administration | (1,768) | (1,391) | (1,628) | 27% | 9% | (5,754) | (5,873) | (2%) | |||||
PRRT | (1,054) | (99) | (13,568) | 965% | (92%) | (6,878) | (60,340) | (89%) | |||||
Corporate income taxes | 1,201 | (2,720) | (4,799) | (144%) | (125%) | (7,230) | (24,477) | (70%) | |||||
Fund flows from operations | 32,390 | 21,349 | 33,257 | 52% | (3%) | 91,227 | 131,359 | (31%) | |||||
Netbacks ($/boe) | |||||||||||||
Sales | 58.74 | 68.20 | 90.37 | (14%) | (35%) | 70.22 | 113.80 | (38%) | |||||
Operating expense | (17.08) | (23.87) | (22.56) | (28%) | (24%) | (22.29) | (24.66) | (10%) | |||||
General and administration | (2.17) | (2.41) | (2.07) | (10%) | 5% | (2.48) | (2.36) | 5% | |||||
PRRT | (1.29) | (0.17) | (17.28) | 659% | (93%) | (2.97) | (24.22) | (88%) | |||||
Corporate income taxes | 1.47 | (4.72) | (6.11) | (131%) | (124%) | (3.12) | (9.83) | (68%) | |||||
Fund flows from operations netback | 39.67 | 37.03 | 42.35 | 7% | (6%) | 39.36 | 52.73 | (25%) | |||||
Reference prices | |||||||||||||
Dated Brent (US $/bbl) | 43.69 | 50.26 | 76.27 | (13%) | (43%) | 52.46 | 98.99 | (47%) | |||||
Dated Brent ($/bbl) | 58.34 | 65.81 | 86.62 | (11%) | (33%) | 67.09 | 109.36 | (39%) |
Sales
Royalties and transportation expense
Operating expense
General and administration
PRRT and corporate income taxes
UNITED STATES BUSINESS UNIT
Overview
Operational and financial review
Three Months Ended | % change | Year Ended | % change | ||||||||
United States business unit | Dec 31, | Sep 30, | Dec 31, | Q4/15 vs. | Q4/15 vs. | Dec 31, | Dec 31, | 2015 vs. | |||
($M except as indicated) | 2015 | 2015 | 2014 | Q3/15 | Q4/14 | 2015 | 2014 | 2014 | |||
Production | |||||||||||
Crude oil (bbls/d) | 420 | 226 | 195 | 86% | 115% | 231 | 49 | 371% | |||
NGLs (bbls/d) | 29 | - | - | 100% | 100% | 7 | - | 100% | |||
Natural gas (mmcf/d) | 0.20 | - | - | 100% | 100% | 0.05 | - | 100% | |||
Total (boe/d) | 483 | 226 | 195 | 114% | 148% | 247 | 49 | 404% | |||
Activity | |||||||||||
Capital expenditures | 5,643 | 3,226 | 460 | 75% | 1,127% | 12,250 | 460 | 2,563% | |||
Acquisitions | (21) | 12,785 | - | 12,764 | 11,175 | ||||||
Gross wells drilled | 2.00 | - | - | 3.00 | - | ||||||
Net wells drilled | 2.00 | - | - | 3.00 | - | ||||||
Sales | 1,864 | 1,075 | 1,330 | 73% | 40% | 4,288 | 1,330 | 222% | |||
Royalties | (551) | (309) | (366) | 78% | 51% | (1,257) | (366) | 243% | |||
Operating expense | (271) | (146) | (241) | 86% | 12% | (742) | (241) | 208% | |||
General and administration | (897) | (896) | (959) | - | (6%) | (3,836) | (959) | 300% | |||
Fund flows from operations | 145 | (276) | (236) | 153% | 161% | (1,547) | (236) | 556% | |||
Netbacks ($/boe) | |||||||||||
Sales | 41.94 | 51.60 | 74.08 | (19%) | (43%) | 47.53 | 74.08 | (36%) | |||
Royalties | (12.40) | (14.83) | (20.38) | (16%) | (39%) | (13.93) | (20.38) | (32%) | |||
Operating expense | (6.11) | (6.98) | (13.44) | (12%) | (55%) | (8.23) | (13.44) | (39%) | |||
General and administration | (20.18) | (43.03) | (53.44) | (53%) | (62%) | (42.51) | (53.44) | (20%) | |||
Fund flows from operations netback | 3.25 | (13.24) | (13.18) | 125% | 125% | (17.14) | (13.18) | 30% | |||
Reference prices | |||||||||||
WTI (US $/bbl) | 42.18 | 46.43 | 73.15 | (9%) | (42%) | 48.80 | 93.00 | (48%) | |||
WTI ($/bbl) | 56.32 | 60.80 | 83.08 | (7%) | (32%) | 62.41 | 102.75 | (39%) | |||
Henry Hub (US $/mmbtu) | 2.27 | 2.77 | 4.00 | (18%) | (43%) | 2.66 | 4.41 | (40%) | |||
Henry Hub ($/mmbtu) | 3.03 | 3.62 | 4.54 | (16%) | (33%) | 3.41 | 4.88 | (30%) |
Activity review
Sales
Royalties
Operating expense
General and administration
CORPORATE
Overview
Financial review
Three Months Ended | Year Ended | ||||||
Dec 31, | Sep 30, | Dec 31, | Dec 31, | Dec 31, | |||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | ||
General and administration recovery (expense) | 3,356 | 2,359 | 1,224 | 7,172 | (7,423) | ||
Current income taxes | 313 | (480) | (642) | (1,091) | (1,420) | ||
Interest expense | (16,584) | (15,420) | (12,943) | (59,852) | (49,655) | ||
Realized gain on derivatives | 21,164 | 10,854 | 22,816 | 41,356 | 36,712 | ||
Realized foreign exchange (loss) gain | (252) | 309 | (179) | 623 | (821) | ||
Realized other income | 243 | 227 | 202 | 896 | 732 | ||
Fund flows from operations | 8,240 | (2,151) | 10,478 | (10,896) | (21,875) |
General and administration
Current income taxes
Interest expense
Hedging
FINANCIAL PERFORMANCE REVIEW
Year Ended | |||||||||
Dec 31, | Dec 31, | Dec 31, | |||||||
($M except per share) | 2015 | 2014 | 2013 | ||||||
Total assets | 4,209,220 | 4,386,091 | 3,708,719 | ||||||
Long-term debt | 1,162,998 | 1,238,080 | 990,024 | ||||||
Petroleum and natural gas sales | 939,586 | 1,419,628 | 1,273,835 | ||||||
Net earnings (loss) | (217,302) | 269,326 | 327,641 | ||||||
Net earnings (loss) per share | |||||||||
Basic | (1.98) | 2.55 | 3.24 | ||||||
Diluted | (1.98) | 2.51 | 3.20 | ||||||
Cash dividends ($/share) | 2.58 | 2.58 | 2.40 | ||||||
Three Months Ended | |||||||||
Dec 31, | Sep 30, | Jun 30, | Mar 31, | Dec 31, | Sep 30, | Jun 30, | Mar 31, | ||
($M except per share) | 2015 | 2015 | 2015 | 2015 | 2014 | 2014 | 2014 | 2014 | |
Petroleum and natural gas sales | 234,319 | 245,051 | 264,331 | 195,885 | 306,073 | 344,688 | 387,684 | 381,183 | |
Net earnings (loss) | (142,080) | (83,310) | 6,813 | 1,275 | 58,642 | 53,903 | 53,993 | 102,788 | |
Net earnings (loss) per share | |||||||||
Basic | (1.28) | (0.76) | 0.06 | 0.01 | 0.55 | 0.50 | 0.51 | 1.00 | |
Diluted | (1.28) | (0.76) | 0.06 | 0.01 | 0.54 | 0.50 | 0.50 | 0.99 |
The following table shows a reconciliation of the change in net earnings (loss):
($M) | Q4/15 vs. Q3/15 | Q4/15 vs. Q4/14 | 2015 vs. 2014 |
Net earnings (loss) - Comparative period | (83,310) | 58,642 | 269,326 |
Changes in: | |||
Fund flows from operations | 7,006 | (49,087) | (288,698) |
Equity based compensation | (4,760) | (3,140) | (7,430) |
Unrealized gain or loss on derivative instruments | (4,627) | 10,236 | 16,177 |
Unrealized foreign exchange gain or loss | (21,315) | (2,371) | 26,386 |
Unrealized other expense | 75 | 511 | 484 |
Accretion | (125) | (137) | 2 |
Depletion and depreciation | 41,031 | 9,369 | (33,064) |
Deferred tax | (87,432) | (34,480) | 74,138 |
Impairment | 11,377 | (131,623) | (274,623) |
Net loss - Current period | (142,080) | (142,080) | (217,302) |
The fluctuations in net earnings (loss) from quarter-to-quarter and from year-to-year are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations and include: sales, royalties, operating expenses, transportation, general and administration expense, current tax expense, interest expense, realized gains and losses on derivative instruments, and realized foreign exchange gains and losses. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include amounts resulting from acquisitions or charges resulting from impairment or impairment recoveries.
Equity based compensation
Equity based compensation expense relates to non-cash compensation
expense attributable to long-term incentives granted to directors,
officers, and employees under the Vermilion Incentive Plan ("VIP"). The
expense is recognized over the vesting period based on the grant date
fair value of awards, adjusted for the ultimate number of awards that
actually vest as determined by the Company's achievement of performance
conditions.
Equity based compensation expense for the three months and year ended December 31, 2015 was higher versus the comparable periods in 2014 due to a higher average number of awards outstanding and higher grant value.
Unrealized gain or loss on derivative instruments
Unrealized gain or loss on derivative instruments arise as a result of
changes in forecasted future commodity prices. As Vermilion uses
derivative instruments to manage the commodity price exposure of our
future crude oil and natural gas production, we will normally recognize
unrealized gains on derivative instruments when forecasted future
commodity prices decline and vice-versa.
For the year ended December 31, 2015, we recognized an unrealized gain on derivative instruments of $43.5 million, relating primarily to our TTF, Dated Brent, and WTI swaps and collars. As at December 31, 2015, we have a net derivative asset position of $68.3 million.
Unrealized foreign exchange gain or loss
As a result of Vermilion's international operations, Vermilion conducts
business in currencies other than the Canadian dollar and has monetary
assets and liabilities (including cash, receivables, payables,
derivative assets and liabilities, and intercompany loans) denominated
in such currencies. Vermilion's exposure to foreign currencies
includes the US dollar, the Euro and the Australian dollar.
Unrealized foreign exchange gains and losses are the result of translating monetary assets and liabilities held in non-functional currencies to the respective functional currencies of Vermilion and its subsidiaries. Unrealized foreign exchange primarily results from the translation of Euro denominated financial assets and US dollar denominated financial liabilities. As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain while an appreciation in the US dollar against the Canadian dollar will result in an unrealized foreign exchange loss (and vice-versa).
For the three months ended December 31, 2015, the Canadian dollar weakened against the US dollar and remained relatively flat against the Euro, leading to an unrealized foreign exchange loss of $6.4 million. During the year ended December 31, 2015, the Canadian dollar weakened significantly versus the US dollar, but was offset by a strengthening in the Canadian dollar against the Euro resulting in an unrealized foreign exchange gain of $8.8 million.
Accretion
Fluctuations in accretion expense are primarily the result of changes in
discount rates applicable to the balance of asset retirement
obligations and additions resulting from drilling and acquisitions.
Q4 2015 accretion expense was relatively consistent with all comparative periods.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the
result of changes in produced crude oil and natural gas volumes.
Depletion and depreciation on a per boe basis for Q4 2015 of $18.88 was lower as compared to $28.28 in Q3 2015 and $24.42 for Q4 2014. This decrease is primarily due to increased production natural gas properties in Drayton Valley, Canada which have a lower per boe depletion expense. For the year ended December 31, 2015, depletion and depreciation on a per boe basis of $22.98 was relatively consistent with $23.31 for the comparable period in 2014 as increased production from natural gas properties in the Netherlands and light crude oil properties in Saskatchewan, Canada, which both have relatively higher per boe depletion expense, was offset with higher production from natural gas properties in Drayton Valley, Canada, which have a relatively lower per boe depletion expense.
Deferred tax
Deferred tax expense (recovery) arises primarily as a result of changes
in the accounting basis and tax basis for capital assets and asset
retirement obligations and changes in available tax losses. The
increase in deferred tax recovery largely pertains to the tax effect on
the $274.6 million impairment charge recorded in 2015, increased
accounting basis depletion primarily associated with higher global
production, partially offset by a valuation allowance recorded on
deferred tax assets. The valuation allowance relates to certain
non-capital losses for which there is uncertainty as to the Company's
ability to fully utilize such losses when applying forecasted commodity
prices in effect as at December 31, 2015.
Impairment
For the three months and year ended December 31, 2015, Vermilion
recorded impairment charges of $131.6 million and $274.6 million,
respectively, related to the light crude oil play in Saskatchewan,
Canada ($267.9 million in 2015) and the shallow coal bed methane gas
properties in Alberta, Canada ($6.7 million in 2015). These impairment
charges were a result of declines in the price forecasts for crude oil
and natural gas in Canada which decreased the expected future cash
flows from the CGU.
TAXES
Corporate income tax rates
Vermilion pays corporate income taxes in France, the Netherlands, and
Australia. In addition, Vermilion pays PRRT in Australia. PRRT is a
profit based tax applied at a rate of 40% on sales less operating
expenses, capital expenditures, and other eligible expenditures. PRRT
is deductible in the calculation of taxable income in Australia.
Taxable income was subject to corporate income tax at the following rates:
Jurisdiction | 2015 | 2014 |
Canada (1) | 25.5% / 27.0% | 25.5% |
France | 34.4% | 34.4% |
Netherlands | 46.0% | 46.0% |
Germany | 24.2% | 22.8% |
Ireland | 25.0% | 25.0% |
Australia | 30.0% | 30.0% |
United States | 35.0% | 35.0% |
(1) Alberta corporate income tax rates increased from 10% to 12% effective July 1, 2015. |
In 2012, the France government enacted a new 3% tax on dividend distributions made by entities subject to corporate income tax in France. The tax applies to any dividends paid on or after April 17, 2012 and is not recovered by any tax treaties or deductible for French corporate income tax purposes. Vermilion did not pay any dividends from its French entities in 2015.
Tax pools
As at December 31, 2015, we had the following tax pools:
($M) | Oil & Gas Assets | Tax Losses (4) | Other | Total | |
Canada | 1,176,574 (1) | 341,445 | 2,448 | 1,520,467 | |
France | 430,735 (2) | 14,171 | - | 444,906 | |
Netherlands | 54,104 (3) | - | - | 54,104 | |
Germany | 112,038 (3) | 43,360 | 18,977 | 174,375 | |
Ireland | 1,028,986 (4) | 429,987 | - | 1,458,973 | |
Australia | 265,743 (1) | - | - | 265,743 | |
United States | 28,950 (1) | 15,767 | - | 44,717 | |
Total | 3,097,130 (1) | 844,730 | 21,425 | 3,963,285 |
(1) | Deduction calculated using various declining balance rates | |||||
(2) | Deduction calculated using a combination of straight-line over the assets life and unit of production method | |||||
(3) | Deduction calculated using a unit of production method | |||||
(4) | Deduction for current development expenditures and tax losses at 100% against taxable income |
FINANCIAL POSITION REVIEW
Balance sheet strategy
We believe that our balance sheet supports our defined growth
initiatives and our focus is on managing and maintaining a conservative
balance sheet. To ensure that our balance sheet continues to support
our defined growth initiatives, we regularly review whether forecasted
fund flows from operations is sufficient to finance planned capital
expenditures, dividends, and abandonment and reclamation expenditures.
To the extent that forecasted fund flows from operations is not
expected to be sufficient to fulfill such expenditures, we will
evaluate our ability to finance any excess with debt (including
borrowing using the unutilized capacity of our existing revolving
credit facility) or issue equity.
To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations and typically strive to maintain an internally targeted ratio of approximately 1.0 to 1.3 in a normalized commodity price environment. When prices trend higher, we may target a lower ratio and conversely, in a lower commodity price environment, the debt ratio may prove to be higher. At times, we will use our balance sheet to finance acquisitions and, in these situations, we are prepared to accept a higher ratio in the short term but will implement a strategy to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 24 months. This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.
In the current low commodity price environment, Vermilion's net debt to fund flows ratio is expected to be higher than the longer term target ratio. During this period, Vermilion will remain focused on maintaining a strong balance sheet by aligning capital expenditures within forecasted fund flows from operations, which is continually monitored for revised forward price estimates, as well as by hedging additional European natural gas volumes to maintain a diversified commodity portfolio.
Long-term debt
Our long-term debt consists of our revolving credit facility and our
senior unsecured notes. The applicable annual interest rates and the
balances recognized on our balance sheet are as follows:
Annual Interest Rate | As at | |||||
Dec 31, | Dec 31, | Dec 31, | Dec 31, | |||
($M) | 2015 | 2014 | 2015 | 2014 | ||
Revolving credit facility | 3.1% | 3.1% | 1,162,998 | 1,014,067 | ||
Senior unsecured notes (1) | 6.5% | 6.5% | 224,901 | 224,013 | ||
Long-term debt | 3.7% | 3.8% | 1,387,899 | 1,238,080 |
(1) | The senior unsecured notes, which matured on February 10, 2016, are included in the current portion of long-term debt as at December 31, 2015. |
Revolving Credit Facility
On January 30, 2015, Vermilion increased its credit facility from $1.5
billion to $1.75 billion. During Q2 2015, we negotiated a further
expansion and extension of our existing revolving credit facilities
from $1.75 billion to $2 billion with a maturity of May 2019. This
allowed Vermilion to redeem the senior unsecured notes, which matured
on February 10, 2016, with a portion of the credit facility. The
facility bears interest at rates applicable to demand loans plus
applicable margins. The following table outlines the terms of our
revolving credit facility:
As at | ||
Dec 31, | Dec 31, | |
2015 | 2014 | |
Total facility amount | $2.0 billion | $1.5 billion |
Amount drawn | $1.2 billion | $1.0 billion |
Letters of credit outstanding | $25.2 million | $8.6 million |
Facility maturity date | 31-May-19 | 31-May-17 |
In addition, the revolving credit facility is subject to the following covenants:
As at | |||
Dec 31, | Dec 31, | ||
Financial covenant | Limit | 2015 | 2014 |
Consolidated total debt to consolidated EBITDA | 4.0 | 2.23 | 1.21 |
Consolidated total senior debt to consolidated EBITDA | 3.0 | 1.83 | 0.99 |
Consolidated total senior debt to total capitalization | 50% | 36% | 31% |
Our covenants include financial measures defined within our revolving credit facility agreement that are not defined under GAAP. These financial measures are defined by our revolving credit facility agreement as follows:
Vermilion was in compliance with its financial covenants for all periods presented.
