Project: Project Wildcat
Firm Commitment: 400 Mmcf/d
COST: 450 $MM
VOLUMES: 19 MBOE/d
ACRES: 172000 Acres
COST: 3.25 $B
VOLUMES: 50 MBOE/d
ACRES: 92000 Acres
COST: 68 $MM
ACRES: 26000 Acres
OKLAHOMA CITY, Jan. 19, 2021 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") plans to announce full-year 2020 and fourth quarter 2020 results on Tuesday, February 16, 2021 after the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss full-year 2020 and fourth quarter 2020 results on Wednesday, February 17, 2021 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
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Time and date: | 12:00 p.m. ET, Wednesday, February 17, 2021 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 6942729 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10151479 |
The Company plans to publish a full-year 2020 and fourth quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Wednesday, February 17, 2021.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2021, the Company will celebrate 54 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Spaay | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-full-year-2020-and-fourth-quarter-2020-results-on-tuesday-february-16-2021-301211214.html
SOURCE Continental Resources
OKLAHOMA CITY, Dec. 4, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today that it will redeem $400 million in aggregate principal amount, representing approximately 63% of the approximately $631 million in aggregate principal amount currently outstanding, of its 5% Senior Notes due 2022 (the "Notes") on January 5, 2021, the redemption date for the Notes.
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The redemption price for the Notes called for redemption will be equal to 100.00% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the redemption date in accordance with the terms of the Notes and the indenture under which the Notes were issued. The Notes to be redeemed will be selected in accordance with the procedures of The Depository Trust Company. Interest on the portion of the Notes selected for redemption will cease to accrue on and after the redemption date.
Additional information concerning the terms and conditions of the redemption is contained in the notice distributed to holders of the Notes. Beneficial holders with any questions about the redemption should contact their respective brokerage firm or financial institution.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance and financial condition, are forward-looking statements. When used in this press release, the word "will" is intended to identify forward-looking statements, although not all forward-looking statements contain this identifying word.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, the ability to complete the redemption and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-partial-redemption-of-5-senior-notes-due-2022-301186208.html
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 24, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today the results to date of Continental's previously announced cash tender offers (the "Tender Offers") to purchase up to $1.0 billion aggregate principal amount (the "Aggregate Maximum Tender Amount") of its outstanding 5.0% senior notes due 2022 (the "2022 Notes") and 4.5% senior notes due 2023 (the "2023 Notes" and collectively, the "Notes"), subject to a limit of $200 million aggregate principal amount of 2023 Notes that may be purchased in the Tender Offers (the "2023 Series Cap").
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The Company has amended the Aggregate Maximum Tender Amount to increase the aggregate principal amount of Notes subject to the Tender Offers from $1.0 billion to approximately $1.27 billion, as well as to increase the 2023 Series Cap to $800 million. All other terms of the Tender Offers remain unchanged. Based on information provided by D.F. King and Co., the tender agent for the Tender Offers, approximately $1.47 billion aggregate principal amount of Notes were validly tendered (and not validly withdrawn) at or prior to 5:00 p.m., New York City time, on November 24, 2020 (the "Early Tender Date"). The following table sets forth the approximate aggregate principal amounts of each series of Notes that were validly tendered (and not validly withdrawn) as of the Early Tender Date and the principal amounts that, subject to satisfaction of the conditions to the Tender Offers described below, are expected to be accepted for purchase pursuant to the Tender Offers:
Title of Notes | CUSIP Numbers | Acceptance | Principal Amount | Total | Principal Amount | Principal Amount | Proration |
5.0% Senior Notes due 2022 | 212015AH4; 212015AG6; U21180AA9 | 1 | $ 1,100,000,000 | $ 1,002.50 | $ 469,218,000 | $ 469,218,000 | 100.0% |
4.5% Senior Notes due 2023 | 212015AL5 | 2 | $ 1,449,625,000 | $ 1,030.00 | $ 1,001,075,000 | $ 800,000,000 | 79.9% |
_________________________ | |
(1) | As of the date of the Offer to Purchase (as defined below). |
(2) | Holders will also receive accrued and unpaid interest from the applicable last interest payment with respect to the Notes accepted for purchase to, but not including, the Early Settlement Date (as defined below). |
(3) | Includes the Early Tender Premium (as defined below). |
(4) | The final proration factor has been rounded to the nearest tenth of a percentage point for presentation purposes. |
Subject to satisfaction of the conditions to the Tender Offers set forth in the Offer to Purchase dated November 10, 2020 (the "Offer to Purchase"), the Company expects to accept and pay for Notes tendered prior to the Early Tender Date, subject to the proration described herein, on or about November 25, 2020 (the "Early Settlement Date"). Holders of Notes that have been accepted for purchase in connection with the Early Tender Date will receive the applicable Total Consideration set forth in the table above, which includes an early tender premium of $30.00 per $1,000 principal amount of the Notes accepted for purchase (the "Early Tender Premium"). The deadline for holders to validly withdraw tenders of Notes has passed. Accordingly, tendered Notes may no longer be withdrawn or revoked, except in certain limited circumstances where additional withdrawal or revocation rights are required by law.
Because the Aggregate Maximum Tender Amount of Notes were tendered and not withdrawn prior to the Early Tender Date, the Company does not expect to accept for purchase any tenders of Notes after the Early Tender Date.
The Tender Offers are subject to the satisfaction of the conditions described in the Offer to Purchase. Such conditions may be waived by the Company in its sole discretion, subject to applicable law. Any waiver of a condition by the Company will not constitute a waiver of any other condition.
The dealer manager for the Tender Offers is BofA Securities. Any questions regarding the terms of the Tender Offers should be directed to the Dealer Manager, BofA Securities at (980) 386-6026 (all call) or debt_advisory@bofa.com. The information agent and tender agent is D.F. King & Co., Inc. Any questions regarding procedures for tendering Notes or requests for copies of the Offer to Purchase or other documents relating to the Tender Offers should be directed to the information agent for the Tender Offers, D.F. King & Co., Inc., at (877) 732-3619 (toll-free), (212) 269-5550 (all others) or clr@dfking.com, or by visiting www.dfking.com/clr.
This press release shall not constitute an offer to sell, a solicitation to buy or an offer to purchase or sell any securities. No offer, solicitation, purchase or sale will be made in any jurisdiction in which such offer, solicitation, or sale would be unlawful. The offer is being made solely pursuant to the terms and conditions set forth in the Offer to Purchase. The Company's obligation to accept for purchase and to pay for the Notes validly tendered in any Tender Offer is subject to and conditioned on the satisfaction or waiver of the conditions described in the Offer to Purchase, including the completion of the Company's separately announced offering of 5.75% Senior Notes due 2031 (the "Debt Financing"). Nothing contained herein shall constitute an offer of the securities that are the subject of the Debt Financing.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, expectations regarding the completion of the Debt Financing and the Tender Offers are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing and greenhouse gas emissions; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, our Forms 10-Q for the quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contact: | Media Contact: | |
Rory Sabino | Kristin Thomas | |
Vice President, Investor Relations | Senior Vice President, Public Relations | |
405-234-9620 | 405-234-9480 | |
Lucy Guttenberger | ||
Investor Relations Analyst | ||
405-774-5878 | ||
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-early-results-and-upsizing-of-cash-tender-offers-301180244.html
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 10, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today the pricing of its private placement of new 5.75% senior unsecured notes due 2031, which was upsized to $1.5 billion in aggregate principal amount from the originally proposed $1.0 billion offering. The notes were sold at par. The offering is expected to close on November 25, 2020, subject to customary closing conditions. The Company intends to use the net proceeds from this offering to fund the concurrent tender offers for a portion of the Company's 5.0% senior notes due 2022 and 4.5% senior notes due 2023 (the "Tender Offers"), to pay fees and expenses incurred in connection therewith, and the excess, if any, for general corporate purposes, including other repayments or refinancings of the Company's debt.