Senior Unsecured Notes
As at December 31, 2015, we had outstanding senior unsecured notes that
were senior unsecured obligations and ranked pari passu with all our
unsecured and unsubordinated indebtedness. The following table
outlines the terms of these notes:
Total issued and outstanding amount | $225.0 million |
Interest rate | 6.5% per annum |
Issued date | February 10, 2011 |
Maturity date | February 10, 2016 |
Vermilion redeemed the full principal outstanding of the notes on February 10, 2016 using available capacity under the revolving credit facility. The notes were initially recognized at fair value net of transaction costs and were subsequently measured at amortized cost using an effective interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP measure,
long-term debt, as follows:
As at | ||
Dec 31, | Dec 31, | |
($M) | 2015 | 2014 |
Long-term debt | 1,162,998 | 1,238,080 |
Current liabilities (1) | 503,731 | 365,729 |
Current assets | (284,778) | (338,159) |
Net debt | 1,381,951 | 1,265,650 |
Ratio of net debt to fund flows from operations | 2.7 | 1.6 |
(1) | Includes the current portion of long-term debt, which, as at December 31, 2015, represented the senior unsecured notes that matured on February 10, 2016. |
Long term debt, including the current portion, as at December 31, 2015, increased to $1.39 billion from $1.24 billion as at December 31, 2014 as a result of draws on the revolving credit facility during the current year to fund capital expenditures, particularly relating to development expenditures in Canada, France, Ireland, and Australia. The increase in long-term debt resulted in an increase to net debt from $1.27 billion to $1.38 billion. As a result of this increase to long-term debt coupled with weak commodity prices, the ratio of net debt to fund flows from operations increased from 1.6 times as at December 31, 2014 to 2.7 times for the year ended December 31, 2015.
Shareholders' capital
During the year ended December 31, 2015, we maintained monthly dividends
at $0.215 per share and declared dividends which totalled $283.6
million.
The following table outlines our dividend payment history:
Date | Monthly dividend per unit or share |
January 2003 to December 2007 | $0.170 |
January 2008 to December 2012 | $0.190 |
January 2013 to December 31, 2013 | $0.200 |
January 2014 to Present | $0.215 |
Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations. During low commodity price cycles, we will initially maintain dividends and allow the ratio to rise. Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels and acquisition opportunities. As a further step to preserve our financial flexibility and conservatively exercise our access to capital, we amended our existing DRIP to include a Premium Dividend™ Component in February 2015. The Premium Dividend™ Component, when combined with our continuing Dividend Reinvestment Component, increases our access to the lowest cost sources of equity capital available. While the Premium Dividend™ results in a modest amount of equity issuance, we believe it represents the most prudent approach to preserving near-term balance sheet strength. We view implementation of a Premium Dividend™ as a short-term measure to maintain our financial flexibility while we continue to lower our unit costs and await further clarity on the direction of commodity prices. Both components of our program can be reduced or eliminated at the company's discretion, offering considerable flexibility. We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate.
Although we currently expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this period to fund cash dividends, capital expenditures and asset retirement obligations. We will evaluate our ability to finance any shortfalls with debt, issuances of equity or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.
The following table reconciles the change in shareholders' capital:
Shareholders' Capital | Number of Shares ('000s) | Amount ($M) | ||
Balance as at December 31, 2014 | 107,303 | 1,959,021 | ||
Issuance of shares pursuant to the dividend reinvestment and Premium DividendTM plans | 3,338 | 155,033 | ||
Vesting of equity based awards | 1,158 | 56,855 | ||
Share-settled dividends on vested equity based awards | 135 | 7,561 | ||
Shares issued pursuant to the employee savings and bonus plans | 57 | 2,619 | ||
Balance as at December 31, 2015 | 111,991 | 2,181,089 |
As at December 31, 2015, there were approximately 1.7 million VIP awards outstanding. As at February 25, 2016, there were approximately 113.0 million common shares issued and outstanding.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
As at December 31, 2015, we had the following contractual obligations and commitments:
($M) | Less than 1 year | 1 - 3 years | 3 - 5 years | After 5 years | Total |
Long-term debt | 226,625 | - | 1,171,620 | - | 1,398,245 |
Operating lease obligations | 12,535 | 22,049 | 16,617 | 9,288 | 60,489 |
Ship or pay agreement relating to the Corrib project | 8,215 | 8,893 | 7,292 | 40,446 | 64,846 |
Purchase obligations | 17,897 | 4,071 | 3,156 | - | 25,124 |
Drilling and service agreements | 23,205 | 2,480 | - | - | 25,685 |
Total contractual obligations and commitments | 288,477 | 37,493 | 1,198,685 | 49,734 | 1,574,389 |
ASSET RETIREMENT OBLIGATIONS
As at December 31, 2015, asset retirement obligations were $305.6 million compared to $350.8 million as at December 31, 2014.
The decrease in asset retirement obligations is largely attributable to an overall increase in the discount rates applied to the abandonment obligations.
RISKS AND UNCERTAINTIES
Crude oil and natural gas exploration, production, acquisition and marketing operations involve a number of risks and uncertainties including financial risks and uncertainties. These include fluctuations in commodity prices, exchange rates and interest rates as well as uncertainties associated with reserve and resource volumes, sales volumes and government regulatory and income tax regime changes. These and other related risks and uncertainties are discussed in additional detail below.
Commodity prices
Our operational results and financial condition is dependent on the
prices received for crude oil and natural gas production. Crude oil and
natural gas prices have fluctuated significantly during recent years
and are determined by supply and demand factors, including weather and
general economic conditions as well as conditions in other crude oil
and natural gas producing regions.
Exchange rates
Much of our revenue stream is priced in U.S. dollars and as such an
increase in the strength of the Canadian dollar relative to the U.S.
dollar may result in the receipt of fewer Canadian dollars with respect
to our production. In addition, we incur expenses and capital costs in
U.S. dollars, Euros and Australian dollars and accordingly, the
Canadian dollar equivalent of these expenditures as reported in our
financial results is impacted by the prevailing exchange rates at the
time the transaction occurs. We monitor risks associated with exchange
rates and, when appropriate, use derivative financial instruments to
manage our exposure to these risks.
Production and sales volumes
The operation of crude oil and natural gas wells and facilities involves
a number of operating and natural hazards which may result in blowouts,
environmental damage and other unexpected or dangerous conditions
resulting in damage to us and possible liability to third parties. We
maintain liability insurance, where available, in amounts consistent
with industry standards. Business interruption insurance may also be
purchased for selected operations, to the extent that such insurance is
commercially viable. We may become liable for damages arising from such
events against which we cannot insure or against which we may elect not
to insure because of high premium costs or other reasons. Costs
incurred to repair such damage or pay such liabilities may materially
impact our financial results.
Continuing production from a property, and to some extent the marketing of produced volumes, is largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat our claim to certain properties. Such circumstances could negatively affect our financial results.
An increase in operating costs or a decline in our production level could have an adverse effect on our financial results. The level of production may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond our control. A significant decline in production could result in materially lower revenues.
Interest rates
An increase in interest rates could result in a significant increase in
the amount we pay to service debt.
Reserve volumes
Our reserve volumes and related reserve values support the carrying
value of our crude oil and natural gas assets on the consolidated
balance sheets and provide the basis to calculate the depletion of
those assets. There are numerous uncertainties inherent in estimating
quantities of reserves and future net revenues to be derived therefrom,
including many factors beyond our control. These include a number of
assumptions relating to factors such as initial production rates,
production decline rates, ultimate recovery of reserves, timing and
amount of capital expenditures, marketability of production, future
prices of crude oil, NGLs and natural gas, operating expenses, well
abandonment and salvage values, royalties and any government levies
that may be imposed over the producing life of the reserves. These
assumptions were based on estimated prices in use at the date the
evaluation was prepared, and many of these assumptions are subject to
change and are beyond our control. Actual production and income
derived therefrom will vary from these evaluations, and such variations
could be material.
Asset retirement obligations
Our asset retirement obligations are based on environmental regulations
and estimates of future costs and the timing of expenditures. Changes
in environmental regulations, the estimated costs associated with
reclamation activities and the related timing may impact our financial
position and results of operations.
Government regulation and income tax regime
Our operations are governed by many levels of government, including
municipal, state, provincial and federal governments, in Canada,
France, the Netherlands, Australia, Germany, Ireland and the United
States. We are subject to laws and regulations regarding environment,
health and safety issues, lease interests, taxes and royalties, among
others. Failure to comply with the applicable laws can result in
significant increases in costs, penalties and even losses of operating
licences. The regulatory process involved in each of the countries in
which we operate is not uniform and regulatory regimes vary as to
complexity, timeliness of access to, and response from, regulatory
bodies and other matters specific to each jurisdiction. If regulatory
approvals or permits are delayed or not obtained, there can also be
delays or abandonment of projects and decreases in production and
increases in costs, potentially resulting in us being unable to fully
execute our strategy. Governments may also amend or create new
legislation and regulatory bodies may also amend regulations or impose
additional requirements which could result in increased capital,
operating and compliance costs.
There can be no assurance that income tax laws and government incentive programs relating to the crude oil and natural gas industry in Canada and the foreign jurisdictions in which we operate, will not be changed in a manner which adversely affects the results of our operations.
A change in the royalty regime resulting in an increase in royalties would reduce our net earnings and could make future capital expenditures or our operations uneconomic and could, in the event of a material increase in royalties, make it more difficult to service and repay outstanding debt. Any material increase in royalties would also significantly reduce the value of the associated assets.
FINANCIAL RISK MANAGEMENT
To mitigate the aforementioned risks whenever possible, we seek to hire personnel with experience in specific areas. In addition, we provide continued training and development to staff to further develop their skills. When appropriate, we use third party consultants with relevant experience to augment our internal capabilities with respect to certain risks.
We consider our commodity price risk management program as a form of insurance that protects our cash flow and rate of return. The primary objective of the risk management program is to support our dividends and our internal capital development program. The level of commodity price risk management that occurs is highly dependent on the amount of debt that is carried. When debt levels are higher, we will be more active in protecting our cash flow stream through our commodity price risk management strategy.
When executing our commodity price risk management programs, we use derivative financial instruments encompassing over-the-counter financial structures as well as fixed/collar structures to economically hedge a part of our physical crude oil and natural gas production. We have strict controls and guidelines in relation to these activities and contract principally with counterparties that have investment grade credit ratings.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on our consolidated financial statements or financial performance. Estimates are reviewed by management on an ongoing basis, and as a result, certain estimates may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction in which we operate, the critical accounting estimates may affect one or more jurisdictions.
The following discussion outlines what management believes to be the most critical accounting policies involving the use of estimates and assumptions.
Depletion and depreciation
We classify our assets into depletion units, which are groups of assets
or properties that are within a specific production area and have
similar economic lives. The depletion units represent the lowest level
of disaggregation for which we accumulate costs for the purposes of
calculating and recording depletion and depreciation.
The net carrying value of each depletion unit is depleted using the unit of production method by reference to the ratio of production in the period to the total proven and probable reserves, taking into account the future development costs necessary to bring the applicable reserves into production. As a result, depletion and depreciation charges are based on estimates of total proven and probable reserves that we expect to recover in the future. The reserve estimates are reviewed annually by management or when material changes occur to the underlying assumptions.
Asset retirement obligations
Our estimate of asset retirement obligations are based on past
experience and current economic factors which management believes are
reasonable. The estimates include assumptions of environmental
regulations, legal requirements, technological advances, inflation and
the timing of expenditures, all of which impact our measurement of the
present value of the obligations. Due to these estimates, the actual
cost of the obligation may change from period to period due to new
information being available. Several or all of these estimates are
subject to change and such changes could have a material impact on our
financial position and net earnings.
Assessment of impairments
Impairment tests are performed at the level of the cash generating unit
("CGU"), which are determined based on management's judgment of the
lowest level at which there are identifiable cash inflows which are
largely independent of the cash inflows of other groups of assets or
properties. The factors used to determine CGUs vary by country due to
the unique operating and geographic circumstances in each
jurisdiction. However, in general, we will assess the following
factors in determining whether a group of assets generate largely
independent cash inflows: geographic proximity of the assets within a
group to one another, geographic proximity of the group of assets to
other groups of assets, homogeneity of the production from the group of
assets and the sharing of infrastructure used to process or transport
production.
The calculation of the recoverable amount of CGUs is based on market factors as well as estimates of reserves and resources and future costs required to develop reserves and resources. Our reserve and resource estimates and the related future cash flows are subject to measurement uncertainty, and the impact on the consolidated financial statements in future periods could be material. Considerable judgment is used in determining the recoverable amount of petroleum and natural gas assets as well as exploration and evaluation assets, including determining the quantity of reserves and resources, the time horizon to develop and produce such reserves and resources, and the estimated revenues and expenditures from such production.
Taxes
Tax interpretations, regulations and legislation in the various
jurisdictions in which we operate are subject to change. Such changes
can affect the timing of the reversal of temporary tax differences, the
tax rates in effect when such differences reverse and our ability to
use tax losses and other credits in the future. The determination of
deferred tax amounts recognized in the consolidated financial
statements was based on management's assessment of the tax positions,
including consideration of their technical merits and communications
with tax authorities. The effect of a change in income tax rates or
legislation on tax assets and liabilities is recognized in net earnings
in the period in which the change is enacted.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are entered into in the normal course of operations, including operating leases for which no asset or liability value has been assigned to the consolidated balance sheet as at December 31, 2015.
We have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.
ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
The impacts of the adoption of the following pronouncements are currently being evaluated.
IFRS 9 "Financial Instruments"
On July 24, 2014, the IASB issued the final element of its comprehensive
response to the financial crisis by issuing IFRS 9 "Financial
Instruments". The improvements introduced by IFRS 9 includes a model
for classification and measurement, a single, forward-looking 'expected
loss' impairment model and a substantially-reformed approach to hedge
accounting. Vermilion will adopt the standard for reporting periods
beginning January 1, 2018.
IFRS 15 "Revenue from Contracts with Customers"
On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with
Customers", a new standard that specifies recognition requirements for
revenue as well as requiring entities to provide the users of financial
statements with more informative and relevant disclosures. The
standard replaces IAS 11 "Construction Contracts" and IAS 18 "Revenue"
as well as a number of revenue-related interpretations. Vermilion will
adopt the standard for reporting periods beginning January 1, 2018.
IFRS 16 "Leases"
On January 13, 2016, the IASB issued IFRS 16, "Leases", a new standard
which will replace IAS 17, "Leases". Under IFRS 16, a single
recognition and measurement model will apply for lessees which will
require recognition of assets and liabilities for most leases.
Vermilion will adopt the standard for reporting periods beginning
January 1, 2019.
HEALTH, SAFETY AND ENVIRONMENT
We are committed to ensuring we conduct our activities in a manner that will protect the health and safety of our employees, contractors, and the public. Our health, safety, and environment ("HSE") vision is to fully integrate health, safety, and environment into our business, where our culture is recognized as a model by industry and stakeholders, resulting in a workplace free of incidents. Our mantra is HSE: Everywhere. Everyday. Everyone.
We maintain health, safety and environmental practices and procedures that comply with or exceed regulatory requirements and industry standards. It is a condition of employment that our personnel work safely and in accordance with established regulations and procedures.
In 2015, we remained committed to the principles of the Responsible Canadian Energy™ program set out by the Canadian Association of Petroleum Producers. Responsible Canadian Energy™ is an association-wide performance reporting program to demonstrate progress in environmental, health, safety, and social performance.
We uphold our commitment to keep our people safe and to reduce impacts to land, water and air, as policies and procedures demonstrating leadership in these areas, were maintained and further developed in 2015. Examples of our accomplishments during the year included:
We are a member of several organizations concerned with environment, health and safety, including numerous regional co-operatives and synergy groups. In the area of stakeholder relations, we work to build long-term relationships with environmental stakeholders and communities.
CORPORATE GOVERNANCE
We are committed to a high standard of corporate governance practices, a dedication that begins at the Board level and extends throughout the Company. We believe good corporate governance is in the best interest of our shareholders, and that successful companies are those that deliver growth and a competitive return along with a commitment to the environment, to the communities where they operate and to their employees.
We comply with the objectives and guidelines relating to corporate governance adopted by the Canadian Securities Administrators and the Toronto Stock Exchange. In addition, the Board monitors and considers the implementation of corporate governance standards proposed by various regulatory and non-regulatory authorities in Canada. A discussion of corporate governance policies will be provided in our Management Proxy Circular, which will be filed on SEDAR (www.sedar.com) and mailed to all shareholders on April 6, 2016.
A summary of the significant differences between the governance practices of the Company and those required of U.S. domestic companies under the New York Stock Exchange listing standards can be found in the Governance section of the Company's website at http://www.vermilionenergy.com/about/governance.cfm.
DISCLOSURE CONTROLS AND PROCEDURES
Our officers have established and maintained disclosure controls and procedures and evaluated the effectiveness of these controls in conjunction with our filings.
As of December 31, 2015, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded and certified that our disclosure controls and procedures are effective.
INTERNAL CONTROL OVER FINANCIAL REPORTING
A company's internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
The Chief Executive Officer and the Chief Financial Officer of Vermilion have assessed the effectiveness of Vermilion's internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. The assessment was based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Chief Executive Officer and the Chief Financial Officer of Vermilion have concluded that Vermilion's internal control over financial reporting was effective as of December 31, 2015. The effectiveness of Vermilion's internal control over financial reporting as of December 31, 2015 has been audited by Deloitte LLP, as reflected in their report included in the 2015 audited annual financial statements filed with the US Securities and Exchange Commission. No changes were made to Vermilion's internal control over financial reporting during the year ended December 31, 2015, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.
Supplemental Table 1: Netbacks
The following table includes financial statement information on a per unit basis by business unit. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.