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The securities offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The senior unsecured notes are expected to be eligible for trading by qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S.
This press release is being issued pursuant to Rule 135c under the Securities Act, and is neither an offer to sell nor a solicitation of an offer to buy the notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the completion of the notes offering and the use of proceeds therefrom are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing and greenhouse gas emissions; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2019, our Form 10-Q for the quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-pricing-of-upsized-1-5-billion-offering-of-new-senior-notes-due-2031--301170382.html
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 10, 2020 /PRNewswire/ -- CONTINENTAL RESOURCES, INC. (NYSE: CLR) ("Continental" or the "Company") announced today the commencement of cash tender offers (the "Tender Offers") to purchase up to $1.0 billion aggregate principal amount (the "Aggregate Maximum Tender Amount") of its outstanding 5.0% senior notes due 2022 (the "2022 Notes") and 4.5% senior notes due 2023 (the "2023 Notes") (collectively, the 2022 Notes and the 2023 Notes are referred to herein as the "Notes") in the priorities set forth in the table below; provided that the Company will not accept for purchase more than $200 million aggregate principal amount (as it may be increased by the Company, the "2023 Series Cap") of the 2023 Notes.
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The following table sets forth certain terms of the Tender Offers:
Dollars per $1,000 Principal Amount of Notes | ||||||
Title of | CUSIP Numbers | Aggregate (1) | Acceptance | Tender Offer | Early Tender | Total (2)(3) |
5.0% Senior | 212015AH4; U21180AA9 | $ 1,100,000,000 | 1 | $ 972.50 | $ 30.00 | $ 1,002.50 |
4.5% Senior | 212015AL5 | $ 1,449,625,000 | 2 | $ 1,000.00 | $ 30.00 | $ 1,030.00 |
_________________________ | |
(1) | As of the date of the Offer to Purchase. |
(2) | Holders will also receive accrued and unpaid interest from the applicable last interest payment with respect to the Notes accepted for purchase to, but not including, the Early Settlement Date (as defined below) or the Final Settlement Date (as defined below), as applicable. |
(3) | Includes the Early Tender Premium. |
The terms and conditions of the Tender Offers are described in an Offer to Purchase, dated November 10, 2020 (the "Offer to Purchase"). Continental intends to fund the Tender Offers, including accrued interest and fees and expenses payable in connection with the Tender Offers, with the net proceeds of its separately announced proposed offering of debt securities (the "Debt Financing"), together with, if necessary, borrowings from its bank credit facility or cash on hand.
Holders of Notes that are validly tendered (and not validly withdrawn) at or prior to 5:00 p.m., New York City time, on November 24, 2020 (such date and time, as it may be extended, the "Early Tender Date") and accepted for purchase pursuant to the Tender Offers will receive the applicable Total Consideration set forth in the table above, which includes an early tender premium of $30 per $1,000 principal amount of the Notes accepted for purchase (the "Early Tender Premium"). Holders of Notes tendering their Notes after the Early Tender Date will only be eligible to receive the applicable Tender Offer Consideration for such series of Notes set forth in the table above, which is the applicable Total Consideration minus the Early Tender Premium.
In addition to the Tender Offer Consideration or the Total Consideration, as applicable, all holders of Notes accepted for purchase will receive accrued and unpaid interest from and including the last interest payment date applicable to the relevant series of Notes up to, but not including, the applicable Settlement Date (as defined below) for such Notes.
Tendered Notes may be withdrawn at any time prior to 5:00 p.m., New York City time, on November 24, 2020 (the "Withdrawal Date") and may not be validly withdrawn thereafter except as provided in the Offer to Purchase or applicable law.
The Tender Offers will expire at Midnight, New York City time, at the end of December 9, 2020, unless extended by Continental in its sole discretion (the "Expiration Date").
Provided that the conditions to the applicable Tender Offer have been satisfied or waived, and assuming acceptance for purchase by Continental of the Notes validly tendered pursuant to the Tender Offers, (i) payment for Notes validly tendered at or prior to the Early Tender Date and accepted for purchase in the Tender Offers will be made on the settlement date that is expected to be the first business day following the Early Tender Date, or as promptly as practicable thereafter (the "Early Settlement Date") and (ii) payment for any Notes validly tendered after the Early Tender Date, but at or prior to the Expiration Date, and accepted for purchase in the Tender Offers will be made on the settlement date that is expected to be the second business day following the Expiration Date (the "Final Settlement Date" and, together with the related Early Settlement Date, the "Settlement Dates").
Subject to the Aggregate Maximum Tender Amount, the 2023 Series Cap and proration, the Notes accepted for payment on any Settlement Date will be accepted in accordance with their Acceptance Priority Levels set forth in the table above, with 1 being the higher Acceptance Priority Level and 2 being the lower Acceptance Priority Level; provided that Notes tendered at or prior to the Early Tender Date will be accepted for purchase with priority over Notes tendered after the Early Tender Date, even if such Notes tendered after the Early Tender Date have a higher Acceptance Priority Level.
Acceptance for tenders of any Notes may be subject to proration if the aggregate principal amount for any series of Notes validly tendered and not validly withdrawn would cause the Aggregate Maximum Tender Amount to be exceeded. Furthermore, if the Tender Offers are fully subscribed as of the Early Tender Date, holders who validly tender Notes after the Early Tender Date will not have any of such Notes accepted for purchase. If the principal amount of the 2023 Notes validly tendered at or prior to the Early Tender Date exceeds the 2023 Series Cap, the Company will not accept for purchase any 2023 Notes tendered after the Early Tender Date.
The Company reserves the right, but is under no obligation, to increase the Aggregate Maximum Tender Amount and the 2023 Series Cap at any time, subject to compliance with applicable law, which could result in the Company purchasing a greater aggregate principal amount of Notes in the Tender Offers. There can be no assurance that the Company will exercise its right to increase the Aggregate Maximum Tender Amount or the 2023 Series Cap. If the Company increases the Aggregate Maximum Tender Amount or the 2023 Series Cap, it does not expect to extend the Withdrawal Date, subject to applicable law. Accordingly, holders should not tender any Notes that they do not wish to have purchased in the Tender Offers.
The Tender Offers are not contingent upon the tender of any minimum principal amount of Notes. Continental's obligation to accept for purchase and to pay for the Notes validly tendered in any Tender Offer is subject to and conditioned on the satisfaction or waiver of the conditions described in the Offer to Purchase, including the completion of the Debt Financing. Continental reserves the right, subject to applicable law, to: (a) extend the Early Tender Date, Withdrawal Date or Expiration Date to a later date and time as announced by the Company; (b) increase the Aggregate Maximum Tender Amount and the 2023 Series Cap; (c) waive or modify in whole or in part any or all conditions to the Tender Offers; (d) delay the acceptance for purchase of any Notes or delay the purchase of any Notes; or (e) otherwise modify or terminate one or more of the Tender Offers.
If the Tender Offers are not consummated, or if we purchase less than the Aggregate Maximum Tender Amount in the Tender Offers, we may exercise our right under the indenture to redeem all or part of the 2022 Notes that remain outstanding afterward, although we have no legal obligation to do so and the selection of any particular redemption date is in our discretion. The current redemption price of the 2022 Notes is equal to 100.00%, which is less than the Total Consideration, plus accrued and unpaid interest, if any, to the date of redemption.
The dealer manager for the Tender Offers is BofA Securities. Any questions regarding the terms of the Tender Offers should be directed to the Dealer Manager, BofA Securities at (980) 386-6026 (all call) or debt_advisory@bofa.com. The information agent and tender agent is D.F. King & Co., Inc. Any questions regarding procedures for tendering Notes or requests for copies of the Offer to Purchase or other documents relating to the Tender Offers should be directed to the information agent for the Tender Offers, D.F. King & Co., Inc., at (877) 732-3619 (toll-free), (212) 269-5550 (all others) or clr@dfking.com, or by visiting www.dfking.com/clr.
This press release shall not constitute an offer to sell, a solicitation to buy or an offer to purchase or sell any securities. No offer, solicitation, purchase or sale will be made in any jurisdiction in which such offer, solicitation, or sale would be unlawful. The offer is being made solely pursuant to the terms and conditions set forth in the Offer to Purchase. Nothing contained herein shall constitute an offer of the debt securities that are the subject of the Debt Financing.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, expectations regarding the completion of the Debt Financing and the Tender Offers are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing and greenhouse gas emissions; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, our Form 10-Q for the quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Rory.Sabino@CLR.com | Kristin.Thomas@CLR.com |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
Lucy.Guttenberger@CLR.com |
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 10, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today that, subject to market conditions, it intends to offer a series of senior notes due 2031 in a private placement to eligible purchasers. Continental intends to use the net proceeds from this offering to fund the concurrent tender offers for a portion of the Company's 5.0% senior notes due 2022 and 4.5% senior notes due 2023 and to pay fees and expenses incurred in connection therewith, and the excess, if any, to repay borrowings under our revolving credit facility and for general corporate purposes.
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The securities to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The senior unsecured notes are expected to be eligible for trading by qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S.
This press release is being issued pursuant to Rule 135c under the Securities Act, and is neither an offer to sell nor a solicitation of an offer to buy the notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the completion of the notes offering and the use of proceeds therefrom are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing and greenhouse gas emissions; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2019, our Form 10-Q for the quarters ended March 31, 2020, June 30, 2020 and September 30, 2020, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contact: | Media Contact: | |
Rory Sabino | Kristin Thomas | |
Vice President, Investor Relations | Senior Vice President, Public Relations | |
405-234-9620 | 405-234-9480 | |
Lucy Guttenberger |
Investor Relations Analyst |
405-774-5878 |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-private-offering-of-new-senior-notes-due-2031-301169716.html
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 5, 2020 /PRNewswire/ --
3Q20 Results and Full-Year 2020 Expectations
• $291.2 Million Cash Flow from Operations in 3Q20; $258.3 Million Free Cash Flow (Non-
GAAP)
• $149.4 Million in Non-Acquisition Capex in 3Q20; On Track for $1.2 Billion in Full-Year
2020
• 297 MBoepd Average Daily Production in 3Q20 (57% Oil)
o Maintain 2020 Average Annual Production Guidance of 155 to 165 MBopd & 800 to 820
MMcfpd
o December 2020 Exit Rate Production of 315 to 325 MBoepd
• $1.63 Total G&A per Boe in 3Q20 in Line with Initial 2020 Guidance; $1.04 Cash G&A per
Boe (Non-GAAP) and $3.19 Production Expense per Boe in 3Q20 Below Initial 2020
Guidance
• Improved Cost Metric Guidance for 2020
o 2020 Total G&A per Boe Guidance of $1.60 to $1.90 (Previously $1.60 to $2.00)
o 2020 Cash G&A per Boe Guidance: $1.10 to $1.30 (Previously $1.10 to $1.40)
o 2020 Production Expense per Boe Guidance: $3.50 to $3.75 (Previously $3.50 to $4.00)
• Operating Efficiencies Improve Year-Over-Year All-In Completed Well Costs (CWC) per
Well
o South: $9.0 Million CWC Improved 14% YoY (80% Structural); Targeting $8.9 Million YE20
o Bakken: $7.2 Million CWC Improved 12% YoY (70% Structural); Targeting $6.9 Million YE20
Preliminary 2021 Outlook
• Oklahoma Oil & Gas Assets Provide Optionality to Capitalize on Strong Gas Prices in 2021
• Maximizing Free Cash Flow (FCF) & Prioritizing Debt Paydown
o Projecting Annual Cash Flow from Operations of $1.6 Billion and Annual FCF of Approximately
$400 Million (Approx. 8.0% FCF Yield) at the Midpoint of Projected Capex Spend at $40 WTI
o Projecting Annual Cash Flow from Operations of $1.85 Billion and Annual FCF of
Approximately $650 Million (Approx. 14.0% FCF Yield) at the Midpoint of Projected Capex
Spend at $45 WTI
o Projecting Total Debt Below $5.0 Billion at YE21; $4.0 Billion or Below by YE22/2023
• Projecting 65-75% Cash Flow from Operations (CFFO) Reinvestment Rate for 2021
o Projecting $1.2 to $1.3 Billion Capex Spend in 2021 at $40 to $45 WTI
o Projecting Low Single Digit Production Growth YoY with Cash Flow Breakeven Price of $32
WTI
Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced third quarter 2020 operating and financial results, as well as its preliminary 2021 outlook.
The Company reported a net loss of $79.4 million, or $0.22 per diluted share, for the quarter ended September 30, 2020. In third quarter 2020, typically excluded items in aggregate represented $20.5 million, or $0.06 per diluted share of Continental's reported net loss. Adjusted net loss for third quarter 2020 was $58.9 million, or $0.16 per diluted share (non-GAAP). Net cash provided by operating activities for third quarter 2020 was $291.2 million and free cash flow was $258.3 million. EBITDAX was $473.3 million (non-GAAP).
Adjusted net income (loss), adjusted net income (loss) per share, free cash flow, free cash flow yield, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
"The production we voluntarily curtailed was back on line in the third quarter 2020, performing well as anticipated. As we look to year end 2020 and into 2021, we will continue our track record of delivering sustainable free cash flow alongside ongoing debt reduction, low cost leadership and unmatched shareholder alignment, while responsibly fueling a better world through our ESG stewardship," said Bill Berry, Chief Executive Officer.