Three Months Ended December 31, 2015 | Year Ended December 31, 2015 |
Three Months Ended December 31, 2014 |
Year Ended December 31, 2014 |
|||||||||
Oil & NGLs | Natural Gas | Total | Oil & NGLs | Natural Gas | Total | Total | Total | |||||
$/bbl | $/mcf | $/boe | $/bbl | $/mcf | $/boe | $/boe | $/boe | |||||
Canada | ||||||||||||
Sales | 44.03 | 2.57 | 28.94 | 49.73 | 2.78 | 34.32 | 51.27 | 64.06 | ||||
Royalties | (5.15) | (0.12) | (2.80) | (5.26) | (0.07) | (3.01) | (7.12) | (7.81) | ||||
Transportation | (2.04) | (0.16) | (1.48) | (2.38) | (0.17) | (1.75) | (1.57) | (1.74) | ||||
Operating | (10.97) | (1.40) | (9.62) | (10.47) | (1.41) | (9.54) | (8.80) | (9.07) | ||||
Operating netback | 25.87 | 0.89 | 15.04 | 31.62 | 1.13 | 20.02 | 33.78 | 45.44 | ||||
General and administration | (1.44) | (1.81) | (1.29) | (2.00) | ||||||||
Fund flows from operations netback | 13.60 | 18.21 | 32.49 | 43.44 | ||||||||
France | ||||||||||||
Sales | 54.88 | 2.81 | 54.20 | 63.31 | 2.52 | 62.67 | 79.25 | 105.43 | ||||
Royalties | (6.23) | (0.32) | (6.15) | (6.06) | (0.33) | (6.00) | (6.07) | (6.95) | ||||
Transportation | (3.72) | - | (3.65) | (3.47) | - | (3.42) | (3.94) | (4.64) | ||||
Operating | (13.55) | (1.81) | (13.50) | (11.34) | (1.31) | (11.30) | (13.01) | (15.09) | ||||
Operating netback | 31.38 | 0.68 | 30.90 | 42.44 | 0.88 | 41.95 | 56.23 | 78.75 | ||||
General and administration | (4.18) | (4.50) | (3.62) | (5.12) | ||||||||
Other income | - | 7.08 | - | - | ||||||||
Current income taxes | 3.87 | (5.29) | (5.89) | (16.36) | ||||||||
Fund flows from operations netback | 30.59 | 39.24 | 46.72 | 57.27 | ||||||||
Netherlands | ||||||||||||
Sales | 48.30 | 7.09 | 42.61 | 49.98 | 7.79 | 46.77 | 52.07 | 52.65 | ||||
Royalties | - | (0.04) | (0.26) | - | (0.19) | (1.12) | (2.40) | (2.13) | ||||
Operating | - | (1.21) | (7.17) | - | (1.39) | (8.24) | (12.70) | (10.22) | ||||
Operating netback | 48.30 | 5.84 | 35.18 | 49.98 | 6.21 | 37.41 | 36.97 | 40.30 | ||||
General and administration | (0.93) | (1.51) | (5.10) | (1.54) | ||||||||
Current income taxes | (3.35) | (4.40) | 4.35 | (1.77) | ||||||||
Fund flows from operations netback | 30.90 | 31.50 | 36.22 | 36.99 | ||||||||
Germany | ||||||||||||
Sales | - | 6.61 | 39.68 | - | 7.18 | 43.10 | 49.19 | 46.03 | ||||
Royalties | - | (0.78) | (4.70) | - | (1.12) | (6.75) | (9.13) | (9.45) | ||||
Transportation | - | (0.34) | (2.05) | - | (0.57) | (3.41) | (0.80) | (2.60) | ||||
Operating | - | (3.22) | (19.31) | - | (1.90) | (11.41) | (10.54) | (9.53) | ||||
Operating netback | - | 2.27 | 13.62 | - | 3.59 | 21.53 | 28.72 | 24.45 | ||||
General and administration | (12.22) | (7.69) | (8.10) | (5.14) | ||||||||
Current income taxes | - | - | 4.21 | (0.05) | ||||||||
Fund flows from operations netback | 1.40 | 13.84 | 24.83 | 19.26 | ||||||||
Australia | ||||||||||||
Sales | 58.74 | - | 58.74 | 70.22 | - | 70.22 | 90.37 | 113.80 | ||||
Operating | (17.08) | - | (17.08) | (22.29) | - | (22.29) | (22.56) | (24.66) | ||||
PRRT (1) | (1.29) | - | (1.29) | (2.97) | - | (2.97) | (17.28) | (24.22) | ||||
Operating netback | 40.37 | - | 40.37 | 44.96 | - | 44.96 | 50.53 | 64.92 | ||||
General and administration | (2.17) | (2.48) | (2.07) | (2.36) | ||||||||
Corporate income taxes | 1.47 | (3.12) | (6.11) | (9.83) | ||||||||
Fund flows from operations netback | 39.67 | 39.36 | 42.35 | 52.73 | ||||||||
United States | ||||||||||||
Sales | 44.83 | 0.52 | 41.94 | 49.10 | 0.52 | 47.53 | 74.08 | 74.08 | ||||
Royalties | (13.19) | (0.30) | (12.40) | (14.36) | (0.30) | (13.93) | (20.38) | (20.38) | ||||
Operating | (6.56) | - | (6.11) | (8.52) | - | (8.23) | (13.44) | (13.44) | ||||
Operating netback | 25.08 | 0.22 | 23.43 | 26.22 | 0.22 | 25.37 | 40.26 | 40.26 | ||||
General and administration | (20.18) | (42.51) | (53.44) | (53.44) | ||||||||
Fund flows from operations netback | 3.25 | (17.14) | (13.18) | (13.18) | ||||||||
Total Company | ||||||||||||
Sales | 51.64 | 4.55 | 41.04 | 58.80 | 4.98 | 47.07 | 63.79 | 77.75 | ||||
Realized hedging gain | 2.69 | 0.84 | 3.71 | 1.32 | 0.53 | 2.07 | 4.76 | 2.01 | ||||
Royalties | (4.32) | (0.16) | (2.85) | (4.58) | (0.24) | (3.30) | (5.41) | (5.92) | ||||
Transportation | (2.09) | (0.23) | (1.78) | (2.30) | (0.30) | (2.09) | (1.98) | (2.32) | ||||
Operating | (13.35) | (1.52) | (11.50) | (13.06) | (1.46) | (11.32) | (12.48) | (12.72) | ||||
PRRT (1) | (0.33) | - | (0.18) | (0.58) | - | (0.34) | (2.83) | (3.30) | ||||
Operating netback | 34.24 | 3.48 | 28.44 | 39.60 | 3.51 | 32.09 | - | 45.85 | - | 55.50 | ||
General and administration | (2.18) | (2.68) | (2.76) | (3.38) | ||||||||
Interest expense | (2.90) | (3.00) | (2.70) | (2.72) | ||||||||
Realized foreign exchange (loss) gain | (0.04) | 0.03 | (0.03) | (0.04) | ||||||||
Other income | 0.04 | 1.64 | 0.04 | 0.04 | ||||||||
Corporate income taxes (1) | 0.55 | (2.22) | (1.73) | (5.31) | ||||||||
Fund flows from operations netback | 23.91 | 25.86 | 38.67 | 44.09 |
(1) | Vermilion considers Australian PRRT to be an operating item and, accordingly, has included PRRT in the calculation of operating netbacks. Current income taxes presented above excludes PRRT. |
Supplemental Table 2: Hedges
The following tables outline Vermilion's outstanding risk management positions as at December 31, 2015:
Note | Volume | Strike Price(s) | |
Crude Oil | |||
WTI - Collar | |||
July 2015 - March 2016 | 1 | 250 bbl/d | 75.00 - 83.45 CAD $ |
July 2015 - June 2016 | 2 | 500 bbl/d | 75.50 - 85.08 CAD $ |
Dated Brent - Collar | |||
July 2015 - June 2016 | 3 | 1,000 bbl/d | 80.50 - 93.49 CAD $ |
July 2015 - June 2016 | 4 | 500 bbl/d | 64.50 - 75.48 US $ |
October 2015 - June 2016 | 5 | 250 bbl/d | 82.00 - 94.55 CAD $ |
January 2016 - June 2016 | 1 | 250 bbl/d | 84.00 - 93.70 CAD $ |
North American Natural Gas | |||
AECO - Collar | |||
November 2015 - March 2016 | 2,500 GJ/d | 2.50 - 3.76 CAD $ | |
November 2015 - October 2016 | 10,000 GJ/d | 2.56 - 3.23 CAD $ | |
January 2016 - December 2016 | 10,000 GJ/d | 2.53 - 3.29 CAD $ | |
April 2016 - October 2016 | 5,000 GJ/d | 2.30 - 2.80 CAD $ | |
AECO Basis - Fixed Price Differential | |||
November 2015 - March 2016 | 2,500 mmbtu/d | Nymex HH less 0.47 US $ | |
Nymex HH - Collar | |||
November 2015 - March 2016 | 6 | 5,000 mmbtu/d | 3.25 - 3.86 US $ |
(1) | The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(2) | The contracted volumes increase to 1,250 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(3) | The contracted volumes increase to 2,500 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(4) | The contracted volumes increase to 1,000 boe/d for any monthly settlement periods above the contracted ceiling price. |
(5) | The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price and are settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(6) | The contracted volumes increase to 10,000 mmbtu/d for any monthly settlement periods above the contracted ceiling price. |
Note | Volume | Strike Price(s) | |
European Natural Gas | |||
NBP - Call | |||
October 2016 - March 2017 | 2,638 GJ/d | 4.64 GBP £ | |
NBP - Collar | |||
April 2016 - March 2017 | 2,638 GJ/d | 3.79 - 4.53 GBP £ | |
January 2017 - December 2017 | 2,638 GJ/d | 3.22 - 3.75 GBP £ | |
January 2018 - December 2018 | 2,638 GJ/d | 2.99 - 3.63 GBP £ | |
NBP - Put | |||
April 2016 - September 2016 | 2,638 GJ/d | 3.79 GBP £ | |
NBP - Swap | |||
July 2015 - March 2016 | 2,592 GJ/d | 6.42 EUR € | |
October 2015 - March 2016 | 10,368 GJ/d | 6.54 EUR € | |
January 2016 - June 2016 | 5,184 GJ/d | 6.24 EUR € | |
January 2016 - June 2016 | 2,592 GJ/d | 6.82 US $ | |
July 2016 - March 2017 | 2,592 GJ/d | 5.43 EUR € | |
January 2017 - December 2017 | 1 | 2,638 GJ/d | 4.00 GBP £ |
January 2018 - December 2018 | 2 | 2,638 GJ/d | 3.83 GBP £ |
TTF - Call | |||
October 2016 - March 2017 | 2,592 GJ/d | 6.03 EUR € | |
TTF - Collar | |||
January 2016 - December 2016 | 3 | 2,592 GJ/d | 5.76 - 6.50 EUR € |
April 2016 - December 2016 | 4 | 12,960 GJ/d | 5.58 - 6.21 EUR € |
April 2016 - March 2017 | 5 | 5,184 GJ/d | 5.28 - 6.35 EUR € |
July 2016 - December 2016 | 2,592 GJ/d | 5.00 - 5.63 EUR € | |
July 2016 - March 2017 | 3 | 2,592 GJ/d | 5.07 - 6.56 EUR € |
July 2016 - March 2018 | 3 | 2,592 GJ/d | 5.32 - 6.54 EUR € |
October 2016 - December 2017 | 2,592 GJ/d | 5.00 - 5.89 EUR € | |
January 2017 - December 2017 | 6 | 7,776 GJ/d | 5.00 - 6.15 EUR € |
January 2018 - December 2018 | 5,184 GJ/d | 4.17 - 5.03 EUR € | |
TTF - Put | |||
April 2016 - September 2016 | 2,592 GJ/d | 5.21 EUR € | |
TTF - Swap | |||
January 2015 - March 2016 | 5,184 GJ/d | 6.40 EUR € | |
January 2015 - June 2016 | 2,592 GJ/d | 6.07 EUR € | |
February 2015 - March 2016 | 5,184 GJ/d | 6.24 EUR € | |
April 2015 - March 2016 | 5,832 GJ/d | 6.18 EUR € | |
October 2015 - March 2016 | 2,592 GJ/d | 6.64 EUR € | |
January 2016 - June 2016 | 5,184 GJ/d | 5.94 EUR € | |
April 2016 - December 2016 | 2,592 GJ/d | 5.91 EUR € | |
July 2016 - June 2018 | 2,700 GJ/d | 5.58 EUR € | |
October 2016 - December 2016 | 2,592 GJ/d | 5.45 EUR € | |
January 2017 - December 2017 | 7 | 2,592 GJ/d | 5.04 EUR € |
Electricity | |||
AESO - Swap | |||
January 2016 - December 2016 | 93.6 MWh/d | 38.58 CAD $ | |
Interest Rate | |||
CDOR to fixed - Swap | |||
September 2015 - September 2019 | 100,000,000 CAD $/year | 1.00 % | |
October 2015 - October 2019 | 100,000,000 CAD $/year | 1.10 % |
(1) | On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 2,638 GJ/d at the contracted price, for the following month. |
(2) | On the last business day of each month, the counterparty has the option to increase the contracted volumes to 7,913 GJ/d at the contracted price, for the following month. |
(3) | The contracted volumes increase to 5,184 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(4) | The contracted volumes increase to 15,552 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(5) | The contracted volumes increase to 10,368 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(6) | The contracted volumes increase to 18,144 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(7) | On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 5,184 GJ/d at the contracted price, for the following month. |
Supplemental Table 3: Capital Expenditures
Three Months Ended | Year Ended | ||||||
By classification | Dec 31, | Sep 30, | Dec 31, | Dec 31, | Dec 31, | ||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | ||
Drilling and development | 128,996 | 93,381 | 151,395 | 486,861 | 618,689 | ||
Exploration and evaluation | - | - | 14,848 | - | 69,035 | ||
Capital expenditures | 128,996 | 93,381 | 166,243 | 486,861 | 687,724 | ||
Property acquisition | 6,227 | 22,155 | 1,652 | 28,897 | 220,726 | ||
Corporate acquisition | - | - | - | - | 381,139 | ||
Acquisitions | 6,227 | 22,155 | 1,652 | 28,897 | 601,865 | ||
Three Months Ended | Year Ended | ||||||
By category | Dec 31, | Sep 30, | Dec 31, | Dec 31, | Dec 31, | ||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | ||
Land | 819 | 763 | 1,457 | 3,793 | 9,506 | ||
Seismic | 4,217 | 810 | 7,598 | 8,243 | 19,034 | ||
Drilling and completion | 58,327 | 39,712 | 69,691 | 212,358 | 311,696 | ||
Production equipment and facilities | 55,662 | 44,589 | 77,272 | 218,963 | 275,538 | ||
Recompletions | 6,338 | 3,948 | 7,696 | 26,689 | 36,234 | ||
Other | 3,633 | 3,559 | 2,529 | 16,815 | 35,716 | ||
Capital expenditures | 128,996 | 93,381 | 166,243 | 486,861 | 687,724 | ||
Acquisitions | 6,227 | 22,155 | 1,652 | 28,897 | 601,865 | ||
Total capital expenditures and acquisitions | 135,223 | 115,536 | 167,895 | 515,758 | 1,289,589 | ||
Three Months Ended | Year Ended | ||||||
By country | Dec 31, | Sep 30, | Dec 31, | Dec 31, | Dec 31, | ||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | ||
Canada | 33,723 | 45,286 | 87,113 | 216,158 | 750,390 | ||
France | 24,164 | 17,511 | 37,189 | 92,582 | 147,852 | ||
Netherlands | 18,810 | 5,297 | 10,022 | 47,325 | 61,740 | ||
Germany | (441) | 1,605 | 563 | 5,363 | 175,618 | ||
Ireland | 12,493 | 20,694 | 20,932 | 66,409 | 94,439 | ||
Australia | 40,852 | 7,966 | 11,616 | 61,741 | 44,283 | ||
United States | 5,622 | 16,011 | 460 | 25,014 | 11,635 | ||
Corporate | - | 1,166 | - | 1,166 | 3,632 | ||
Total capital expenditures and acquisitions | 135,223 | 115,536 | 167,895 | 515,758 | 1,289,589 |
Supplemental Table 4: Production
Q4/15 | Q3/15 | Q2/15 | Q1/15 | Q4/14 | Q3/14 | Q2/14 | Q1/14 | Q4/13 | Q3/13 | Q2/13 | Q1/13 | ||
Canada | |||||||||||||
Crude oil (bbls/d) | 7,964 | 9,195 | 10,182 | 10,893 | 11,384 | 11,469 | 12,676 | 9,437 | 8,719 | 7,969 | 8,885 | 7,966 | |
NGLs (bbls/d) | 5,159 | 4,513 | 3,755 | 2,976 | 2,741 | 2,291 | 2,796 | 2,071 | 1,699 | 1,897 | 1,725 | 1,335 | |
Natural gas (mmcf/d) | 87.90 | 71.94 | 64.66 | 61.78 | 58.36 | 57.07 | 57.59 | 49.53 | 41.43 | 43.40 | 43.69 | 41.04 | |
Total (boe/d) | 27,773 | 25,698 | 24,713 | 24,165 | 23,851 | 23,272 | 25,070 | 19,763 | 17,322 | 17,099 | 17,892 | 16,140 | |
% of consolidated | 45% | 47% | 48% | 48% | 49% | 47% | 49% | 42% | 43% | 41% | 42% | 41% | |
France | |||||||||||||
Crude oil (bbls/d) | 12,537 | 12,310 | 12,746 | 11,463 | 11,133 | 11,111 | 11,025 | 10,771 | 11,131 | 11,625 | 10,390 | 10,330 | |
Natural gas (mmcf/d) | 1.36 | 1.47 | 1.03 | - | - | - | - | - | - | 5.23 | 4.19 | 4.21 | |
Total (boe/d) | 12,763 | 12,555 | 12,917 | 11,463 | 11,133 | 11,111 | 11,025 | 10,771 | 11,131 | 12,496 | 11,088 | 11,032 | |
% of consolidated | 21% | 22% | 25% | 23% | 22% | 22% | 21% | 23% | 27% | 30% | 26% | 29% | |
Netherlands | |||||||||||||
NGLs (bbls/d) | 110 | 109 | 112 | 63 | 81 | 63 | 96 | 69 | 62 | 48 | 50 | 96 | |
Natural gas (mmcf/d) | 56.34 | 53.56 | 32.43 | 36.41 | 31.35 | 38.07 | 40.35 | 43.15 | 37.53 | 28.78 | 38.52 | 36.91 | |
Total (boe/d) | 9,500 | 9,035 | 5,517 | 6,132 | 5,306 | 6,407 | 6,822 | 7,260 | 6,318 | 4,845 | 6,470 | 6,248 | |
% of consolidated | 16% | 16% | 11% | 12% | 11% | 13% | 13% | 16% | 15% | 12% | 15% | 16% | |
Germany | |||||||||||||
Natural gas (mmcf/d) | 16.17 | 14.00 | 16.18 | 16.80 | 17.71 | 15.38 | 16.13 | 10.64 | - | - | - | - | |
Total (boe/d) | 2,695 | 2,333 | 2,696 | 2,801 | 2,952 | 2,563 | 2,689 | 1,773 | - | - | - | - | |
% of consolidated | 4% | 4% | 5% | 6% | 6% | 5% | 5% | 4% | - | - | - | - | |
Ireland | |||||||||||||
Natural gas (mmcf/d) | 0.12 | - | - | - | - | - | - | - | - | - | - | - | |
Total (boe/d) | 20 | - | - | - | - | - | - | - | - | - | - | - | |
% of consolidated | - | - | - | - | - | - | - | - | - | - | - | - | |
Australia | |||||||||||||
Crude oil (bbls/d) | 7,824 | 6,433 | 5,865 | 5,672 | 6,134 | 6,567 | 6,483 | 7,110 | 6,189 | 7,070 | 7,363 | 5,287 | |
% of consolidated | 13% | 11% | 11% | 11% | 12% | 13% | 12% | 15% | 15% | 17% | 17% | 14% | |
United States | |||||||||||||
Crude oil (bbls/d) | 420 | 226 | 123 | 153 | 195 | - | - | - | - | - | - | - | |
NGLs (bbls/d) | 29 | - | - | - | - | - | - | - | - | - | - | - | |
Natural gas (mmcf/d) | 0.20 | - | - | - | - | - | - | - | - | - | - | - | |