Production & Operations Update
Third quarter 2020 total production averaged 297,001 Boepd. Third quarter 2020 oil production averaged 169,265 Bopd. Third quarter 2020 natural gas production averaged 766.4 MMcfpd. The Company maintains its full-year 2020 production guidance of 155,000 to 165,000 Bopd and 800,000 to 820,000 Mcfpd. The Company expects exit rate production of 315,000 to 325,000 Boepd in December 2020.
Technical innovations and operating efficiencies in the Bakken and Oklahoma continue to reduce cycle times and CWC, which include drilling and completion, full facilities costs and artificial lift. In the Bakken, CWC have improved 12% year-over-year to $7.2 million per well, with a $6.9 million target by year-end 2020. Approximately 70% of cost savings are structural. In Oklahoma, CWC have improved 14% year-over-year to $9.0 million per well, with an $8.9 million target by year-end 2020. Approximately 80% of cost savings are structural.
"The capital efficiency of our operations continues to improve through our teams' innovation and consistent performance from our assets. At the same time, our teams are constantly seeking strategic opportunities to cost-effectively grow our assets. We recently closed on a bolt-on acquisition in SCOOP that added 19,500 net acres and up to 185 high quality, oil-weighted operated wells to our inventory," said Jack Stark, President and Chief Operating Officer.
The following table provides the Company's average daily production by region for the periods presented.
3Q | 3Q | YTD | YTD | |||||
Boe per day | 2020 | 2019 | 2020 | 2019 | ||||
Bakken | 160,661 | 191,268 | 150,366 | 194,872 | ||||
South | 129,583 | 133,266 | 129,559 | 128,826 | ||||
All other | 6,757 | 7,781 | 6,997 | 8,291 | ||||
Total | 297,001 | 332,315 | 286,922 | 331,989 |
Financial Update
"Continental has consistently demonstrated low cost leadership and despite the market volatility we have faced this year, 2020 will be no exception. Thanks to our unique combination of assets and operational efficiencies, Continental will deliver positive free cash flow for the fifth consecutive year alongside improved guidance for LOE per Boe and cash G&A per Boe," said John Hart, Chief Financial Officer.
Three Months Ended | Nine Months Ended | |||
3Q20 Financial Update | September 30, 2020 | September 30, 2020 | ||
Cash and Cash Equivalents | $21.2 million | |||
Total Debt | $5.63 billion | |||
Net Debt (non-GAAP)(1) | $5.61 billion | |||
Average Net Sales Price (non-GAAP)(1) | ||||
Per Barrel of Oil | $35.93 | $33.71 | ||
Per Mcf of Gas | $0.98 | $0.72 | ||
Per Boe | $23.23 | $20.21 | ||
Production Expense per Boe | $3.19 | $3.45 | ||
Total G&A Expenses per Boe | $1.63 | $1.65 | ||
Crude Oil Differential per Barrel | ($5.00) | ($6.03) | ||
Natural Gas Differential per Mcf | ($1.05) | ($1.19) | ||
Non-Acquisition Capital Expenditures | $149.4 million | $990.9 million | ||
Exploration & Development Drilling & Completion | $120.9 million | $820.7 million | ||
Leasehold | $5.5 million | $31.0 million | ||
Minerals, of which 80% was Recouped from FNV | $0.6 million | $23.9 million | ||
Workovers, Recompletions and Other | $22.4 million | $115.3 million | ||
(1) Net debt and net sales prices represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Preliminary 2021 Outlook
"As a continuation of Continental's historic track record of sustainable cash flow and debt reduction, we are projecting a 65% to 75% cash flow from operations reinvestment rate for 2021, with free cash flow projections of approximately $400 million at $40 WTI and $650 million at $45 WTI. Additionally, Continental is prioritizing debt paydown and expects to significantly reduce total debt to $5 billion or below by year end 2021, and down to $4 billion or below by year end 2022 or 2023," said Bill Berry, Chief Executive Officer.
In anticipation of stronger gas fundamentals in 2021, the Company shifted Oklahoma rigs to gassier areas in the second quarter 2020. To date, approximately 202 MMcfpd of the Company's 2021 natural gas is hedged, with two-thirds of the hedges representing collars with a weighted average floor price of $2.67 and a weighted average ceiling price of $3.44. The Company expects to continue an active and ongoing hedging program in 2021 and 2022. In Oklahoma, condensate wells are delivering strong early time results, with 20 recently completed SCOOP condensate wells performing in line with or better than expectations and are expected to deliver over 50% rates of return at $3.00 Henry Hub. With oil and gas inventory depth and direct access to multiple premium oil and gas markets in Oklahoma, the Company has the flexibility to capitalize on both oil and gas commodity prices.
The Company is projecting a 65% to 75% cash flow from operations (CFFO) reinvestment rate for 2021. At the midpoint of projected 2021 Capex, the Company is projecting annual cash flow from operations of $1.6 billion and annual free cash flow (FCF) of approximately $400 million at $40 WTI. The Company is projecting annual cash flow from operations of $1.85 billion and annual FCF of approximately $650 million at $45 WTI. The Company is projecting approximately 8.0% to 14.0% free cash flow yield at $40 to $45 WTI. Free cash flow yield is estimated by dividing the 2021 annual FCF estimate range by the Company's current market capitalization, as of November 5, 2020. Additionally, the Company is projecting total debt below $5.0 billion at year-end 2021 and $4.0 billion or below by year-end 2022 and 2023.
In 2021, the Company is projecting $1.2 to $1.3 billion of Capex at $40 to $45 WTI and $3 Henry Hub. The Company is projecting a low single digit production growth year-over-year in 2021 and expects a cash flow breakeven price of $32 WTI in 2021.
The Company will provide its full 2021 guidance, capital expenditures budget and operating details during its historical timeframe of early next year. The Company's full 2020 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended September 30, | Nine months ended September 30, | ||||||
2020 | 2019 | 2020 | 2019 | ||||
Average daily production: | |||||||
Crude oil (Bbl per day) | 169,265 | 198,074 | 155,088 | 195,209 | |||
Natural gas (Mcf per day) | 766,416 | 805,446 | 791,005 | 820,679 | |||
Crude oil equivalents (Boe per day) | 297,001 | 332,315 | 286,922 | 331,989 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||||
Crude oil ($/Bbl) | $ 35.93 | $ 51.28 | $ 33.71 | $ 51.99 | |||
Natural gas ($/Mcf) | $ 0.98 | $ 1.12 | $ 0.72 | $ 1.78 | |||
Crude oil equivalents ($/Boe) | $ 23.23 | $ 33.30 | $ 20.21 | $ 34.95 | |||
Production expenses ($/Boe) | $ 3.19 | $ 3.73 | $ 3.45 | $ 3.68 | |||
Production taxes (% of net crude oil and gas sales) | 7.8% | 8.5% | 8.3% | 8.4% | |||
DD&A ($/Boe) | $ 16.58 | $ 15.81 | $ 16.37 | $ 16.18 | |||
Total general and administrative expenses ($/Boe) (2) | $ 1.63 | $ 1.54 | $ 1.65 | $ 1.57 | |||
Net income (loss) attributable to Continental Resources (in thousands) | $ (79,422) | $ 158,162 | $ (504,372) | $ 581,695 | |||
Diluted net income (loss) per share attributable to Continental Resources | $ (0.22) | $ 0.43 | $ (1.39) | $ 1.56 | |||
Adjusted net income (loss) (non-GAAP) (in thousands) (1) | $ (58,871) | $ 199,389 | $ (342,139) | $ 635,135 | |||
Adjusted diluted net income (loss) per share (non-GAAP) (1) | $ (0.16) | $ 0.54 | $ (0.95) | $ 1.70 | |||
Net cash provided by operating activities (in thousands) | $ 291,197 | $ 806,972 | $ 934,767 | $ 2,311,876 | |||
EBITDAX (non-GAAP) (in thousands) (1) | $ 473,311 | $ 828,704 | $ 1,103,571 | $ 2,541,508 | |||
(1) Net sales prices, adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.04, $1.12, $1.04, and $1.16 for 3Q 2020, 3Q 2019, YTD 2020, and YTD 2019, respectively. Non-cash equity compensation expense per Boe was $0.59, $0.42, $0.61, and $0.41 for 3Q 2020, 3Q 2019, YTD 2020, and YTD 2019, respectively. |
Third Quarter Earnings Conference Call
The Company plans to host a conference call to discuss third quarter 2020 results on Friday, November 6, 2020 at 10:00 a.m. ET (9:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 10:00 a.m. ET, Friday, November 6, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8013830 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10147993 |
The Company plans to publish a third quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Friday, November 6, 2020.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing and greenhouse gas emissions; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020 and June 30, 2020, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
Continental Resources, Inc. and Subsidiaries | |||||||
Unaudited Condensed Consolidated Statements of Income (Loss) | |||||||
Three months ended September 30, | Nine months ended September 30, | ||||||
2020 | 2019 | 2020 | 2019 | ||||
Revenues: | In thousands, except per share data | ||||||
Crude oil and natural gas sales | $ 701,468 | $ 1,081,400 | $ 1,738,863 | $ 3,328,409 | |||
Gain (loss) on derivative instruments, net | (17,853) | 1,195 | (25,635) | 53,519 | |||
Crude oil and natural gas service operations | 8,755 | 21,602 | 35,602 | 54,886 | |||
Total revenues | 692,370 | 1,104,197 | 1,748,830 | 3,436,814 | |||
Operating costs and expenses: | |||||||
Production expenses | 88,701 | 114,050 | 271,852 | 333,446 | |||
Production taxes | 50,153 | 86,931 | 132,444 | 267,237 | |||
Transportation expenses | 55,272 | 62,038 | 148,079 | 164,569 | |||
Exploration expenses | 1,041 | 2,472 | 14,638 | 7,399 | |||
Crude oil and natural gas service operations | 3,316 | 8,224 | 15,288 | 26,616 | |||
Depreciation, depletion, amortization and accretion | 461,191 | 484,031 | 1,288,185 | 1,464,672 | |||
Property impairments | 18,518 | 20,199 | 264,976 | 66,854 | |||
General and administrative expenses | 45,273 | 46,993 | 129,713 | 141,837 | |||
Net (gain) loss on sale of assets and other | 800 | 535 | 5,914 | 647 | |||
Total operating costs and expenses | 724,265 | 825,473 | 2,271,089 | 2,473,277 | |||
Income (loss) from operations | (31,895) | 278,724 | (522,259) | 963,537 | |||
Other income (expense): | |||||||
Interest expense | (63,884) | (68,090) | (192,547) | (204,398) | |||
Gain (loss) on extinguishment of debt | - | (4,584) | 64,573 | (4,584) | |||
Other | 224 | 1,119 | 1,385 | 3,196 | |||
(63,660) | (71,555) | (126,589) | (205,786) | ||||
Income (loss) before income taxes | (95,555) | 207,169 | (648,848) | 757,751 | |||
(Provision) benefit for income taxes | 13,972 | (49,747) | 138,350 | (177,386) | |||
Net income (loss) | (81,583) | 157,422 | (510,498) | 580,365 | |||
Net loss attributable to noncontrolling interests | (2,161) | (740) | (6,126) | (1,330) | |||
Net income (loss) attributable to Continental Resources | $ (79,422) | $ 158,162 | $ (504,372) | $ 581,695 | |||
Net income (loss) per share attributable to Continental Resources: | |||||||
Basic | $ (0.22) | $ 0.43 | $ (1.39) | $ 1.56 | |||
Diluted | $ (0.22) | $ 0.43 | $ (1.39) | $ 1.56 | |||
Continental Resources, Inc. and Subsidiaries | ||||
Unaudited Condensed Consolidated Balance Sheets | ||||
In thousands | September 30, 2020 | December 31, 2019 | ||
Assets | ||||
Cash and cash equivalents | $ 21,237 | $ 39,400 | ||
Other current assets | 678,525 | 1,167,615 | ||
Net property and equipment (1) | 14,004,414 | 14,497,726 | ||
Other noncurrent assets | 24,048 | 23,166 | ||
Total assets | $ 14,728,224 | $ 15,727,907 | ||
Liabilities and equity | ||||
Current liabilities | $ 748,060 | $ 1,336,026 | ||
Long-term debt, net of current portion | 5,629,133 | 5,324,079 | ||
Other noncurrent liabilities | 1,846,917 | 1,959,451 | ||
Equity attributable to Continental Resources | 6,132,684 | 6,741,667 | ||
Equity attributable to noncontrolling interests | 371,430 | 366,684 | ||
Total liabilities and equity | $ 14,728,224 | $ 15,727,907 | ||
(1) Balance is net of accumulated depreciation, depletion and amortization of $14.21 billion and $12.77 billion as of September 30, 2020 and December 31, 2019, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||
In thousands | 2020 | 2019 | 2020 | 2019 | ||||
Net income (loss) | $ (81,583) | $ 157,422 | $ (510,498) | $ 580,365 | ||||
Adjustments to reconcile net income (loss) to net | ||||||||
Non-cash expenses | 489,905 | 603,397 | 1,427,992 | 1,759,213 | ||||
Changes in assets and liabilities | (117,125) | 46,153 | 17,273 | (27,702) | ||||
Net cash provided by operating activities | 291,197 | 806,972 | 934,767 | 2,311,876 | ||||
Net cash used in investing activities | (162,923) | (696,182) | (1,181,866) | (2,253,927) | ||||
Net cash provided by (used in) financing activities | (113,693) | (282,002) | 228,936 | (305,458) | ||||
Effect of exchange rate changes on cash | - | (10) | - | 20 | ||||
Net change in cash and cash equivalents | 14,581 | (171,222) | (18,163) | (247,489) | ||||
Cash and cash equivalents at beginning of period | 6,656 | 206,482 | 39,400 | 282,749 | ||||
Cash and cash equivalents at end of period | $ 21,237 | $ 35,260 | $ 21,237 | $ 35,260 |
Non-GAAP Financial Measures
Non-GAAP adjusted net income (loss) and adjusted net income (loss) per share attributable to Continental
Our presentation of adjusted net income (loss) and adjusted net income (loss) per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income (loss) and adjusted net income (loss) per share represent net income (loss) and diluted net income (loss) per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and gains and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income (loss) and adjusted net income (loss) per share should not be considered in isolation or as an alternative to, or more meaningful than, net income (loss) or diluted net income (loss) per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile net income (loss) and diluted net income (loss) per share as determined under U.S. GAAP to adjusted net income (loss) and adjusted diluted net income (loss) per share for the periods presented.