Total (boe/d) | 483 | 226 | 123 | 153 | 195 | - | - | - | - | - | - | - | |
% of consolidated | 1% | - | - | - | - | - | - | - | - | - | - | - | |
Consolidated | |||||||||||||
Crude oil & NGLs (bbls/d) | 34,043 | 32,786 | 32,783 | 31,220 | 31,668 | 31,501 | 33,076 | 29,458 | 27,800 | 28,609 | 28,413 | 25,014 | |
% of consolidated | 56% | 58% | 63% | 62% | 64% | 63% | 63% | 63% | 68% | 69% | 66% | 65% | |
Natural gas (mmcf/d) | 162.09 | 140.97 | 114.29 | 115.00 | 107.42 | 110.52 | 114.08 | 103.32 | 78.96 | 77.41 | 86.40 | 82.16 | |
% of consolidated | 44% | 42% | 37% | 38% | 36% | 37% | 37% | 37% | 32% | 31% | 34% | 35% | |
Total (boe/d) | 61,058 | 56,280 | 51,831 | 50,386 | 49,571 | 49,920 | 52,089 | 46,677 | 40,960 | 41,510 | 42,813 | 38,707 |
2015 | 2014 | 2013 | 2012 | 2011 | 2010 | ||
Canada | |||||||
Crude oil (bbls/d) | 9,550 | 11,248 | 8,387 | 7,659 | 4,701 | 2,778 | |
NGLs (bbls/d) | 4,108 | 2,476 | 1,666 | 1,232 | 1,297 | 1,427 | |
Natural gas (mmcf/d) | 71.65 | 55.67 | 42.39 | 37.50 | 43.38 | 43.91 | |
Total (boe/d) | 25,598 | 23,001 | 17,117 | 15,142 | 13,227 | 11,524 | |
% of consolidated | 46% | 47% | 41% | 40% | 38% | 36% | |
France | |||||||
Crude oil (bbls/d) | 12,267 | 11,011 | 10,873 | 9,952 | 8,110 | 8,347 | |
Natural gas (mmcf/d) | 0.97 | - | 3.40 | 3.59 | 0.95 | 0.92 | |
Total (boe/d) | 12,429 | 11,011 | 11,440 | 10,550 | 8,269 | 8,501 | |
% of consolidated | 23% | 22% | 28% | 28% | 23% | 26% | |
Netherlands | |||||||
NGLs (bbls/d) | 99 | 77 | 64 | 67 | 58 | 35 | |
Natural gas (mmcf/d) | 44.76 | 38.20 | 35.42 | 34.11 | 32.88 | 28.31 | |
Total (boe/d) | 7,559 | 6,443 | 5,967 | 5,751 | 5,538 | 4,753 | |
% of consolidated | 14% | 13% | 15% | 15% | 16% | 15% | |
Germany | |||||||
Natural gas (mmcf/d) | 15.78 | 14.99 | - | - | - | - | |
Total (boe/d) | 2,630 | 2,498 | - | - | - | - | |
% of consolidated | 5% | 5% | - | - | - | - | |
Ireland | |||||||
Natural gas (mmcf/d) | 0.03 | - | - | - | - | - | |
Total (boe/d) | 5 | - | - | - | - | - | |
% of consolidated | - | - | - | - | - | - | |
Australia | |||||||
Crude oil (bbls/d) | 6,454 | 6,571 | 6,481 | 6,360 | 8,168 | 7,354 | |
% of consolidated | 12% | 13% | 16% | 17% | 23% | 23% | |
United States | |||||||
Crude oil (bbls/d) | 231 | 49 | - | - | - | - | |
NGLs (bbls/d) | 7 | - | |||||
Natural gas (mmcf/d) | 0.05 | - | - | - | - | - | |
Total (boe/d) | 247 | 49 | - | - | - | - | |
% of consolidated | - | - | - | - | - | - | |
Consolidated | |||||||
Crude oil & NGLs (bbls/d) | 32,716 | 31,432 | 27,471 | 25,270 | 22,334 | 19,941 | |
% of consolidated | 60% | 63% | 67% | 67% | 63% | 62% | |
Natural gas (mmcf/d) | 133.24 | 108.85 | 81.21 | 75.20 | 77.21 | 73.14 | |
% of consolidated | 40% | 37% | 33% | 33% | 37% | 38% | |
Total (boe/d) | 54,922 | 49,573 | 41,005 | 37,803 | 35,202 | 32,132 |
Supplemental Table 5: Segmented Financial Results
Three Months Ended December 31, 2015 | |||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia | United States | Corporate | Total | ||||||||
Drilling and development | 27,554 | 24,085 | 18,810 | (441) | 12,493 | 40,852 | 5,643 | - | 128,996 | ||||||||
Oil and gas sales to external customers | 73,952 | 63,411 | 37,243 | 9,840 | 57 | 47,952 | 1,864 | - | 234,319 | ||||||||
Royalties | (7,146) | (7,198) | (224) | (1,166) | - | - | (551) | - | (16,285) | ||||||||
Revenue from external customers | 66,806 | 56,213 | 37,019 | 8,674 | 57 | 47,952 | 1,313 | - | 218,034 | ||||||||
Transportation expense | (3,784) | (4,275) | - | (508) | (1,580) | - | - | - | (10,147) | ||||||||
Operating expense | (24,575) | (15,792) | (6,263) | (4,788) | (15) | (13,941) | (271) | - | (65,645) | ||||||||
General and administration | (3,669) | (4,894) | (813) | (3,032) | (714) | (1,768) | (897) | 3,356 | (12,431) | ||||||||
PRRT | - | - | - | - | - | (1,054) | - | - | (1,054) | ||||||||
Corporate income taxes | - | 4,529 | (2,930) | - | - | 1,201 | - | 313 | 3,113 | ||||||||
Interest expense | - | - | - | - | - | - | - | (16,584) | (16,584) | ||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 21,164 | 21,164 | ||||||||
Realized foreign exchange loss | - | - | - | - | - | - | - | (252) | (252) | ||||||||
Realized other income | - | - | - | - | - | - | - | 243 | 243 | ||||||||
Fund flows from operations | 34,778 | 35,781 | 27,013 | 346 | (2,252) | 32,390 | 145 | 8,240 | 136,441 | ||||||||
Year Ended December 31, 2015 | |||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia | United States | Corporate | Total | ||||||||
Total assets | 1,609,180 | 863,304 | 212,749 | 167,908 | 908,453 | 235,139 | 42,927 | 169,560 | 4,209,220 | ||||||||
Drilling and development | 201,508 | 92,265 | 47,325 | 5,363 | 66,409 | 61,741 | 12,250 | - | 486,861 | ||||||||
Oil and gas sales to external customers | 320,613 | 281,422 | 129,057 | 41,384 | 57 | 162,765 | 4,288 | - | 939,586 | ||||||||
Royalties | (28,144) | (26,958) | (3,082) | (6,479) | - | - | (1,257) | - | (65,920) | ||||||||
Revenue from external customers | 292,469 | 254,464 | 125,975 | 34,905 | 57 | 162,765 | 3,031 | - | 873,666 | ||||||||
Transportation expense | (16,326) | (15,378) | - | (3,269) | (6,687) | - | - | - | (41,660) | ||||||||
Operating expense | (89,085) | (50,718) | (22,746) | (10,956) | (15) | (51,676) | (742) | - | (225,938) | ||||||||
General and administration | (16,888) | (20,217) | (4,158) | (7,386) | (2,517) | (5,754) | (3,836) | 7,172 | (53,584) | ||||||||
PRRT | - | - | - | - | - | (6,878) | - | - | (6,878) | ||||||||
Corporate income taxes | - | (23,764) | (12,152) | - | - | (7,230) | - | (1,091) | (44,237) | ||||||||
Interest expense | - | - | - | - | - | - | - | (59,852) | (59,852) | ||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 41,356 | 41,356 | ||||||||
Realized foreign exchange gain | - | - | - | - | - | - | - | 623 | 623 | ||||||||
Realized other income | - | 31,775 | - | - | - | - | - | 896 | 32,671 | ||||||||
Fund flows from operations | 170,170 | 176,162 | 86,919 | 13,294 | (9,162) | 91,227 | (1,547) | (10,896) | 516,167 |
NON-GAAP FINANCIAL MEASURES
This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS and are not disclosed in our audited consolidated financial statements. As such, these financial measures are considered non-GAAP financial measures and therefore may not be comparable with similar measures presented by other issuers.
Fund flows from operations per basic and diluted share: Management assesses fund flows from operations on a per share basis as we believe this provides a measure of our operating performance after taking into account the issuance and potential future issuance of Vermilion common shares. Fund flows from operations per basic share is calculated by dividing fund flows from operations by the basic weighted average shares outstanding as defined under IFRS. Fund flows from operations per diluted share is calculated by dividing fund flows from operations by the sum of basic weighted average shares outstanding and incremental shares issuable under our equity based compensation plans as determined using the treasury stock method.
Free cash flow: Represents fund flows from operations in excess of capital expenditures. We consider free cash flow to be a key measure as it is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures.
Net dividends: We define net dividends as dividends declared less proceeds received for the issuance of shares pursuant to the dividend reinvestment plan. Management monitors net dividends and net dividends as a percentage of fund flows from operations to assess our ability to pay dividends.
Payout: We define payout as net dividends plus drilling and development, exploration and evaluation, dispositions and asset retirement obligations settled. Management uses payout to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.
Fund flows from operations (excluding Corrib) and Payout (excluding Corrib): Management excludes expenditures relating to the Corrib project in assessing fund flows from operations (a non-GAAP financial measure) and payout in order to assess our ability to generate cash and finance organic growth from our current producing assets.
Diluted shares outstanding: Is the sum of shares outstanding at the period end plus outstanding awards under the VIP, based on current estimates of future performance factors and forfeiture rates.
Cash dividends per share: Represents cash dividends declared per share.
Total returns: Includes cash dividends per share and the change in Vermilion's share price on the Toronto Stock Exchange.
The following tables reconcile fund flows from operations (excluding Corrib), net dividends, payout, and diluted shares outstanding to their most directly comparable GAAP measures as presented in our financial statements:
Three Months Ended | Year Ended | |||||||
Dec 31, | Sep 30, | Dec 31, | Dec 31, | Dec 31, | ||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | |||
Cash flows from operating activities | 164,863 | 122,230 | 229,146 | 444,408 | 791,986 | |||
Changes in non-cash operating working capital | (33,343) | 5,082 | (49,865) | 60,390 | (3,077) | |||
Asset retirement obligations settled | 4,921 | 2,123 | 6,247 | 11,369 | 15,956 | |||
Fund flows from operations | 136,441 | 129,435 | 185,528 | 516,167 | 804,865 | |||
Expenses related to Corrib | 2,252 | 2,429 | 2,299 | 9,162 | 7,841 | |||
Fund flows from operations (excluding Corrib) | 138,693 | 131,864 | 187,827 | 525,329 | 812,706 | |||
Three Months Ended | Year Ended | |||||||
Dec 31, | Sep 30, | Dec 31, | Dec 31, | Dec 31, | ||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | |||
Dividends declared | 71,965 | 71,244 | 69,119 | 283,575 | 272,732 | |||
Issuance of shares pursuant to the dividend reinvestment and Premium DividendTM plans |
(46,764) | (44,590) | (20,980) | (155,033) | (79,430) | |||
Net dividends | 25,201 | 26,654 | 48,139 | 128,542 | 193,302 | |||
Drilling and development | 128,996 | 93,381 | 151,395 | 486,861 | 618,689 | |||
Exploration and evaluation | - | - | 14,848 | - | 69,035 | |||
Asset retirement obligations settled | 4,921 | 2,123 | 6,247 | 11,369 | 15,956 | |||
Payout | 159,118 | 122,158 | 220,629 | 626,772 | 896,982 | |||
Corrib drilling and development | (12,493) | (20,694) | (20,932) | (66,409) | (94,439) | |||
Payout (excluding Corrib) | 146,625 | 101,464 | 199,697 | 560,363 | 802,543 | |||
As at | ||||||||
Dec 31, | Sep 30, | Dec 31, | ||||||
('000s of shares) | 2015 | 2015 | 2014 | |||||
Shares outstanding | 111,991 | 110,818 | 107,303 | |||||
Potential shares issuable pursuant to the VIP | 3,033 | 2,825 | 3,031 | |||||
Diluted shares outstanding | 115,024 | 113,643 | 110,334 |
MANAGEMENT'S REPORT TO SHAREHOLDERS
Management's Responsibility for Financial Statements
The accompanying consolidated financial statements of Vermilion Energy Inc. are the responsibility of management and have been approved by the Board of Directors of Vermilion Energy Inc. The consolidated financial statements have been prepared in accordance with the accounting policies detailed in the notes to the consolidated financial statements and are prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Where necessary, management has made informed judgments and estimates of transactions that were not yet completed at the balance sheet date. Financial information throughout the Annual Report is consistent with the consolidated financial statements.
Management ensures the integrity of the consolidated financial statements by maintaining high-quality systems of internal control. Procedures and policies are designed to provide reasonable assurance that assets are safeguarded and transactions are properly recorded, and that the financial records are reliable for preparation of the consolidated financial statements. Deloitte LLP, Vermilion's external auditors, have conducted an audit of the consolidated financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) and have provided their report.
The Board of Directors is responsible for ensuring that management fulfills its responsibility for financial reporting and internal control. The Board carries out this responsibility principally through the Audit Committee, which is appointed by the Board and is comprised entirely of independent Directors. The Committee meets periodically with management and Deloitte LLP to satisfy itself that each party is properly discharging its responsibilities and to review the consolidated financial statements, the Management's Discussion and Analysis and the external Auditor's Report before they are presented to the Board of Directors.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the criteria established in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has assessed the effectiveness of Vermilion's internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Management concluded that Vermilion's internal control over financial reporting was effective as of December 31, 2015. The effectiveness of Vermilion's internal control over financial reporting as of December 31, 2015 has been audited by Deloitte LLP, the Company's Independent Registered Public Accounting Firm, who also audited the Company's consolidated financial statements for the year ended December 31, 2015.
("Lorenzo Donadeo") | ("Curtis W. Hicks") | ||||||||
Lorenzo Donadeo Chief Executive Officer February 25, 2016 |
Curtis W. Hicks Executive Vice President & Chief Financial Officer |
||||||||
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Vermilion Energy Inc.
We have audited the internal control over financial reporting of Vermilion Energy Inc. and subsidiaries (the "Company") as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015 of the Company and our report dated February 26, 2016 expressed an unqualified opinion on those financial statements.
("/s/Deloitte LLP") |
Chartered Professional Accountants, Chartered Accountants February 26, 2016 Calgary, Canada |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Vermilion Energy Inc.
We have audited the accompanying consolidated financial statements of Vermilion Energy Inc. and subsidiaries (the "Company"), which comprise the consolidated balance sheets as at December 31, 2015 and December 31, 2014, and the consolidated statements of net earnings (loss) and comprehensive income (loss), cash flows, and changes in shareholders' equity for the years then ended, and a summary of significant accounting policies and other explanatory information.
Management's Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditor's Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Vermilion Energy Inc. and subsidiaries as at December 31, 2015 and December 31, 2014, and their financial performance and their cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.
Other Matter
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the Company's
internal control over financial reporting as of December 31, 2015,
based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 26, 2016 expressed an
unmodified opinion on the Company's internal control over financial
reporting.