Three months ended September 30, | |||||||||||||||
2020 | 2019 | ||||||||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | |||||||||||
Net income (loss) attributable to Continental Resources (GAAP) | $ (79,422) | $ (0.22) | $ 158,162 | $ 0.43 | |||||||||||
Adjustments: | |||||||||||||||
Non-cash loss on derivatives | 7,901 | 29,289 | |||||||||||||
Property impairments | 18,518 | 20,199 | |||||||||||||
Net loss on sale of assets and other | 800 | 535 | |||||||||||||
Loss on extinguishment of debt | - | 4,584 | |||||||||||||
Total tax effect of adjustments (1) | (6,668) | (13,380) | |||||||||||||
Total adjustments, net of tax | 20,551 | 0.06 | 41,227 | 0.11 | |||||||||||
Adjusted net income (loss) (non-GAAP) | $ (58,871) | ($0.16) | $ 199,389 | $ 0.54 | |||||||||||
Weighted average diluted shares outstanding | 360,257 | 370,676 | |||||||||||||
Adjusted diluted net income (loss) per share (non-GAAP) | $ (0.16) | $ 0.54 | |||||||||||||
Nine months ended September 30, | |||||||||||||||
2020 | 2019 | ||||||||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | |||||||||||
Net income (loss) attributable to Continental Resources (GAAP) | $ (504,372) | $ (1.39) | $ 581,695 | $ 1.56 | |||||||||||
Adjustments: | |||||||||||||||
Non-cash (gain) loss on derivatives | 8,560 | (1,303) | |||||||||||||
Property impairments | 264,976 | 66,854 | |||||||||||||
Net loss on sale of assets and other | 5,914 | 647 | |||||||||||||
(Gain) loss on extinguishment of debt | (64,573) | 4,584 | |||||||||||||
Total tax effect of adjustments (1) | (52,644) | (17,342) | |||||||||||||
Total adjustments, net of tax | 162,233 | 0.44 | 53,440 | 0.14 | |||||||||||
Adjusted net income (loss) (non-GAAP) | $ (342,139) | ($0.95) | $ 635,135 | $ 1.70 | |||||||||||
Weighted average diluted shares outstanding | 361,948 | 373,506 | |||||||||||||
Adjusted diluted net income (loss) per share (non-GAAP) | $ (0.95) | $ 1.70 | |||||||||||||
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2020 and 2019 to the pre-tax amount of adjustments associated with our operations in the United States. | |||||||||||||||
Non-GAAP Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At September 30, 2020, the Company's total debt was $5.63 billion and its net debt amounted to $5.61 billion, representing total debt of $5.63 billion less cash and cash equivalents of $21.2 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Non-GAAP EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and gains and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||
In thousands | 2020 | 2019 | 2020 | 2019 | ||||
Net income (loss) | $ (81,583) | $ 157,422 | $ (510,498) | $ 580,365 | ||||
Interest expense | 63,884 | 68,090 | 192,547 | 204,398 | ||||
Provision (benefit) for income taxes | (13,972) | 49,747 | (138,350) | 177,386 | ||||
Depreciation, depletion, amortization and accretion | 461,191 | 484,031 | 1,288,185 | 1,464,672 | ||||
Property impairments | 18,518 | 20,199 | 264,976 | 66,854 | ||||
Exploration expenses | 1,041 | 2,472 | 14,638 | 7,399 | ||||
Impact from derivative instruments: | ||||||||
Total (gain) loss on derivatives, net | 17,853 | (1,195) | 25,635 | (53,519) | ||||
Total cash (paid) received on derivatives, net | (9,952) | 30,484 | (17,075) | 52,216 | ||||
Non-cash (gain) loss on derivatives, net | 7,901 | 29,289 | 8,560 | (1,303) | ||||
Non-cash equity compensation | 16,331 | 12,870 | 48,086 | 37,153 | ||||
Gain (loss) on extinguishment of debt | - | 4,584 | (64,573) | 4,584 | ||||
EBITDAX (non-GAAP) | $ 473,311 | $ 828,704 | $ 1,103,571 | $ 2,541,508 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||
In thousands | 2020 | 2019 | 2020 | 2019 | ||||
Net cash provided by operating activities | $ 291,197 | $ 806,972 | $ 934,767 | $ 2,311,876 | ||||
Current income tax provision (benefit) | - | - | (2,223) | - | ||||
Interest expense | 63,884 | 68,090 | 192,547 | 204,398 | ||||
Exploration expenses, excluding dry hole costs | 901 | 2,472 | 8,182 | 7,399 | ||||
Gain (loss) on sale of assets and other, net | (800) | (535) | (5,914) | (647) | ||||
Other, net | 1,004 | (2,142) | (6,515) | (9,220) | ||||
Changes in assets and liabilities | 117,125 | (46,153) | (17,273) | 27,702 | ||||
EBITDAX (non-GAAP) | $ 473,311 | $ 828,704 | $ 1,103,571 | $ 2,541,508 | ||||
Non-GAAP Free Cash Flow and Free Cash Flow Yield
Our presentation of free cash flow and free cash flow yield are non-GAAP measures. We define free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, excluding acquisitions, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our relationship formed with Franco-Nevada in 2018 to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Free cash flow yield is calculated by taking free cash flow divided by the market capitalization of the Company at a given date. Management believes these measures are useful to management and investors as measures of a company's ability to internally fund its capital expenditures, to service or incur additional debt, and to measure management's success in creating shareholder value. From time to time the Company provides forward-looking free cash flow and free cash flow yield estimates or targets; however, the Company is unable to provide a quantitative reconciliation of these forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
The following table reconciles net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the three months ended September 30, 2020.
In thousands | 3Q 2020 | |
Net cash provided by operating activities (GAAP) | $ 291,197 | |
Exclude: Changes in working capital items | 117,125 | |
Less: Capital expenditures (1) | (149,371) | |
Plus: Contributions from noncontrolling interest | 516 | |
Less: Distributions to noncontrolling interest | (1,171) | |
Free cash flow (non-GAAP) | $ 258,296 | |
(1) Capital expenditures are calculated as follows: | ||
In thousands | 3Q 2020 | |
Cash paid for capital expenditures | $ 163,092 | |
Less: Total acquisitions | (4,092) | |
Plus: Change in accrued capital expenditures & other | (9,629) | |
Plus: Exploratory seismic costs | - | |
Capital expenditures | $ 149,371 |
Non-GAAP Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following tables present a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.