(To be signed "/s/Deloitte LLP") |
Chartered Professional Accountants, Chartered Accountants February 26, 2016 Calgary, Canada |
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS)
December 31, | December 31, | ||||
Note | 2015 | 2014 | |||
ASSETS | |||||
Current | |||||
Cash and cash equivalents | 17 | 41,676 | 120,405 | ||
Accounts receivable | 160,499 | 171,820 | |||
Crude oil inventory | 13,079 | 9,510 | |||
Derivative instruments | 13 | 55,214 | 23,391 | ||
Prepaid expenses | 14,310 | 13,033 | |||
284,778 | 338,159 | ||||
Derivative instruments | 13 | 13,128 | 1,403 | ||
Deferred taxes | 9 | 135,753 | 154,816 | ||
Exploration and evaluation assets | 6 | 308,192 | 380,621 | ||
Capital assets | 5 | 3,467,369 | 3,511,092 | ||
4,209,220 | 4,386,091 | ||||
LIABILITIES | |||||
Current | |||||
Accounts payable and accrued liabilities | 248,747 | 298,196 | |||
Current portion of long-term debt | 8 | 224,901 | - | ||
Dividends payable | 10 | 24,077 | 23,070 | ||
Income taxes payable | 9 | 6,006 | 44,463 | ||
503,731 | 365,729 | ||||
Long-term debt | 8 | 1,162,998 | 1,238,080 | ||
Finance lease obligation | 16 | 23,565 | - | ||
Asset retirement obligations | 7 | 305,613 | 350,753 | ||
Deferred taxes | 9 | 354,654 | 410,183 | ||
2,350,561 | 2,364,745 | ||||
SHAREHOLDERS' EQUITY | |||||
Shareholders' capital | 10 | 2,181,089 | 1,959,021 | ||
Contributed surplus | 107,946 | 92,188 | |||
Accumulated other comprehensive income | 113,647 | 5,722 | |||
Deficit | (544,023) | (35,585) | |||
1,858,659 | 2,021,346 | ||||
4,209,220 | 4,386,091 |
APPROVED BY THE BOARD | ||||||
(Signed "Joseph F. Killi") | (Signed "Lorenzo Donadeo") | |||||
Joseph F. Killi, Director | Lorenzo Donadeo, Director |
CONSOLIDATED STATEMENTS OF NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME
(LOSS)
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS)
Year Ended | |||||
December 31, | December 31, | ||||
Note | 2015 | 2014 | |||
REVENUE | |||||
Petroleum and natural gas sales | 939,586 | 1,419,628 | |||
Royalties | (65,920) | (108,000) | |||
Petroleum and natural gas revenue | 873,666 | 1,311,628 | |||
EXPENSES | |||||
Operating | 21 | 225,938 | 232,307 | ||
Transportation | 41,660 | 42,361 | |||
Equity based compensation | 11 | 75,232 | 67,802 | ||
Gain on derivative instruments | 13 | (84,904) | (64,083) | ||
Interest expense | 59,852 | 49,655 | |||
General and administration | 21 | 53,584 | 61,727 | ||
Foreign exchange (gain) loss | (9,410) | 18,420 | |||
Other (income) expense | (31,663) | 760 | |||
Accretion | 7 | 23,911 | 23,913 | ||
Depletion and depreciation | 5, 6 | 458,758 | 425,694 | ||
Impairment | 5, 6 | 274,623 | - | ||
1,087,581 | 858,556 | ||||
EARNINGS (LOSS) BEFORE INCOME TAXES | (213,915) | 453,072 | |||
INCOME TAXES | 9 | ||||
Deferred | (47,728) | 26,410 | |||
Current | 51,115 | 157,336 | |||
3,387 | 183,746 | ||||
NET EARNINGS (LOSS) | (217,302) | 269,326 | |||
OTHER COMPREHENSIVE (LOSS) INCOME | |||||
Currency translation adjustments | 107,925 | (41,420) | |||
COMPREHENSIVE (LOSS) INCOME | (109,377) | 227,906 | |||
NET EARNINGS (LOSS) PER SHARE | 12 | ||||
Basic | (1.98) | 2.55 | |||
Diluted | (1.98) | 2.51 | |||
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s) | 12 | ||||
Basic | 109,642 | 105,448 | |||
Diluted | 109,642 | 107,187 |
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS)
Year Ended | ||||||
December 31, | December 31, | |||||
Note | 2015 | 2014 | ||||
OPERATING | ||||||
Net earnings (loss) | (217,302) | 269,326 | ||||
Adjustments: | ||||||
Accretion | 7 | 23,911 | 23,913 | |||
Depletion and depreciation | 5, 6 | 458,758 | 425,694 | |||
Impairment | 5, 6 | 274,623 | - | |||
Unrealized gain on derivative instruments | 13 | (43,548) | (27,371) | |||
Equity based compensation | 11 | 75,232 | 67,802 | |||
Unrealized foreign exchange (gain) loss | (8,787) | 17,599 | ||||
Unrealized other expense | 1,008 | 1,492 | ||||
Deferred taxes | 9 | (47,728) | 26,410 | |||
Asset retirement obligations settled | 7 | (11,369) | (15,956) | |||
Changes in non-cash operating working capital | 14 | (60,390) | 3,077 | |||
Cash flows from operating activities | 444,408 | 791,986 | ||||
INVESTING | ||||||
Drilling and development | 5 | (486,861) | (618,689) | |||
Exploration and evaluation | 6 | - | (69,035) | |||
Property acquisitions | 4, 5, 6 | (28,897) | (220,726) | |||
Corporate acquisitions, net of cash acquired | 4 | - | (176,179) | |||
Changes in non-cash investing working capital | 14 | (25,980) | 12,365 | |||
Cash flows used in investing activities | (541,738) | (1,072,264) | ||||
FINANCING | ||||||
Increase in long-term debt | 8 | 138,341 | 196,387 | |||
Decrease in finance lease obligation | 16 | (2,246) | - | |||
Cash dividends | 10 | (127,535) | (190,657) | |||
Cash flows from financing activities | 8,560 | 5,730 | ||||
Foreign exchange gain on cash held in foreign currencies | 10,041 | 5,394 | ||||
Net change in cash and cash equivalents | (78,729) | (269,154) | ||||
Cash and cash equivalents, beginning of year | 120,405 | 389,559 | ||||
Cash and cash equivalents, end of year | 17 | 41,676 | 120,405 | |||
Supplementary information for operating activities - cash payments | ||||||
Interest paid | 62,911 | 50,801 | ||||
Income taxes paid | 92,907 | 166,993 |
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS)
Accumulated | ||||||||||||
Other | Total | |||||||||||
Shareholders' | Contributed | Comprehensive | Shareholders' | |||||||||
Note | Capital | Surplus | Income | Deficit | Equity | |||||||
Balances as at January 1, 2014 | 1,618,443 | 75,427 | 47,142 | (24,637) | 1,716,375 | |||||||
Net earnings | - | - | - | 269,326 | 269,326 | |||||||
Currency translation adjustments | - | - | (41,420) | - | (41,420) | |||||||
Equity based compensation expense | 11 | - | 67,081 | - | - | 67,081 | ||||||
Dividends declared | 10 | - | - | - | (272,732) | (272,732) | ||||||
Shares issued pursuant to the | ||||||||||||
dividend reinvestment plan | 10 | 79,430 | - | - | - | 79,430 | ||||||
Shares issued pursuant to | ||||||||||||
corporate acquisition | 4, 10 | 204,960 | - | - | - | 204,960 | ||||||
Modification of equity based awards | 11 | - | (2,395) | - | - | (2,395) | ||||||
Vesting of equity based awards | 10, 11 | 47,925 | (47,925) | - | - | - | ||||||
Share-settled dividends | ||||||||||||
on vested equity based awards | 10, 11 | 7,542 | - | - | (7,542) | - | ||||||
Shares issued pursuant to the bonus plan | 10 | 721 | - | - | - | 721 | ||||||
Balances as at December 31, 2014 | 1,959,021 | 92,188 | 5,722 | (35,585) | 2,021,346 | |||||||
Accumulated | ||||||||||||
Other | Total | |||||||||||
Shareholders' | Contributed | Comprehensive | Shareholders' | |||||||||
Note | Capital | Surplus | Income | Deficit | Equity | |||||||
Balances as at January 1, 2015 | 1,959,021 | 92,188 | 5,722 | (35,585) | 2,021,346 | |||||||
Net loss | - | - | - | (217,302) | (217,302) | |||||||
Currency translation adjustments | - | - | 107,925 | - | 107,925 | |||||||
Equity based compensation expense | 11 | - | 72,613 | - | - | 72,613 | ||||||
Dividends declared | 10 | - | - | - | (283,575) | (283,575) | ||||||
Shares issued pursuant to the | ||||||||||||
dividend reinvestment and Premium | ||||||||||||
DividendTM plans | 10 | 155,033 | - | - | - | 155,033 | ||||||
Vesting of equity based awards | 10, 11 | 56,855 | (56,855) | - | - | - | ||||||
Share-settled dividends | ||||||||||||
on vested equity based awards | 10, 11 | 7,561 | - | - | (7,561) | - | ||||||
Shares issued pursuant to the employee | ||||||||||||
savings and bonus plans | 10 | 2,619 | - | - | - | 2,619 | ||||||
Balances as at December 31, 2015 | 2,181,089 | 107,946 | 113,647 | (544,023) | 1,858,659 |
DESCRIPTION OF EQUITY RESERVES
Shareholders' capital
Represents the recognized amount for common shares when issued, net of
equity issuance costs and deferred taxes.
Contributed surplus
Represents the recognized value of employee awards which are settled in
shares. Once vested, the value of the awards is transferred to
shareholders' capital.
Accumulated other comprehensive income
Represents the cumulative income and expenses which are not recorded
immediately in net earnings (loss) and are accumulated until an event
triggers recognition in net earnings (loss). The current balance
consists of currency translation adjustments resulting from translating
financial statements of subsidiaries with a foreign functional currency
to Canadian dollars at period-end rates.
Deficit
Represents the cumulative net earnings (loss) less distributed earnings
of Vermilion Energy Inc.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2015 AND 2014
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER
SHARE AMOUNTS)
1. BASIS OF PRESENTATION
Vermilion Energy Inc. (the "Company" or "Vermilion") is a corporation governed by the laws of the Province of Alberta and is actively engaged in the business of crude oil and natural gas exploration, development, acquisition and production.
These consolidated financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on February 25, 2016.
2. SIGNIFICANT ACCOUNTING POLICIES
Accounting Framework
The consolidated financial statements have been prepared in accordance
with International Financial Reporting Standards ("IFRS") as issued by
the International Accounting Standards Board ("IASB").
Principles of Consolidation
Subsidiaries that are directly controlled by the parent company or
indirectly controlled through other consolidated subsidiaries are fully
consolidated. Vermilion accounts for joint operations by recognizing
its share of assets, liabilities, income and expenses. All significant
intercompany balances, transactions, income and expenses are eliminated
upon consolidation.
Vermilion currently has no special purpose entities of which it retains control and accordingly the consolidated financial statements do not include the accounts of any such entities.
Exploration and Evaluation Assets
Vermilion accounts for exploration and evaluation of petroleum and
natural gas property ("E&E") costs in accordance with IFRS 6
"Exploration for and Evaluation of Mineral Resources". Costs incurred
are classified as E&E costs when they relate to exploring and
evaluating a property for which the Company has the licence or right to
explore and extract resources.
E&E costs related to each license or prospect area are initially capitalized within E&E assets. E&E costs that are capitalized may include costs of licence acquisitions, technical services and studies, seismic acquisitions, exploration drilling and testing, directly attributable overhead and administration expenses and, if applicable, the estimated costs of retiring the assets. Any costs incurred prior to the acquisition of the legal rights to explore an area are expensed as incurred.
E&E assets are not initially depleted and are carried at cost until technical feasibility and commercial viability of the area can be determined. The technical feasibility and commercial viability of extracting the reserves is considered to be determinable when proven and probable reserves are identified. If proven and probable reserves are identified as recoverable, the related E&E costs are reclassified to Petroleum and Natural Gas ("PNG") assets pending an impairment test. If reserves are not found within the license area or the area is abandoned, the related E&E costs are amortized over a period not greater than five years.
Petroleum and Natural Gas Assets
Vermilion recognizes PNG assets at cost less accumulated depletion,
depreciation and impairment losses. Directly attributable costs
incurred for the drilling of development wells and for the construction
of production facilities are capitalized together with the discounted
value of estimated future costs of asset retirement obligations. When
components of PNG assets are replaced, disposed of, or no longer in
use, they are derecognized.
Gains and losses on disposal of a component of PNG assets, including oil and gas interests, are determined by comparing the proceeds of disposal with the carrying amount of the component, and are recognized in net earnings (loss).
Depletion and Depreciation
Vermilion classifies its assets into PNG depletion units, which are
groups of assets or properties that are within a specific production
area and have similar economic lives. The PNG depletion units
represent the lowest level of disaggregation for which Vermilion
accumulates costs for the purposes of calculating and recording
depletion and depreciation.
The net carrying value of each PNG depletion unit is depleted using the unit of production method by reference to the ratio of production in the period to the total proven and probable reserves, taking into account the future development costs necessary to bring the applicable reserves into production. The reserve estimates are reviewed annually by management or when material changes occur to the underlying assumptions.
For the purposes of the depletion calculations, oil and gas reserves are converted to a common unit of measure on the basis of their relative energy content based on a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent.
Furniture and office equipment are recorded at cost and are depreciated on a declining-balance basis.
Impairment of Long-Lived Assets
E&E assets are tested for impairment when reclassified to PNG assets or
when indicators of impairment are identified. If indicators of
impairment are identified, E&E assets are tested for impairment as part
of the group of Cash Generating Units ("CGUs") attributable to the
jurisdiction in which the exploration area resides.
PNG depletion units are aggregated into CGUs for impairment testing. The determination of CGUs is based on management's judgment and represents the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets or properties. CGUs are reviewed for indicators that the carrying value of the CGU may exceed its recoverable amount. If an indication of impairment exists, the CGU's recoverable amount is then estimated. A CGU's recoverable amount is defined as the higher of the fair value less costs to sell and its value in use. If the carrying amount exceeds its recoverable amount, an impairment loss is recorded to net earnings (loss) in the period to reduce the carrying value of the CGU to its recoverable amount.
For PNG assets and E&E assets, when there has been an impairment loss recognized, at each reporting date an assessment is performed as to whether the circumstances which led to the impairment loss have reversed. If the change in circumstances leads to the recoverable amount being higher than the carrying value after recognition of an impairment, that impairment loss is reversed, with such reversal not to exceed the depreciated value of the asset had no impairment loss been previously recognized.
Finance leases
Finance leases, which transfer substantially all the risks and rewards
incidental to legal ownership, are recognized at the commencement of
the least term. The lease obligation and corresponding capitalized
lease asset are measured at the lower of fair value of the leased
property or the present value of the minimum lease payments, which are
determined at the inception of the lease. Capitalized leased assets are
depreciated over the shorter of the estimated useful life of the asset
or the lease term.
Cash and Cash Equivalents
Cash and cash equivalents include monies on deposit and short-term
investments, which are comprised primarily of guaranteed investment
certificates.
Crude Oil Inventory
Inventories of crude oil, consisting of production for which title has
not yet transferred to the customer, are valued at the lower of cost or
net realizable value. Cost is determined on a weighted-average basis
and includes related operating expenses, royalties, and depletion.
Provisions and Asset Retirement Obligations
Vermilion recognizes a provision or asset retirement obligation in the
consolidated financial statements when an event gives rise to an
obligation of uncertain timing or amount.
The estimated present value of the asset retirement obligation is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. This increase is depleted with the related depletion unit and is allocated to a CGU for impairment testing. The liability recorded is increased each reporting period due to the passage of time and this change is charged to net earnings (loss) in the period as accretion expense. The asset retirement obligation can also increase or decrease due to changes in the estimated timing of cash flows, changes in the discount rate and/or changes in the original estimated undiscounted costs. Increases or decreases in the obligation will result in a corresponding change in the carrying amount of the related asset. Actual costs incurred upon settlement of the asset retirement obligation are charged against the asset retirement obligation to the extent of the liability recorded. Vermilion discounts the costs related to asset retirement obligations using the discount rate that reflects current market assessment of the time value of money and risks specific to the liabilities that have not been reflected in the cash flow estimates. Vermilion applies discount rates applicable to each of the jurisdictions in which it has future asset retirement obligations. Asset retirement obligations are remeasured at each reporting period in order to reflect the discount rates in effect at that time.
A provision for onerous contracts is recognized when the expected benefits to be derived by Vermilion from a contract are lower than the unavoidable cost of meeting the obligations under the contract. The provision is measured at the lower of the expected cost of terminating the contract and the present value of the expected net cost of the remaining term of the contract. Before a provision is established, Vermilion first recognizes any impairment loss on assets associated with the onerous contract. For the periods presented in the consolidated financial statements, there were no onerous contracts recognized.
Revenue Recognition
Revenues associated with the sale of crude oil, natural gas and natural
gas liquids are recorded when title passes to the customer. For the
majority of Canadian oil and natural gas production, legal title
transfers upon delivery to major pipelines. In Australia, oil is sold
at the Wandoo B Platform. In the Netherlands, natural gas is sold at
the plant gate. In Germany, natural gas is sold upon delivery to major
pipelines. In France, oil is sold either when delivered to the refinery
by pipeline or when delivered to the refinery via tanker. In the United
States, oil is sold when transferred to the truck from the tank and
natural gas is sold at a custody transfer meter on location.
Financial Instruments
Cash and cash equivalents are classified as held for trading and are
measured at fair value. A gain or loss arising from a change in the
fair value is recognized in net earnings (loss) in the period in which
it occurs.
Accounts receivable are classified as loans and receivables and are initially measured at fair value and are then subsequently measured at amortized cost. The carrying value of accounts receivable approximates the fair value due to the short-term nature of these instruments.
Accounts payable and accrued liabilities, dividends payable, finance lease, and long-term debt have been classified as other financial liabilities and are initially recognized at fair value and are subsequently measured at amortized cost. Transaction costs and discounts are recorded against the fair value of long-term debt on initial recognition.
All derivative instruments have been classified as held for trading and are measured at fair value. A gain or loss arising from a change in the fair value is recognized in net earnings (loss) in the period in which it occurs.
Equity Based Compensation
Vermilion has long-term equity based compensation plans for directors,
officers and employees of Vermilion and its subsidiaries. Equity based
compensation expense is recognized in net earnings (loss) over the
vesting period of the awards with a corresponding adjustment to
contributed surplus. Upon vesting, the amount previously recognized in
contributed surplus is reclassified to shareholders' capital.
The expense recognized is based on the grant date fair value of the awards and incorporates an estimate of the forfeiture rate based on historical vesting data. The grant date fair value of the awards is determined as the grant date closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the Company's estimate of the performance factor that will ultimately be achieved.
Per Share Amounts
Net earnings (loss) per share is calculated using the weighted-average
number of shares outstanding during the period. Diluted net earnings
per share is calculated using the diluted weighted-average number of
shares outstanding during the period. The diluted weighted-average
number of shares is determined by considering whether equity based
compensation plans, if converted during the year, would result in
reduced net earnings per share.
The treasury stock method is used to determine the dilutive effect of equity based compensation plans. The treasury stock method assumes that the deemed proceeds related to unrecognized equity based compensation expense are used to repurchase shares at the average market price during the period. Equity based awards outstanding are included in the calculation of diluted net earnings per share based on estimated performance factors.
Foreign Currency Translation
The consolidated financial statements are presented in Canadian dollars,
which is Vermilion's reporting currency. As several of Vermilion's
subsidiaries transact and operate primarily in countries other than
Canada, they accordingly have functional currencies other than the
Canadian dollar.
Transactions denominated in currencies other than the functional currency of the subsidiary are translated to the functional currency at the prevailing rates on the date of the transaction. Non-monetary assets or liabilities that result from such transactions are held at the prevailing rate on the date of the transaction. Monetary items denominated in non-functional currencies are translated to the functional currency of the subsidiary at the prevailing rate at the balance sheet date. All translations associated with currencies other than the respective functional currencies are recorded in net earnings (loss).
Translation of all assets and liabilities from the respective functional currencies to the reporting currency are performed using the rates prevailing at the balance sheet date. The differences arising upon translation from the functional currency to the reporting currency are recorded as currency translation adjustments in other comprehensive income (loss) and are held within accumulated other comprehensive income (loss) until a disposal or partial disposal of a subsidiary. A disposal or partial disposal may give rise to a realized gain or loss, which is recorded in net earnings (loss).
Within the consolidated group there are outstanding intercompany loans which in substance represent investments in certain subsidiaries. When these loans are identified as part of the net investment in a foreign subsidiary, any exchange differences arising on those loans are recorded to currency translation adjustments within other comprehensive income (loss) until the disposal or partial disposal of the subsidiary.
Income Taxes
Deferred taxes are calculated using the liability method of accounting.
Under this method, deferred tax is recognized for the estimated effect
of any temporary differences between the amounts recognized on
Vermilion's consolidated balance sheets and respective tax basis. This
calculation uses enacted or substantively enacted tax rates that will
be in effect when the temporary differences are expected to reverse.
The effect of a change in tax rates on deferred taxes is recognized in
net earnings (loss) in the period in which the related legislation is
substantively enacted.
Deferred tax assets are reviewed each reporting period and a valuation allowance is recognized if available evidence indicates that it is not probable that all or a part of a deferred tax asset will be utilized in future periods. A previously recognized valuation allowance is removed when available evidence indicates that all or a part of the valuation allowance is no longer required.
Vermilion is subject to current income taxes based on the tax legislation of each respective country in which Vermilion conducts business.
Borrowing Costs
Borrowing costs that are directly attributable to the acquisition or
construction of an asset that necessarily takes a substantial period of
time to prepare for its intended use are capitalized as part of the
cost of that asset. Borrowing costs are capitalized by applying
interest rates attributable to the project being financed and could
include both general and/or specific borrowings. Interest rates applied
from general borrowings are computed using the weighted average
borrowing rate for the period.
Measurement Uncertainty
The preparation of the consolidated financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and
the reported amounts of revenues and expenses for the periods
presented.
Key areas where management has made complex or subjective judgments include asset retirement obligations, assessment of impairment or recovery of impairment of long-lived assets and income taxes. Actual results could differ significantly from these and other estimates.
Asset Retirement Obligations
Vermilion's asset retirement obligations are based on the expected cost
of adherence to environmental regulations and estimates of the amount
and timing of future expenditures. Changes in environmental
regulations, the estimated costs associated with reclamation
activities, the discount rate applied and the timing of expenditures
could materially impact Vermilion's measurement of the obligations and,
correspondingly, impact Vermilion's financial position and net earnings
(loss).
Assessment of Impairments or Recovery of Previous Impairments
Impairment tests are performed at a CGU level. CGUs are determined
based on management's judgment of the lowest level at which there is
identifiable cash inflows that are largely independent of the cash
inflows of other groups of assets or properties. The factors used by
Vermilion to determine CGUs may vary by country due to the unique
operating and geographic circumstances in each country. However, in
general, Vermilion will assess the following factors in determining
whether a group of assets generate largely independent cash inflows:
geographic proximity of the assets within a group to one another,
geographic proximity of the group of assets to other groups of assets,
homogeneity of the production from the group of assets and the sharing
of infrastructure used to process and/or transport production.