Three months ended September 30, 2020 | Three months ended September 30, 2019 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $623,955 | $77,513 | $701,468 | $989,297 | $92,103 | $1,081,400 | ||||||
Less: Transportation expenses | (46,890) | (8,382) | (55,272) | (53,038) | (9,000) | (62,038) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $577,065 | $69,131 | $646,196 | $936,259 | $83,103 | $1,019,362 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 16,063 | 70,510 | 27,815 | 18,258 | 74,101 | 30,608 | ||||||
Net sales price (non-GAAP) | $35.93 | $0.98 | $23.23 | $51.28 | $1.12 | $33.30 | ||||||
Nine months ended September 30, 2020 | Nine months ended September 30, 2019 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $1,556,445 | $182,418 | $1,738,863 | $2,905,561 | $422,848 | $3,328,409 | ||||||
Less: Transportation expenses | (120,780) | (27,299) | (148,079) | (140,666) | (23,903) | (164,569) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $1,435,665 | $155,119 | $1,590,784 | $2,764,895 | $398,945 | $3,163,840 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 42,583 | 216,735 | 78,706 | 53,179 | 224,045 | 90,520 | ||||||
Net sales price (non-GAAP) | $33.71 | $0.72 | $20.21 | $51.99 | $1.78 | $34.95 |
Non-GAAP Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||
2020 | 2019 | 2020 | 2019 | |||||
Total G&A per Boe (GAAP) | $ 1.63 | $ 1.54 | $ 1.65 | $ 1.57 | ||||
Less: Non-cash equity compensation per Boe | (0.59) | (0.42) | (0.61) | (0.41) | ||||
Cash G&A per Boe (non-GAAP) | $ 1.04 | $ 1.12 | $ 1.04 | $ 1.16 |
Continental Resources, Inc. | |||||
2020 Guidance | |||||
As of November 5, 2020 | |||||
2020 | |||||
Full-year average oil production (Bopd) | 155,000 to 165,000 | ||||
Full-year average natural gas production (Mcfpd) | 800,000 to 820,000 | ||||
Capital expenditures budget | $1.2 billion | ||||
Operating Expenses: | |||||
Production expense per Boe | Updated: $3.50 to $3.75 | ||||
Previous: $3.50 to $4.00 | |||||
Production tax (% of net oil & gas revenue) | 8.3% to $8.5% | ||||
Cash G&A expense per Boe(1) | Updated: $1.10 to $1.30 | ||||
Previous: $1.10 to $1.40 | |||||
Non-cash equity compensation per Boe | $0.50 to $0.60 | ||||
DD&A per Boe | $15.00 to $17.00 | ||||
Average Price Differentials: | |||||
NYMEX WTI crude oil(2) (per barrel of oil) | ($5.50) to ($6.50) | ||||
Henry Hub natural gas(3) (per Mcf) | ($0.75) to ($1.25) | ||||
1. | Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is a projected range of $1.60 to $1.90 per Boe. | ||||
2. | Includes second half 2020 guidance of ($5.00) to ($5.50). | ||||
3. | Includes natural gas liquids production in differential range. Includes second half 2020 guidance of ($0.50) to ($1.00). |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-third-quarter-2020-results-preliminary-2021-outlook-301167535.html
SOURCE Continental Resources
OKLAHOMA CITY, Oct. 8, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") plans to announce third quarter 2020 results on Thursday, November 5, 2020 after the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss third quarter 2020 results on Friday, November 6, 2020 at 10:00 a.m. ET (9:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Logo: https://mma.prnewswire.com/media/95419/continental_resources_logo.jpg
Time and date: | 10:00 a.m. ET, Friday, November 6, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8013830 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10147993 |
The Company plans to publish a third quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Friday, November 6, 2020.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-third-quarter-2020-results-on-thursday-november-5-2020-301149026.html
SOURCE Continental Resources
OKLAHOMA CITY, Aug. 3, 2020 /PRNewswire/ --
Curtailed Operated Oil Volumes in 2Q20 Estimated to Generate $90 Million in Incremental Cash Flow from Operations at $40 WTI
• Approximately 55% of Oil Volumes (7.8 MMBo) Curtailed in 2Q20
• 202,815 Boepd Average Daily 2Q20 Production
2020 Full-Year Average Production of 155,000 to 165,000 Bopd & 800,000 to 820,000 Mcfpd
• 3Q20 Average Production of 280,000 to 300,000 Boepd
• 2020 Exit Rate Production of 310,000 to 330,000 Boepd
Forecasting Approx. $1.3 Billion Annual Cash Flow from Operations and $200 Million Annual Free Cash Flow (FCF) (Non-GAAP) in 2020 at $40 WTI
• $615 Million Cash Flow from Operations and $500 Million FCF in 2H20
Targeting Total Debt of $5.4 Billion to $5.5 Billion by YE20
Low Cost Industry Leadership: Reinstating Original per Unit Cost Guidance
• $3.58 Production Expense per Boe in 2Q20; in Line with Original Guidance even with Production Curtailments
On Track for Previously Revised $1.2 Billion or Lower Capital Spend in 2020
• Est. $1.2 Billion D&C Maintenance Capital to Hold Production Flat YoY in 2021
Operating Efficiencies Continue to Drive Year-Over-Year All-In Well Costs Lower
• Bakken Completed Well Cost Decreased 12% to $7.2 Million per Well (Approx. 70% Structural)
• South Completed Well Cost Decreased 10% to $9.5 Million per Well (Approx. 80% Structural)
Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced second quarter 2020 operating and financial results.
Logo - https://mma.prnewswire.com/media/95419/continental_resources_logo.jpg
The Company reported a net loss of $239.3 million, or $0.66 per diluted share, for the quarter ended June 30, 2020. In second quarter 2020, typically excluded items in aggregate represented a decrease of $16.4 million, or $0.05 per diluted share, in Continental's reported net loss. Adjusted net loss for second quarter 2020 was $255.7 million, or $0.71 per diluted share (non-GAAP).
Adjusted net loss, adjusted net loss per share, EBITDAX, net debt, free cash flow, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
"Continental has proactively responded to the unprecedented events that have shaped the global commodity landscape in 2020. By deferring volumes in the second quarter of 2020, we expect to generate an estimated $90 million in incremental cash flow from operations at $40 WTI. Combined with our strong asset position and unmatched shareholder alignment, we believe Continental's equity reflects an uncommon value," said Bill Berry, Chief Executive Officer.
Production Update
Second quarter 2020 total production averaged 202,815 Boepd. Second quarter 2020 oil production averaged 95,174 Bopd. Second quarter 2020 natural gas production averaged 645.8 MMcfpd. During the second quarter, approximately 55% of the Company's operated oil volumes were shut in, or approximately 7.8 MMBo.
The following table provides the Company's average daily production by region for the periods presented.
2Q | 2Q | YTD | YTD | ||||
Boe per day | 2020 | 2019 | 2020 | 2019 | |||
Bakken | 88,822 | 194,014 | 145,162 | 196,704 | |||
South | 107,083 | 128,777 | 129,547 | 126,568 | |||
All other | 6,910 | 8,623 | 7,119 | 8,551 | |||
Total | 202,815 | 331,414 | 281,828 | 331,823 |
Financial Update
"We have made tremendous strides to remain the low cost industry leader amongst our oil-weighted peers. We are reinstituting per unit cost guidance and expect LOE, G&A and DD&A per Boe to be within our previous guidance, reflecting exceptional cost management and capital efficiency," said John Hart, Chief Financial Officer. "While our debt increased modestly due to the pandemic, it has not changed our long-term strategy to continue focusing on debt reduction, with a total debt target of $5.4 billion to $5.5 billion by year end 2020."