The calculation of the recoverable amount of the CGUs is based on market factors, estimates of PNG reserves and future costs required to develop reserves. Vermilion's reserve estimates and the related future cash flows are subject to measurement uncertainty, and the impact on the consolidated financial statements of future periods could be material. Considerable management judgment is used in determining the recoverable amount of PNG assets, including determining the quantity of reserves, the time horizon to develop and produce such reserves and the estimated revenues and expenditures of such production.
Income Taxes
Tax interpretations, regulations, and legislation in the various
jurisdictions in which Vermilion and its subsidiaries operate are
subject to change and interpretation. Such changes can affect the
timing of the reversal of temporary tax differences, the tax rates in
effect when such differences reverse and Vermilion's ability to use tax
losses and other tax pools in the future. The Company's income tax
filings are subject to audit by taxation authorities in numerous
jurisdictions and the results of such audits may increase or decrease
the tax liability. The determination of current and deferred tax amounts recognized in the
consolidated financial statements are based on management's assessment
of the tax positions, which includes consideration of their technical
merits, communications with tax authorities and management's view of
the most likely outcome.
3. CHANGES TO ACCOUNTING PRONOUNCEMENTS
Accounting pronouncements not yet adopted
The impacts of the adoption of the following pronouncements are currently being evaluated.
IFRS 9 "Financial Instruments"
On July 24, 2014, the IASB issued the final element of its comprehensive
response to the financial crisis by issuing IFRS 9 "Financial
Instruments". The improvements introduced by IFRS 9 includes a model
for classification and measurement, a single, forward-looking 'expected
loss' impairment model and a substantially-reformed approach to hedge
accounting. Vermilion will adopt the standard for reporting periods
beginning January 1, 2018.
IFRS 15 "Revenue from Contracts with Customers"
On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with
Customers", a new standard that specifies recognition requirements for
revenue as well as requiring entities to provide the users of financial
statements with more informative and relevant disclosures. The
standard replaces IAS 11 "Construction Contracts" and IAS 18 "Revenue"
as well as a number of revenue-related interpretations. Vermilion will
adopt the standard for reporting periods beginning January 1, 2018.
IFRS 16 "Leases"
On January 13, 2016, the IASB issued IFRS 16, "Leases", a new standard
which will replace IAS 17, "Leases". Under IFRS 16, a single
recognition and measurement model will apply for lessees which will
require recognition of assets and liabilities for most leases.
Vermilion will adopt the standard for reporting periods beginning
January 1, 2019.
4. BUSINESS COMBINATIONS
Property acquisition:
Germany
In February of 2014, Vermilion acquired, through a wholly-owned subsidiary, GDF's 25% interest in four producing natural gas fields and a surrounding exploration license located in northwest Germany. GDF is an affiliate of GDF Suez S.A., a publicly traded, French multinational utility. The acquisition represented Vermilion's entry into the German E&P business, a producing region with a long history of oil and gas development activity, low political risk and strong marketing fundamentals. The acquisition was well aligned with Vermilion's European focus, and has increased the company's exposure to the strong fundamentals and pricing of the European natural gas markets. The acquisition closed in February of 2014 for cash proceeds of $172.9 million. Vermilion funded this acquisition with existing credit facilities.
The acquired assets were comprised of four gas producing fields across eleven production licenses and included both exploration and production licenses that comprised a total of 207,000 gross acres, of which 85% was in the exploration license.
The acquisition was accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized as follows:
($M) | Consideration | |
Cash paid to vendor | 172,871 | |
Total consideration | 172,871 | |
($M) | Allocation of Consideration | |
Petroleum and natural gas assets | 158,840 | |
Exploration and evaluation | 16,065 | |
Asset retirement obligations assumed | (2,030) | |
Deferred tax liabilities | (4) | |
Net assets acquired | 172,871 |
The results of operations from the assets acquired were included in Vermilion's consolidated financial statements beginning February of 2014 and had contributed net revenues of $33.3 million and a net loss of $0.3 million for the year ended December 31, 2014.
Had the acquisition occurred on January 1, 2014, management estimates that consolidated revenues would have increased by an additional $4.6 million and consolidated net earnings would have increased by $0.9 million for the year ended December 31, 2014.
Corporate acquisitions:
a) Elkhorn Resources Inc.
On April 29, 2014, Vermilion acquired Elkhorn Resources Inc., a private southeast Saskatchewan producer. The acquisition created a new core area for Vermilion in the Williston Basin.
The acquired assets included approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to a minimum of 50% of capacity at a solution gas facility.
Total consideration was comprised of $180.4 million of cash, which was funded with existing credit facilities, and the issuance of 2.8 million Vermilion common shares valued at approximately $205.0 million (based on the closing price per Vermilion common share of $72.50 on the Toronto Stock Exchange on April 29, 2014).
The acquisition was accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized as follows:
($M) | Consideration | |
Cash paid to shareholders of Elkhorn Resources Inc. | 180,353 | |
Shares issued pursuant to corporate acquisition | 204,960 | |
Total consideration | 385,313 | |
($M) | Allocation of Consideration | |
Petroleum and natural gas assets | 390,523 | |
Exploration and evaluation | 138,264 | |
Asset retirement obligations assumed | (5,974) | |
Deferred tax liabilities | (89,437) | |
Long-term debt assumed | (47,526) | |
Cash acquired | 4,174 | |
Acquired non-cash working capital deficiency | (4,711) | |
Net assets acquired | 385,313 |
The results of operations from the assets acquired were included in Vermilion's consolidated financial statements beginning April 29, 2014 and contributed revenues of $50.6 million and operating income of $39.8 million for the year ended December 31, 2014.
Had the acquisition occurred on January 1, 2014, management estimates
that consolidated revenues would have increased by an additional $8.8
million and consolidated operating income would have increased by $7.0
million for the year ended December 31, 2014. In determining the
pro-forma amounts, management had assumed that the fair value
adjustments, determined provisionally, that arose at the date of
acquisition would have been the same if the acquisition had occurred on
January 1, 2014. It is impracticable to derive all amounts necessary
to determine the impact on net earnings from the acquisition as the
acquired company was immediately merged with Vermilion's operations.
5. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
Petroleum and | Furniture and | Total | ||||
($M) | Natural Gas Assets | Office Equipment | Capital Assets | |||
Balance at January 1, 2014 | 2,784,634 | 15,211 | 2,799,845 | |||
Additions | 608,709 | 9,980 | 618,689 | |||
Property acquisitions | 176,625 | - | 176,625 | |||
Corporate acquisitions | 390,523 | - | 390,523 | |||
Changes in estimate for asset retirement obligations | 19,107 | - | 19,107 | |||
Depletion and depreciation | (412,768) | (5,072) | (417,840) | |||
Effect of movements in foreign exchange rates | (75,635) | (222) | (75,857) | |||
Balance at December 31, 2014 | 3,491,195 | 19,897 | 3,511,092 | |||
Additions | 482,574 | 4,287 | 486,861 | |||
Property acquisitions | 27,731 | - | 27,731 | |||
Changes in estimate for asset retirement obligations | (78,429) | - | (78,429) | |||
Depletion and depreciation | (431,889) | (6,453) | (438,342) | |||
Recognition of finance lease asset (1) | 31,028 | - | 31,028 | |||
Impairment (2) | (219,808) | - | (219,808) | |||
Effect of movements in foreign exchange rates | 146,641 | 595 | 147,236 | |||
Balance at December 31, 2015 | 3,449,043 | 18,326 | 3,467,369 | |||
Cost | 5,114,188 | 54,723 | 5,168,911 | |||
Accumulated depletion and depreciation | (1,622,993) | (34,826) | (1,657,819) | |||
Carrying amount at December 31, 2014 | 3,491,195 | 19,897 | 3,511,092 | |||
Cost | 5,624,809 | 57,652 | 5,682,461 | |||
Accumulated depletion and depreciation | (2,175,766) | (39,326) | (2,215,092) | |||
Carrying amount at December 31, 2015 | 3,449,043 | 18,326 | 3,467,369 |
(1) | Refer to Financial Statement Note 16 - Leases |
(2) | Refer to Financial Statement Note 6 - Exploration and Evaluation Assets |
Depletion and depreciation rates
PNG assets (unit of production method)
Furniture and office equipment (declining balance at rates of 5% to 25%)
Capitalized overhead
During the year ended December 31, 2015, Vermilion capitalized $5.1
million (2014 - $7.7 million) of overhead costs directly attributable
to PNG activities.
Impairments
On a quarterly basis, Vermilion performs an assessment as to whether any
CGUs have indicators of impairment. When indicators of impairment are
identified, Vermilion assesses the recoverable amount of the applicable
CGU based on the higher of the estimated fair value less costs to sell
and value in use as at the reporting date. The estimated recoverable
amount takes into account commodity price forecasts, expected
production, estimated costs and timing of development, and undeveloped
land values.
As a result of declines in commodity price forecasts, which decreased expected cash flows, Vermilion recorded a non-cash impairment charge of $131.6 million in the Canada segment for the three months ended December 31, 2015 ($274.6 million for the year ended December 31, 2015, of which $219.8 million related to PNG assets and $54.8 million related to E&E assets). The recoverable amount of each CGU was determined using a value in use approach based on 2015 year end reserves and resource data, an after-tax discount rate of 9% for proved and probable reserves, and an after-tax discount rate of 15% on resources carried within exploration and evaluation assets.
This impairment charge in the year ended December 31, 2015 related to the light crude oil play in Saskatchewan, Canada ($267.9 million based on a recoverable amount of $266.8 million) and the shallow coal bed methane properties in Alberta, Canada ($6.7 million based on a recoverable amount of $19.7 million). The determination of impairment is sensitive to changes in key judgments, including reserve or resource revisions, changes in forward commodity prices and exchange rates, and changes in costs and timing of development. Changes in these key judgments would impact the recoverable amount of CGUs, therefore resulting in additional impairment charges or recoveries. For the year ended December 31, 2015, a one percent increase in the assumed discount rate on expected cash flows of the Saskatchewan light crude oil and Alberta shallow coal bed methane CGUs would result in an additional impairment of $19.5 million, and a five percent decrease in commodity prices would result in an additional impairment of $33.3 million.
Vermilion also identified indicators of impairment on the Ireland CGU which consists of Vermilion's non-operating interest in offshore Corrib natural gas field, but determined that the recoverable amount exceeded its carrying value and accordingly, no impairment charge was recorded. For the year ended December 31, 2015, a one percent increase in the assumed discount rate on expected cash flows of the Ireland CGU would have resulted in impairment of $21.9 million, and a five percent decrease in commodity prices would result in an impairment of $33.6 million.
The following table outlines the forward commodity price estimates that were used in the calculation of recoverable amounts:
Forward Commodity Price Assumptions (1) | ||||||||||
WTI Oil (US $/bbl) |
AECO Gas (CDN $/mmbtu) |
Blended NGLs (2) (CDN $/bbl) |
NBP Gas (US $/mmbtu) |
CDN $/US $ Exchange Rate |
||||||
2016 | 44.00 | 2.76 | 30.27 | 5.55 | 0.73 | |||||
2017 | 52.00 | 3.27 | 35.76 | 5.68 | 0.75 | |||||
2018 | 58.00 | 3.45 | 39.04 | 6.10 | 0.78 | |||||
2019 | 64.00 | 3.63 | 42.96 | 6.70 | 0.80 | |||||
2020 | 70.00 | 3.81 | 45.85 | 7.30 | 0.83 | |||||
2021 | 75.00 | 3.90 | 47.86 | 7.80 | 0.85 | |||||
2022 | 80.00 | 4.10 | 51.23 | 8.30 | 0.85 | |||||
2023 | 85.00 | 4.30 | 54.59 | 8.80 | 0.85 | |||||
2024 | 87.88 | 4.50 | 56.05 | 9.14 | 0.85 | |||||
2025 | 89.63 | 4.60 | 57.18 | 9.32 | 0.85 | |||||
Thereafter | +2.0% per year | +2.0% per year | +2.0% per year | +2.0% per year | 0.85 |
(1) | Source: GLJ Petroleum Consultants price forecast, effective January 1, 2016. |
(2) | The price of blended NGLs shown above is determined used a simple average for Ethane, Propane, Butane, and C5+. |
6. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and evaluation assets:
($M) | Exploration and Evaluation Assets | |||
Balance at January 1, 2014 | 136,259 | |||
Additions | 69,035 | |||
Changes in estimate for asset retirement obligations | 22 | |||
Property acquisitions | 46,135 | |||
Corporate acquisitions | 138,264 | |||
Depreciation | (5,038) | |||
Effect of movements in foreign exchange rates | (4,056) | |||
Balance at December 31, 2014 | 380,621 | |||
Changes in estimate for asset retirement obligations | (130) | |||
Property acquisitions | 1,166 | |||
Depreciation | (21,893) | |||
Impairment (1) | (54,815) | |||
Effect of movements in foreign exchange rates | 3,243 | |||
Balance at December 31, 2015 | 308,192 | |||
Cost | 399,348 | |||
Accumulated depreciation | (18,727) | |||
Carrying amount at December 31, 2014 | 380,621 | |||
Cost | 362,919 | |||
Accumulated depreciation | (54,727) | |||
Carrying amount at December 31, 2015 | 308,192 |
(1) | Refer to Financial Statement Note 5 - Capital Assets |
7. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset retirement obligations:
($M) | Asset Retirement Obligations | ||
Balance at January 1, 2014 | 326,162 | ||
Additional obligations recognized | 22,565 | ||
Changes in estimates for asset retirement obligations | (3,434) | ||
Obligations settled | (15,956) | ||
Accretion | 23,913 | ||
Changes in discount rates | 9,404 | ||
Effect of movements in foreign exchange rates | (11,901) | ||
Balance at December 31, 2014 | 350,753 | ||
Additional obligations recognized | 3,550 | ||
Changes in estimates for asset retirement obligations | 1,117 | ||
Obligations settled | (11,369) | ||
Accretion | 23,911 | ||
Changes in discount rates | (83,226) | ||
Effect of movements in foreign exchange rates | 20,877 | ||
Balance at December 31, 2015 | 305,613 |
Vermilion has estimated the net present value of its asset retirement obligations to be $305.6 million as at December 31, 2015 (2014 - $350.8 million) based on a total undiscounted future liability, after inflation adjustment, of $1.3 billion (2014 - $1.3 billion). These payments are expected to be made between 2016 and 2064. Vermilion calculated the present value of the obligations using discount rates between 7.1% and 10.3% (2014 - between 5.7% and 7.9%) to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. Inflation rates used in determining the cash flow estimates were between 0.6% and 2.4% (2014 - between 0.8% and 2.4%).
Vermilion reviews annually its estimates of the expected costs to
reclaim the net interest in its wells and facilities. The resulting
changes are categorized as changes in estimates for existing
obligations in the preceding table. The decrease in the liability for
the year ended December 31, 2015 primarily resulted from an overall
increase in the discount rates applied to the abandonment obligations.
8. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
As at | ||||||||
($M) | Dec 31, 2015 | Dec 31, 2014 | ||||||
Revolving credit facility | 1,162,998 | 1,014,067 | ||||||
Senior unsecured notes (1) | 224,901 | 224,013 | ||||||
Long-term debt | 1,387,899 | 1,238,080 |
(1) | The senior unsecured notes, which matured on February 10, 2016, are included in the current portion of long-term debt as at December 31, 2015. |
Revolving Credit Facility
At December 31, 2015, Vermilion had in place a bank revolving credit facility totalling $2 billion, of which approximately $1.16 billion was drawn. The facility, which matures on May 31, 2019, is fully revolving up to the date of maturity.
The facility is extendable from time to time, but not more than once per year, for a period not longer than four years, at the option of the lenders and upon notice from Vermilion. If no extension is granted by the lenders, the amounts owing pursuant to the facility are due at the maturity date. This facility bears interest at a rate applicable to demand loans plus applicable margins. For the year ended December 31, 2015, the interest rate on the revolving credit facility was approximately 3.1% (2014 - 3.1%).
The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $25.2 million as at December 31, 2015 (December 31, 2014 - $8.6 million).
The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. Under the terms of the facility, Vermilion must maintain:
As at December 31, 2015, Vermilion was in compliance with all financial covenants.
Senior Unsecured Notes
On February 10, 2011, Vermilion issued $225.0 million of senior unsecured notes at par. The notes bear interest at a rate of 6.5% per annum and matured on February 10, 2016. As direct senior unsecured obligations of Vermilion, the notes ranked pari passu with all other present and future unsecured and unsubordinated indebtedness of the Company. The notes were initially recognized at fair value net of transaction costs and were subsequently measured at amortized cost using an effective interest rate of 7.1%.
Subsequent to December 31, 2015, Vermilion repaid the senior unsecured
notes using funds from the revolving credit facility.
9. INCOME TAXES
Deferred taxes
The net deferred income tax liability at December 31, 2015 and 2014 is comprised of the following:
Year Ended | |||||
($M) | Dec 31, 2015 | Dec 31, 2014 | |||
Deferred income tax liabilities: | |||||
Derivative contracts | (18,452) | (5,965) | |||
Capital assets | (349,664) | (445,457) | |||
Asset retirement obligations | (130,904) | (96,616) | |||
Unrealized foreign exchange | (16,300) | (14,507) | |||
Other | (10,767) | (13,164) | |||
Deferred income tax assets: | |||||
Capital assets | 77,343 | 72,821 | |||
Non-capital losses | 175,477 | 178,222 | |||
Asset retirement obligations | 51,958 | 65,760 | |||
Unrealized foreign exchange | - | 720 | |||
Other | 2,408 | 2,819 | |||
Net deferred income tax liability | (218,901) | (255,367) | |||
Comprised of: | |||||
Deferred income tax assets | 135,753 | 154,816 | |||
Deferred income tax liability | (354,654) | (410,183) | |||
Net deferred income tax liability | (218,901) | (255,367) |
Income tax expense differs from the amount that would have been expected if the reported earnings had been subject only to the statutory Canadian income tax rate of 26.2% (2014 - 25.5%), as follows:
Year Ended | |||||
($M) | Dec 31, 2015 | Dec 31, 2014 | |||
Earnings (loss) before income taxes | (213,915) | 453,072 | |||
Canadian corporate tax rate | 26.2% (1) | 25.5% | |||
Expected tax expense (recovery) | (56,046) | 115,533 | |||
Increase (decrease) in taxes resulting from: | |||||
Petroleum resource rent tax rate (PRRT) differential (2) | 8,310 | 37,035 | |||
Foreign tax rate differentials (2), (3) | (8,096) | 3,492 | |||
Equity based compensation expense | 14,000 | 17,290 | |||
Amended returns and changes to estimated tax pools and tax positions | (6,856) | (7,512) | |||
Changes in statutory tax rates and the estimated reversal rates associated with temporary differences | 1,733 | 16,429 | |||
Valuation allowance | 51,736 | - | |||
Other non-deductible items | (1,394) | 1,479 | |||
Provision for income taxes | 3,387 | 183,746 |
(1) | The corporate tax rate increased to 26.2% in 2015 from 25.5% in 2014 due to the Alberta corporate tax rate increase of 2.0% effective July 1, 2015. |
(2) | In Australia, current taxes include both corporate income tax rates and PRRT. Corporate income tax rates were applied at a rate of 30% and PRRT was applied at a rate of 40%. |
(3) | The combined tax rate was 34.4% in France, 46.0% in the Netherlands, 24.2% in Germany, 25% in Ireland, and 35% in the United States. |
The corporate tax rate for Germany increased to 24.2% (2014 - 22.8%) due to a trade tax increase of 1.4% effective January 2015. |
10. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders' capital:
Shareholders' Capital | Number of Shares ('000s) | Amount ($M) | ||
Balance as at January 1, 2014 | 102,123 | 1,618,443 | ||
Shares issued pursuant to corporate acquisition | 2,827 | 204,960 | ||
Shares issued pursuant to the dividend reinvestment plan | 1,279 | 79,430 | ||
Vesting of equity based awards | 955 | 47,925 | ||
Share-settled dividends on vested equity based awards | 108 | 7,542 | ||
Shares issued pursuant to the bonus plan | 11 | 721 | ||
Balance as at December 31, 2014 | 107,303 | 1,959,021 | ||
Shares issued pursuant to the dividend reinvestment and Premium DividendTM plans | 3,338 | 155,033 | ||
Vesting of equity based awards | 1,158 | 56,855 | ||
Share-settled dividends on vested equity based awards | 135 | 7,561 | ||
Shares issued pursuant to the employee savings and bonus plans | 57 | 2,619 | ||
Balance as at December 31, 2015 | 111,991 | 2,181,089 |
Vermilion is authorized to issue an unlimited number of common shares with no par value.
Dividends
Dividends declared to shareholders for the year ended December 31, 2015 were $283.6 million (2014 - $272.7 million). Dividends are approved by the Board of Directors and are paid monthly. Vermilion has a dividend reinvestment plan ("DRIP") which allows eligible holders of common shares to purchase additional common shares at a 3% discount to market by reinvesting their cash dividends. Additionally, an amendment to the existing DRIP to include a Premium Dividend™ Component was announced in February 2015. With the addition of the Premium Dividend™ Component eligible shareholders have the option to reinvest their dividends in new common shares which are exchanged for a premium cash payment equal to 101.5% of the reinvested dividends.
Subsequent to the end of year-end and prior to the consolidated
financial statements being authorized for issue on February 25, 2016,
Vermilion declared dividends totalling $48.5 million or $0.215 per
share for each of January and February of 2016.
11. EQUITY BASED COMPENSATION
The following table summarizes the number of awards outstanding under the Vermilion Incentive Plan ("VIP"):
Number of Awards ('000s) | 2015 | 2014 | |||||||
Opening balance | 1,775 | 1,665 | |||||||
Granted | 609 | 707 | |||||||
Vested | (587) | (515) | |||||||
Modified | - | (21) | |||||||
Forfeited | (86) | (61) | |||||||
Closing balance | 1,711 | 1,775 |
The fair value of a VIP award is determined on the grant date at the closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the estimated performance factor that will ultimately be achieved. Dividends, which notionally accrue to the awards during the vesting period, are not included in the determination of grant date fair values. For the year ended December 31, 2015, the awards granted had a weighted average fair value of $80.70 (2014 - $101.63).
The performance factor is determined by the Board of Directors after consideration of Company performance using Vermilion's balanced scorecard metrics including, but not limited to, relative total shareholder return, financial and operational performance, and performance on strategic objectives.
The expense recognized is based on the grant date fair value of the awards and incorporates an estimate of forfeiture rate based on historical vesting data. For the year ended December 31, 2015, Vermilion incorporated an estimated forfeiture rate of 4.8% (2014 - 5.8%). Equity based compensation expense of $72.6 million was recorded during the year ended December 31, 2015 (2014 - $67.1 million) related to the VIP.
12. PER SHARE AMOUNTS
Basic and diluted net earnings (loss) per share have been determined based on the following:
Year Ended | ||||||
($M except per share amounts) | Dec 31, 2015 | Dec 31, 2014 | ||||
Net (loss) earnings [1] | (217,302) | 269,326 | ||||
Basic weighted average shares outstanding [2] | 109,642 | 105,448 | ||||
Dilutive impact of equity based awards | - | 1,739 | ||||
Diluted weighted average shares outstanding [3] | 109,642 | 107,187 | ||||
Basic (loss) earnings per share ([1] ÷ [2]) | (1.98) | 2.55 | ||||
Diluted (loss) earnings per share ([1] ÷ [3]) | (1.98) | 2.51 |
13. DERIVATIVE INSTRUMENTS
The nature of Vermilion's operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates. Vermilion monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by Vermilion are related to an underlying financial position or to future crude oil and natural gas production. Vermilion does not use derivative financial instruments for speculative purposes. Vermilion has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings at each reporting period. Vermilion has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts.
During the normal course of business, Vermilion may enter into fixed price arrangements to sell a portion of its production or purchase commodities for operational use. Vermilion does not apply fair value accounting on these contracts as they were entered into and continue to be held for the sale of production or operational use in accordance with the Company's expected requirements.
The following tables summarize Vermilion's outstanding risk management positions as at December 31, 2015:
Note | Volume | Strike Price(s) | |||||||
Crude Oil | |||||||||
WTI - Collar | |||||||||
July 2015 - March 2016 | 1 | 250 bbl/d | 75.00 - 83.45 CAD $ | ||||||
July 2015 - June 2016 | 2 | 500 bbl/d | 75.50 - 85.08 CAD $ | ||||||
Dated Brent - Collar | |||||||||
July 2015 - June 2016 | 3 | 1,000 bbl/d | 80.50 - 93.49 CAD $ | ||||||
July 2015 - June 2016 | 4 | 500 bbl/d | 64.50 - 75.48 US $ | ||||||
October 2015 - June 2016 | 5 | 250 bbl/d | 82.00 - 94.55 CAD $ | ||||||
January 2016 - June 2016 | 1 | 250 bbl/d | 84.00 - 93.70 CAD $ | ||||||
North American Natural Gas | |||||||||
AECO - Collar | |||||||||
November 2015 - March 2016 | 2,500 GJ/d | 2.50 - 3.76 CAD $ | |||||||
November 2015 - October 2016 | 10,000 GJ/d | 2.56 - 3.23 CAD $ | |||||||
January 2016 - December 2016 | 10,000 GJ/d | 2.53 - 3.29 CAD $ | |||||||
April 2016 - October 2016 | 5,000 GJ/d | 2.30 - 2.80 CAD $ | |||||||
AECO Basis - Fixed Price Differential | |||||||||
November 2015 - March 2016 | 2,500 mmbtu/d | Nymex HH less 0.47 US $ | |||||||
Nymex HH - Collar | |||||||||
November 2015 - March 2016 | 6 | 5,000 mmbtu/d | 3.25 - 3.86 US $ |
(1) |
The contracted volumes increase to 500 boe/d for any monthly settlement
periods above the contracted ceiling price and are settled on the
monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(2) |
The contracted volumes increase to 1,250 boe/d for any monthly
settlement periods above the contracted ceiling price and are settled
on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(3) |
The contracted volumes increase to 2,500 boe/d for any monthly
settlement periods above the contracted ceiling price and are settled
on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(4) | The contracted volumes increase to 1,000 boe/d for any monthly settlement periods above the contracted ceiling price. |
(5) |
The contracted volumes increase to 750 boe/d for any monthly settlement
periods above the contracted ceiling price and are settled on the
monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(6) | The contracted volumes increase to 10,000 mmbtu/d for any monthly settlement periods above the contracted ceiling price. |
Note | Volume | Strike Price(s) | |||||||
European Natural Gas | |||||||||
NBP - Call | |||||||||
October 2016 - March 2017 | 2,638 GJ/d | 4.64 GBP £ | |||||||
NBP - Collar | |||||||||
April 2016 - March 2017 | 2,638 GJ/d | 3.79 - 4.53 GBP £ | |||||||
January 2017 - December 2017 | 2,638 GJ/d | 3.22 - 3.75 GBP £ | |||||||
January 2018 - December 2018 | 2,638 GJ/d | 2.99 - 3.63 GBP £ | |||||||
NBP - Put | |||||||||
April 2016 - September 2016 | 2,638 GJ/d | 3.79 GBP £ | |||||||
NBP - Swap | |||||||||
July 2015 - March 2016 | 2,592 GJ/d | 6.42 EUR € | |||||||
October 2015 - March 2016 | 10,368 GJ/d | 6.54 EUR € | |||||||
January 2016 - June 2016 | 5,184 GJ/d | 6.24 EUR € | |||||||
January 2016 - June 2016 | 2,592 GJ/d | 6.82 US $ | |||||||
July 2016 - March 2017 | 2,592 GJ/d | 5.43 EUR € | |||||||
January 2017 - December 2017 | 1 | 2,638 GJ/d | 4.00 GBP £ | ||||||
January 2018 - December 2018 | 2 | 2,638 GJ/d | 3.83 GBP £ | ||||||
TTF - Call | |||||||||
October 2016 - March 2017 | 2,592 GJ/d | 6.03 EUR € | |||||||
TTF - Collar | |||||||||
January 2016 - December 2016 | 3 | 2,592 GJ/d | 5.76 - 6.50 EUR € | ||||||
April 2016 - December 2016 | 4 | 12,960 GJ/d | 5.58 - 6.21 EUR € | ||||||
April 2016 - March 2017 | 5 | 5,184 GJ/d | 5.28 - 6.35 EUR € | ||||||
July 2016 - December 2016 | 2,592 GJ/d | 5.00 - 5.63 EUR € | |||||||
July 2016 - March 2017 | 3 | 2,592 GJ/d | 5.07 - 6.56 EUR € | ||||||
July 2016 - March 2018 | 3 | 2,592 GJ/d | 5.32 - 6.54 EUR € | ||||||
October 2016 - December 2017 | 2,592 GJ/d | 5.00 - 5.89 EUR € | |||||||
January 2017 - December 2017 | 6 | 7,776 GJ/d | 5.00 - 6.15 EUR € | ||||||
January 2018 - December 2018 | 5,184 GJ/d | 4.17 - 5.03 EUR € | |||||||
TTF - Put | |||||||||
April 2016 - September 2016 | 2,592 GJ/d | 5.21 EUR € | |||||||
TTF - Swap | |||||||||
January 2015 - March 2016 | 5,184 GJ/d | 6.40 EUR € | |||||||
January 2015 - June 2016 | 2,592 GJ/d | 6.07 EUR € | |||||||
February 2015 - March 2016 | 5,184 GJ/d | 6.24 EUR € | |||||||
April 2015 - March 2016 | 5,832 GJ/d | 6.18 EUR € | |||||||
October 2015 - March 2016 | 2,592 GJ/d | 6.64 EUR € | |||||||
January 2016 - June 2016 | 5,184 GJ/d | 5.94 EUR € | |||||||
April 2016 - December 2016 | 2,592 GJ/d | 5.91 EUR € | |||||||
July 2016 - June 2018 | 2,700 GJ/d | 5.58 EUR € | |||||||
October 2016 - December 2016 | 2,592 GJ/d | 5.45 EUR € | |||||||
January 2017 - December 2017 | 7 | 2,592 GJ/d | 5.04 EUR € | ||||||
Electricity | |||||||||
AESO - Swap | |||||||||
January 2016 - December 2016 | 93.6 MWh/d | 38.58 CAD $ | |||||||
Interest Rate | |||||||||
CDOR to fixed - Swap | |||||||||
September 2015 - September 2019 | 100,000,000 CAD $/year | 1.00 % | |||||||
October 2015 - October 2019 | 100,000,000 CAD $/year | 1.10 % |
(1) | On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 2,638 GJ/d at the contracted price, for the following month. |
(2) | On the last business day of each month, the counterparty has the option to increase the contracted volumes to 7,913 GJ/d at the contracted price, for the following month. |
(3) | The contracted volumes increase to 5,184 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(4) | The contracted volumes increase to 15,552 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(5) | The contracted volumes increase to 10,368 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(6) | The contracted volumes increase to 18,144 GJ/d for any monthly settlement periods above the contracted ceiling price. |
(7) | On the last business day of each month, the counterparty has the option to increase the contracted volumes by an additional 5,184 GJ/d at the contracted price, for the following month. |
The following table reconciles the change in the fair value of Vermilion's derivative instruments:
Year ended | |||||||
($M) | Dec 31, 2015 | Dec 31, 2014 | |||||
Fair value of contracts, beginning of year | 24,794 | (1,287) | |||||
Reversal of opening contracts settled during the year | (23,391) | 1,287 | |||||
Acquired derivative contracts | - | (1,290) | |||||
Realized gain on contracts settled during the year | 41,356 | 36,712 | |||||
Unrealized gain during the year on contracts outstanding at the end of the year | 66,939 | 26,084 | |||||
Net receipt from counterparties on contract settlements during the year | (41,356) | (36,712) | |||||
Fair value of contracts, end of year | 68,342 | 24,794 | |||||
Comprised of: | |||||||
Current derivative asset | 55,214 | 23,391 | |||||
Non-current derivative asset | 13,128 | 1,403 | |||||
Fair value of contracts, end of year | 68,342 | 24,794 |
The gain on derivative instruments for 2015 and 2014 were comprised of the following:
Year Ended | |||||
($M) | Dec 31, 2015 | Dec 31, 2014 | |||
Realized gain on contracts settled during the year | (41,356) | (36,712) | |||
Reversal of opening contracts settled during the year | 23,391 | (1,287) | |||
Unrealized gain during the year on contracts outstanding at the end of the year | (66,939) | (26,084) | |||
Gain on derivative instruments | (84,904) | (64,083) |
14. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of the following:
Year Ended | |||||||
($M) | Dec 31, 2015 | Dec 31, 2014 | |||||
Changes in: | |||||||
Accounts receivable | 11,321 | (4,202) | |||||
Crude oil inventory | (3,569) | 7,633 | |||||
Prepaid expenses | 2,577 | 1,400 | |||||
Accounts payable and accrued liabilities | (49,449) | 30,364 | |||||
Income taxes payable | (38,457) | (11,152) | |||||
Movements in foreign exchange rates | (8,793) | (8,601) | |||||
Changes in non-cash working capital | (86,370) | 15,442 | |||||
Changes in non-cash operating working capital | (60,390) | 3,077 | |||||
Changes in non-cash investing working capital | (25,980) | 12,365 | |||||
Changes in non-cash working capital | (86,370) | 15,442 |
15. SEGMENTED INFORMATION
Vermilion has operations in three core areas: North America, Europe, and Australia. Vermilion's operating activities in each country relate solely to the exploration, development and production of petroleum and natural gas. Vermilion has a Corporate head office located in Calgary, Alberta. Costs incurred in the Corporate segment relate to Vermilion's global hedging program and expenses incurred in financing and managing our operating business units.
Vermilion's chief operating decision maker reviews the financial performance of the Company by assessing the fund flows from operations of each country individually. Fund flows from operations provides a measure of each business unit's ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, fund asset retirement obligations, and make capital investments.
Year Ended December 31, 2015 | |||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia | United States | Corporate | Total | ||||||||
Total assets | 1,609,180 | 863,304 | 212,749 | 167,908 | 908,453 | 235,139 | 42,927 | 169,560 | 4,209,220 | ||||||||
Drilling and development | 201,508 | 92,265 | 47,325 | 5,363 | 66,409 | 61,741 | 12,250 | - | 486,861 | ||||||||
Oil and gas sales to external customers | 320,613 | 281,422 | 129,057 | 41,384 | 57 | 162,765 | 4,288 | - | 939,586 | ||||||||
Royalties | (28,144) | (26,958) | (3,082) | (6,479) | - | - | (1,257) | - | (65,920) | ||||||||
Revenue from external customers | 292,469 | 254,464 | 125,975 | 34,905 | 57 | 162,765 | 3,031 | - | 873,666 | ||||||||
Transportation expense | (16,326) | (15,378) | - | (3,269) | (6,687) | - | - | - | (41,660) | ||||||||
Operating expense | (89,085) | (50,718) | (22,746) | (10,956) | (15) | (51,676) | (742) | - | (225,938) | ||||||||
General and administration | (16,888) | (20,217) | (4,158) | (7,386) | (2,517) | (5,754) | (3,836) | 7,172 | (53,584) | ||||||||
PRRT | - | - | - | - | - | (6,878) | - | - | (6,878) | ||||||||
Corporate income taxes | - | (23,764) | (12,152) | - | - | (7,230) | - | (1,091) | (44,237) | ||||||||
Interest expense | - | - | - | - | - | - | - | (59,852) | (59,852) | ||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 41,356 | 41,356 | ||||||||
Realized foreign exchange gain | - | - | - | - | - | - | - | 623 | 623 | ||||||||
Realized other income | - | 31,775 | - | - | - | - | - | 896 | 32,671 | ||||||||
Fund flows from operations | 170,170 | 176,162 | 86,919 | 13,294 | (9,162) | 91,227 | (1,547) | (10,896) | 516,167 | ||||||||
Year Ended December 31, 2014 | |||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia | United States | Corporate | Total | ||||||||
Total assets | 1,865,942 | 874,163 | 220,100 | 170,237 | 822,756 | 240,614 | 14,731 | 177,548 | 4,386,091 | ||||||||
Drilling and development | 291,046 | 136,019 | 49,695 | 2,747 | 94,439 | 44,283 | 460 | - | 618,689 | ||||||||
Exploration and evaluation | 43,696 | 11,833 | 12,045 | - | - | - | - | 1,461 | 69,035 | ||||||||
Oil and gas sales to external customers | 537,788 | 431,252 | 123,815 | 41,962 | - | 283,481 | 1,330 | - | 1,419,628 | ||||||||
Royalties | (65,563) | (28,444) | (5,014) | (8,613) | - | - | (366) | - | (108,000) | ||||||||
Revenue from external customers | 472,225 | 402,808 | 118,801 | 33,349 | - | 283,481 | 964 | - | 1,311,628 | ||||||||
Transportation expense | (14,625) | (18,975) | - | (2,367) | (6,394) | - | - | - | (42,361) | ||||||||
Operating expense | (76,178) | (61,729) | (24,041) | (8,686) | - | (61,432) | (241) | - | (232,307) | ||||||||
General and administration | (16,791) | (20,929) | (3,617) | (4,688) | (1,447) | (5,873) | (959) | (7,423) | (61,727) | ||||||||
PRRT | - | - | - | - | - | (60,340) | - | - | (60,340) | ||||||||
Corporate income taxes | - | (66,901) | (4,154) | (44) | - | (24,477) | - | (1,420) | (96,996) | ||||||||
Interest expense | - | - | - | - | - | - | - | (49,655) | (49,655) | ||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 36,712 | 36,712 | ||||||||
Realized foreign exchange loss | - | - | - | - | - | - | - | (821) | (821) | ||||||||
Realized other income | - | - | - | - | - | - | - | 732 | 732 | ||||||||
Fund flows from operations | 364,631 | 234,274 | 86,989 | 17,564 | (7,841) | 131,359 | (236) | (21,875) | 804,865 |
Reconciliation of fund flows from operations to net earnings (loss)
Year Ended | ||||||
Dec 31, | Dec 31, | |||||
($M) | 2015 | 2014 | ||||
Fund flows from operations | 516,167 | 804,865 | ||||
Equity based compensation | (75,232) | (67,802) | ||||
Unrealized gain on derivative instruments | 43,548 | 27,371 | ||||
Unrealized foreign exchange loss | 8,787 | (17,599) | ||||
Unrealized other expense | (1,008) | (1,492) | ||||
Accretion | (23,911) | (23,913) | ||||
Depletion and depreciation | (458,758) | (425,694) | ||||
Deferred taxes | 47,728 | (26,410) | ||||
Impairment | (274,623) | - | ||||
Net earnings (loss) | (217,302) | 269,326 |
Vermilion has two major customers with revenues in excess of 10% within the France and Netherlands segments. Substantially all sales in the France and Netherlands segments for the years ended December 31, 2015 and 2014 were to one customer in each respective segment.
16. LEASES
Vermilion had the following future commitments associated with its operating and finance leases as at December 31, 2015:
($M) | Less than 1 year | 1 - 3 years | 4 - 5 years | After 5 years | Total | ||||||||||
Operating lease payments by period | 20,750 | 30,942 | 23,909 | 49,734 | 125,335 | ||||||||||
Finance lease minimum lease payments by period | 6,285 | 12,571 | 9,515 | 6,984 | 35,355 | ||||||||||
Interest | 2,079 | 3,077 | 1,521 | 907 | 7,584 | ||||||||||
Present value of minimum lease payments | 6,029 | 10,746 | 7,069 | 4,148 | 27,992 |
In addition, Vermilion has various other commitments associated with its business operations; none of which, in management's view, are significant in relation to Vermilion's financial position.
As part of an acquisition in April of 2014, Vermilion assumed an
agreement for the use of a solution gas facility. The substance of the
arrangement was determined to be a lease and has been classified as a
finance lease. The assets are to be used for a minimum period of 10
years, with an option to renew. As at December 31, 2015, the carrying
amount of the asset included in capital assets is $28.4 million, and
the current portion of the finance lease obligation included in accrued
liabilities in $5.9 million.
17. CASH AND CASH EQUIVALENTS
Cash and cash equivalents was comprised of the following:
($M) | Dec 31, 2015 | Dec 31, 2014 | ||||||
Money on deposit with financial institutions | 31,175 | 116,643 | ||||||
Short-term investments | 10,501 | 3,762 | ||||||
Cash and cash equivalents | 41,676 | 120,405 |
18. CAPITAL DISCLOSURES
Vermilion defines capital as net debt (a non-standardized measure, which is defined by management as long-term debt as shown on the consolidated balance sheets plus net working capital) and shareholders' capital.
In managing capital, Vermilion reviews whether fund flows from operations (a non-standardized measure, defined by management as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled), is sufficient to pay for all capital expenditures, dividends and abandonment and reclamation expenditures. To the extent that the forecasted fund flows from operations is not expected to be sufficient in relation to these expenditures, Vermilion will evaluate its ability to finance any excess with debt, an issuance of equity or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.
Additionally, Vermilion monitors the ratio of net debt to fund flows from operations. Vermilion typically strives to maintain an internally targeted ratio of net debt to fund flows from operations of 1.0 to 1.3 in a normalized commodity price environment. Where prices trend higher, Vermilion may target a lower ratio and conversely, in a lower commodity price environment, the acceptable ratio may be higher. At times, Vermilion will use its balance sheet to finance acquisitions and, in these situations, Vermilion is prepared to accept a higher ratio in the short term but will implement a plan to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 18 months. This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.
In the current low commodity price environment, the net debt to fund flows ratio is expected to be higher than the longer term ratio. During this period, Vermilion is managing the higher debt level by aligning capital expenditures within forecasted fund flows from operations, which is continually monitored for revised forward price estimates, as well as by hedging additional European natural gas volumes to maintain a diversified commodity portfolio.
The following table calculates Vermilion's ratio of net debt to fund flows from operations:
Year Ended | ||||||
($M except as indicated) | Dec 31, 2015 | Dec 31, 2014 | ||||
Long-term debt | 1,162,998 | 1,238,080 | ||||
Current liabilities(1) | 503,731 | 365,729 | ||||
Current assets | (284,778) | (338,159) | ||||
Net debt [1] | 1,381,951 | 1,265,650 | ||||
Cash flows from operating activities | 444,408 | 791,986 | ||||
Changes in non-cash operating working capital | 60,390 | (3,077) | ||||
Asset retirement obligations settled | 11,369 | 15,956 | ||||
Fund flows from operations [2] | 516,167 | 804,865 | ||||
Ratio of net debt to fund flows from operations ([1] ÷ [2]) | 2.7 | 1.6 |
(1) | Includes the current portion of long-term debt, which, as at December 31, 2015, represents the senior unsecured notes that matured on February 10, 2016. |
Long-term debt, including the current portion, as at December 31, 2015 increased to $1.39 billion from $1.24 billion as at December 31, 2014, primarily as a result of draws on the revolving credit facility to fund capital expenditures as fund flows from operations for the year ended December 31, 2015 were lower due to weakening crude oil and natural gas prices. The increase in long-term debt resulted in an increase in net debt from $1.27 billion as at December 31, 2014 to $1.38 billion as at December 31, 2015.
Driven primarily by the weakness in crude oil prices, the ratio of net
debt to fund flows from operations increased to 2.7 times for the year
ended December 31, 2015.
19. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to Vermilion's financial instruments as at December 31, 2015 and December 31, 2014:
As at Dec 31, 2015 | As at Dec 31, 2014 | |||||||||||||||
Class of financial instrument |
Consolidated balance sheet caption |
Accounting designation |
Related caption on Statement of Net Earnings (Loss) |
Carrying value ($M) |
Fair value ($M) |
Carrying value ($M) |
Fair value ($M) |
Fair value measurement hierarchy |
||||||||
Cash | Cash and cash equivalents | HFT |
Gains and losses on foreign exchange are included in foreign exchange (gain) loss |
41,676 | 41,676 | 120,405 | 120,405 | Level 1 | ||||||||
Receivables | Accounts receivable | LAR |
Gains and losses on foreign exchange are included in foreign exchange (gain) loss and impairments are recognized as general and administration expense |
160,499 | 160,499 | 171,820 | 171,820 | Not applicable | ||||||||
Derivative assets | Derivative instruments | HFT | Gain on derivative instruments | 68,342 | 68,342 | 24,794 | 24,794 | Level 2 | ||||||||
Payables |
Accounts payable and accrued liabilities |
OTH |
Gains and losses on foreign exchange are included in foreign exchange (gain) loss |
(272,824) | (272,824) | (321,266) | (321,266) | Not applicable | ||||||||
Dividends payable | ||||||||||||||||
Long-term debt | Long-term debt | OTH | Interest expense | (1,387,899) | (1,387,998) | (1,238,080) | (1,238,505) | Level 2 |
The accounting designations used in the above table refer to the following:
HFT - Classified as "Held for trading" in accordance with International Accounting Standard 39 "Financial Instruments: Recognition and Measurement". These financial assets and liabilities are carried at fair value on the consolidated balance sheets with associated gains and losses reflected in net earnings (loss).
LAR - "Loans and receivables" are initially recognized at fair value and are subsequently measured at amortized cost. Impairments and foreign exchange gains and losses are recognized in net earnings (loss).
OTH - "Other financial liabilities" are initially recognized at fair value net of transaction costs directly attributable to the issuance of the instrument and subsequently are measured at amortized cost. Interest is recognized in net earnings (loss) using the effective interest method. Foreign exchange gains and losses are recognized in net earnings (loss).
Level 1 - Fair value measurement is determined by reference to unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 - Fair value measurement is determined based on inputs other than unadjusted quoted prices that are observable, either directly or indirectly.
Level 3 - Fair value measurement is based on inputs for the asset or liability that are not based on observable market data.
Determination of Fair Values
The level in the fair value hierarchy into which the fair value measurements are categorized is determined on the basis of the lowest level input that is significant to the fair value measurement. Transfers between levels on the fair value hierarchy are deemed to have occurred at the end of the reporting period.
Fair values for derivative assets and derivative liabilities are determined using pricing models incorporating future prices that are based on assumptions which are supported by prices from observable market transactions and are adjusted for credit risk.
The carrying value of receivables approximate their fair value due to their short maturities.
The carrying value of long-term debt outstanding on the revolving credit facility approximates its fair value due to the use of short-term borrowing instruments at market rates of interest.
The fair value of the senior unsecured notes changes in response to changes in the market rates of interest payable on similar instruments and was determined with reference to prevailing market rates for such instruments.
Nature and Extent of Risks Arising from Financial Instruments
Vermilion is exposed to the following types of risks in relation to its financial instruments:
Credit risk:
Vermilion extends credit to customers and is due amounts from counterparties in relation to derivative instruments. Accordingly, there is a risk of financial loss in the event that a counterparty fails to discharge its obligation. For transactions that are financially significant, Vermilion reviews third-party credit ratings and may require additional forms of security. Cash held on behalf of the Company by financial institutions is also subject to credit risk.
Liquidity risk:
Liquidity risk is the risk that Vermilion will encounter difficulty in meeting obligations associated with its financial liabilities. Vermilion does not consider this to be a significant risk as its financial position and available committed borrowing facility provide significant financial flexibility and allow Vermilion to meet its obligations as they come due.
Currency risk:
Vermilion conducts business in foreign currencies in addition to Canadian dollars and accordingly is subject to currency risk associated with changes in foreign exchange rates in relation to cash and cash equivalents, receivables, payables and derivative assets and liabilities. The impact related to working capital is somewhat mitigated as a result of the offsetting effects of foreign exchange fluctuations on assets and liabilities. Vermilion monitors its exposure to currency risk and reviews whether the use of derivative financial instruments is appropriate to manage potential fluctuations in foreign exchange rates.
Commodity price risk:
Vermilion uses derivative financial instruments as part of its risk management program to mitigate the effects of changes in commodity prices on future cash flows. Changes in the underlying commodity prices impact the fair value and future cash flows related to these derivatives.
Interest rate risk:
Vermilion's long-term debt is comprised of borrowings under the revolving credit facility and the Company's senior unsecured notes. Borrowings under the revolving credit facility bear interest at market rates plus applicable margins and as such changes in interest rates could result in an increase or decrease in the amount Vermilion pays to service this debt. In 2015, Vermilion had interest rate swaps to mitigate the effects of changes in variable interest rates. The senior unsecured notes bear interest at a fixed 6.5% interest rate and as such, changes in prevailing interest rates would affect the fair value of these notes. However, as Vermilion does not intend to settle this debt prior to maturity, the notes are carried at amortized cost and changes in fair value do not affect net earnings.
Summarized Quantitative Data Associated with the Risks Arising from Financial Instruments
Credit risk:
As at December 31, 2015, Vermilion's maximum exposure to receivable credit risk was $228.8 million (December 31, 2014 - $196.6 million) which is the aggregate value of receivables and derivative assets at the balance sheet date. Vermilion's receivables are primarily due from counterparties that have investment grade third party credit ratings or, in the absence of the availability of such ratings, have been satisfactorily reviewed by Vermilion for creditworthiness. Additionally, cash and cash equivalents consist of moneys on deposit and short-term investments which may be subject to counterparty credit risk. Vermilion mitigates this risk by transacting with North American institutions with high third party credit ratings.
As at the balance sheet date the amount of financial assets that were past due or impaired was not material.
Liquidity risk:
Vermilion's derivative financial instruments settle on a monthly basis.
The following table summarizes Vermilion's undiscounted non-derivative financial liabilities and their contractual maturities as at December 31, 2015 and December 31, 2014:
Later than | Later than | Later than | ||||||||||
one month and | three months and | one year and | ||||||||||
Due in | not later than | not later than | not later than | |||||||||
($M) | one month | three months | one year | five years | ||||||||
December 31, 2015 | 112,890 | 353,934 | 33,663 | 1,180,486 | ||||||||
December 31, 2014 | 162,127 | 138,823 | 20,314 | 1,239,067 |
Market risk:
Vermilion's financial instruments are exposed to currency risk related to changes in foreign currency denominated financial instruments and commodity price risk related to outstanding derivative positions. The following table summarizes what the impact on comprehensive income before tax would be for the year ended December 31, 2015 given changes in the relevant risk variables that Vermilion considers were reasonably possible at the balance sheet date. The impact on comprehensive income before tax associated with changes in these risk variables for assets and liabilities that are not considered financial instruments are excluded from this analysis. This analysis does not attempt to reflect any interdependencies between the relevant risk variables.
Before tax effect on comprehensive | |||||||||
income - increase (decrease) | |||||||||
Risk ($M) | Description of change in risk variable | December 31, 2015 | December 31, 2014 | ||||||
Currency risk - Euro to Canadian | Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates | (1,986) | (4,030) | ||||||
Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates | 1,986 | 4,030 | |||||||
Currency risk - US $ to Canadian | Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates | 3,423 | (5,739) | ||||||
Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates | (3,423) | 5,739 | |||||||
Commodity price risk | Increase in relevant oil reference price within option pricing models used to determine | (3,262) | (1,072) | ||||||
the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates | |||||||||
Decrease in relevant oil reference price within option pricing models used to determine | 3,263 | 1,048 | |||||||
the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates | |||||||||
Increase in relevant European natural gas reference price within option pricing models used to | (23,813) | (10,279) | |||||||
determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates | |||||||||
Decrease in relevant European natural gas reference price within option pricing models used to | 21,754 | 10,085 | |||||||
determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates | |||||||||
Interest rate risk | Increase in average Canadian prime interest rate by 100 basis points during the relevant periods | (10,543) | (9,032) | ||||||
Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods | 10,543 | 9,032 |
Reasonably possible changes in North American natural gas prices would
not have had a material impact on comprehensive income for the years
ended December 31, 2015 and 2014.
20. RELATED PARTY DISCLOSURES
The compensation of directors and management are reviewed annually by the independent Governance and Human Resources Committee against industry practices for oil and gas companies of similar size and scope.
The following table summarizes the compensation of directors and other members of key management personnel during the years ended December 31, 2015 and December 31, 2014:
Year Ended | |||||||||
($M) | Dec 31. 2015 | Dec 31, 2014 | |||||||
Short-term benefits | 5,460 | 5,684 | |||||||
Share-based payments | 20,310 | 16,414 | |||||||
25,770 | 22,098 | ||||||||
Number of individuals included in the above amounts | 20 | 18 |
21. WAGES AND BENEFITS
Included in operating expenses and general and administrative expenses
for the year ended December 31, 2015 were $47.7 million and $40.4
million of wages and benefits, respectively (2014 - $56.2 million and
$47.2 million, respectively).
22. SIGNIFICANT TRANSACTIONS
During Q1 2015, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambès oil terminal in France that occurred in 2007. The French court awarded Vermilion approximately €25 million (before taxes), of which 50% was due immediately to Vermilion upon posting a surety bond. The payment was received in Q2 2015, with the remainder due upon conclusion of the appeal process. Based on the recent court decision and the conclusions of the expert engaged by the French court, Vermilion is virtually certain that the award will be upheld.
SOURCE Vermilion Energy Inc.
PDF available at: http://stream1.newswire.ca/media/2016/02/29/20160229_C9875_DOC_EN_44636.pdf
CALGARY, Feb. 11, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on March 15, 2016 to all shareholders of record on February 23, 2016. The ex-dividend date for this payment is February 19, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Jan. 11, 2016 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion") (TSX, NYSE: VET) is pleased to announce a cash dividend of $0.215 CDN per share payable on February 16, 2016 to all shareholders of record on January 22, 2016. The ex-dividend date for this payment is January 20, 2016. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth, along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Dec. 30, 2015 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "the Company", "We", "Us", or "Our") (TSX, NYSE: VET) is pleased to announce that natural gas began to flow at our Corrib gas project in Ireland on December 30, 2015. Production levels at Corrib are expected to rise over a period of approximately six months to a peak rate estimated at 58 mmcf/d (9,700 boe/d), net to Vermilion.
"First gas marks an important milestone for Vermilion" said Lorenzo Donadeo, CEO of Vermilion. "Corrib will be a significant contributor to both our 2016 and 2017 production growth and generate meaningful free cash flow for the Company. Corrib strengthens our focus on Europe and provides us with operational momentum in an area where we are becoming a dominant intermediate producer. Moreover, it is good news for Ireland. Corrib will improve the security of natural gas supply in the Irish market and will bring long-term benefits and employment to the Irish economy."
Corrib production is priced in reference to the National Balancing Point (NBP) in the United Kingdom and will increase Vermilion's exposure to advantageously-priced European natural gas production. We anticipate that European-based natural gas will represent approximately 30% of our 2016 production volumes.
Corrib is a world class natural gas field located approximately 83 km off the northwest coast of Ireland. The field is believed to contain approximately 1 trillion cubic feet of natural gas reserves.
Notes to Editors
More information on the Corrib project is available online at: www.shell.ie
Further information regarding the benefits associated with the Corrib project in Ireland is available online at: www.shell.ie/progress
About Vermilion Energy Inc.
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
CALGARY, Dec. 29, 2015 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "the Company", "We", "Us", or "Our") (TSX, NYSE: VET) is pleased to announce that Shell E&P Ireland Limited ("Shell"), operator of the Corrib project, has received the final remaining consent required for production from the office of Ireland's Minister for Communications, Energy and Natural Resources. The Corrib partners (Shell, Vermilion and Statoil Exploration Ireland Limited) are now focused on final preparations to initiate first gas production at Corrib. Production levels at Corrib are expected to rise over a period of approximately six months to a peak rate estimated at 58 mmcf/d (9,700 boe/d), net to Vermilion.
"Receipt of Ministerial Consent marks the end of a lengthy and comprehensive regulatory review by a number of Irish regulatory agencies," said Lorenzo Donadeo, CEO of Vermilion. "Achievement of first gas at Corrib will mark a significant milestone for Vermilion."
Corrib production is priced in reference to the National Balancing Point (NBP) in the United Kingdom and will increase Vermilion's exposure to advantageously-priced European natural gas production. We anticipate that European-based natural gas will represent approximately 30% of our 2016 production volumes.
Corrib is a world class natural gas field located approximately 83 km off the northwest coast of Ireland. The field is believed to contain approximately 1 trillion cubic feet of natural gas reserves.
Notes to Editors
More information on the Corrib project is available online at: www.shell.ie. Further information regarding the benefits associated with the Corrib project in Ireland is available online at: www.shell.ie/progress
About Vermilion Energy Inc.
Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia. Our business model targets annual organic production growth along with providing reliable and increasing dividends to investors. Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through drilling and workover programs in France and Australia. Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland. Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield of approximately 7%. Management and directors of Vermilion hold approximately 6% of the outstanding shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered a 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.
SOURCE Vermilion Energy Inc.
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