Three Months Ended | Six Months Ended | |||
2Q20 Financial Update | June 30, 2020 | June 30, 2020 | ||
Cash and Cash Equivalents | $6.7 million | |||
Total Debt | $5.74 billion | |||
Net Debt (non-GAAP)(1) | $5.74 billion | |||
Average Net Sales Price (non-GAAP)(1) | ||||
Per Barrel of Oil | $16.35 | $32.37 | ||
Per Mcf of Gas | $0.12 | $0.59 | ||
Per Boe | $7.88 | $18.56 | ||
Production Expense per Boe | $3.58 | $3.60 | ||
Total G&A Expenses per Boe | $2.30 | $1.66 | ||
Crude Oil Differential per Barrel | ($7.54) | ($6.66) | ||
Natural Gas Differential per Mcf | ($1.58) | ($1.26) | ||
Non-Acquisition Capital Expenditures | $190.8 million | $841.5 million | ||
Exploration & Development Drilling & Completion | $155.8 million | $699.8 million | ||
Leasehold | $6.2 million | $25.5 million | ||
Minerals, of which 80% was Recouped from FNV | $2.7 million | $23.3 million | ||
Workovers, Recompletions and Other | $26.1 million | $92.9 million |
(1) Net debt and net sales prices represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Guidance Update
"Our updated 2020 guidance emphasizes our ongoing commitment to shareholder value. This is driven by the strength of our assets, the quality and flexibility of our operations and the outstanding performance by our teams, companywide," said Jack Stark, President and Chief Operating Officer. "Going forward, shareholder value remains our top priority as we continue to drive down costs, maximize free cash flow and focus on reducing debt."
The Company has updated its 2020 annual production guidance to 155,000 to 165,000 Bopd and 800 to 820 MMcfpd. The Company has updated its third quarter 2020 production guidance to 280,000 to 300,000 Boepd and its 2020 exit rate production guidance to 310,000 to 330,000 Boepd. As of June 30, 2020, the Company has 215 wells in progress and expects to end the year with 140. The Company expects to average 7.7 drilling rigs and 2.5 stimulation crews in 2020.
Revised production guidance is forecasted to generate approximately $1.3 billion of annual cash flow from operations and $200 million of annual free cash flow at $40 per barrel WTI, with $615 million of cash flow from operations and $500 million of free cash flow in the second half of 2020. The Company believes it is essential to prioritize the balance sheet and is targeting total debt of $5.4 billion to $5.5 billion by year end 2020.
The Company maintains its commitment to low cost industry leadership amongst oil-weighted peers. In spite of significant production curtailments in the second quarter of 2020, the Company is reinstating previously suspended per unit cost guidance metrics in 2020. Production expense is expected to be $3.50 to $4.00 per Boe in 2020. Total G&A expense, which is comprised of cash and non-cash G&A expense, is expected to be $1.60 to $2.00 per Boe in 2020. Continental expects 2020 guidance for DD&A of $15.00 to $17.00 per Boe, reflecting strong well productivity and capital efficiency.
The Company is on track to achieve its previously revised 2020 Capex guidance of $1.2 billion or lower, a 55% decrease from original guidance of $2.65 billion. The Company continues to drive maintenance capital lower and estimates $1.2 billion D&C maintenance capital or lower to hold production flat year-over-year in 2021.
Bakken completed well cost has decreased 12% year-over-year to $7.2 million per well, with approximately 70% of these savings being structural and South completed well cost has decreased 10% year-over-year to $9.5 million per well, with approximately 80% of these savings being structural. Both the Bakken and South completed well costs include D&C and full facilities costs, including artificial lift.
The Company's full 2020 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended June 30, | Six months ended June 30, | ||||||
2020 | 2019 | 2020 | 2019 | ||||
Average daily production: | |||||||
Crude oil (Bbl per day) | 95,174 | 193,586 | 147,922 | 193,753 | |||
Natural gas (Mcf per day) | 645,846 | 826,969 | 803,434 | 828,422 | |||
Crude oil equivalents (Boe per day) | 202,815 | 331,414 | 281,828 | 331,823 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||||
Crude oil ($/Bbl) | $ 16.35 | $ 54.66 | $ 32.37 | $ 52.36 | |||
Natural gas ($/Mcf) | $ 0.12 | $ 1.66 | $ 0.59 | $ 2.11 | |||
Crude oil equivalents ($/Boe) | $ 7.88 | $ 36.03 | $ 18.56 | $ 35.79 | |||
Production expenses ($/Boe) | $ 3.58 | $ 3.74 | $ 3.60 | $ 3.66 | |||
Production taxes (% of net crude oil and gas sales) | 7.8% | 8.7% | 8.7% | 8.4% | |||
DD&A ($/Boe) | $ 16.07 | $ 16.14 | $ 16.25 | $ 16.37 | |||
Total general and administrative expenses ($/Boe) (2) | $ 2.30 | $ 1.57 | $ 1.66 | $ 1.58 | |||
Net income (loss) attributable to Continental Resources (in thousands) | $ (239,286) | $ 236,557 | $ (424,950) | $ 423,533 | |||
Diluted net income (loss) per share attributable to Continental Resources | $ (0.66) | $ 0.63 | $ (1.17) | $ 1.13 | |||
Adjusted net income (loss) (non-GAAP) (in thousands) (1) | $ (255,702) | $ 219,136 | $ (283,268) | $ 435,746 | |||
Adjusted diluted net income (loss) per share (non-GAAP) (1) | $ (0.71) | $ 0.59 | $ (0.78) | $ 1.16 | |||
Net cash provided by (used in) operating activities (in thousands) | $ (20,248) | $ 783,396 | $ 643,570 | $ 1,504,904 | |||
EBITDAX (non-GAAP) (in thousands) (1) | $ 36,013 | $ 858,019 | $ 630,260 | $ 1,712,804 |
(1) Net sales prices, adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.45, $1.17, $1.04, and $1.18 for 2Q 2020, 2Q 2019, YTD 2020, and YTD 2019, respectively. Non-cash equity compensation expense per Boe was $0.85, $0.40, $0.62, and $0.40 for 2Q 2020, 2Q 2019, YTD 2020, and YTD 2019, respectively. |
Second Quarter Earnings Conference Call
The Company plans to host a conference call to discuss second quarter 2020 results on Tuesday, August 4, 2020 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, August 4, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8636766 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10146341 |
The Company plans to publish a second quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Tuesday, August 4, 2020.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, our Form 10-Q for the quarter ended March 31, 2020, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Statements of Income (Loss) | |||||||
Three months ended June 30, | Six months ended June 30, | ||||||
2020 | 2019 | 2020 | 2019 | ||||
Revenues: | In thousands, except per share data | ||||||
Crude oil and natural gas sales | $ 174,652 | $1,137,425 | $1,037,395 | $2,247,009 | |||
Gain (loss) on natural gas derivatives, net | (7,782) | 53,448 | (7,782) | 52,324 | |||
Crude oil and natural gas service operations | 8,789 | 17,509 | 26,847 | 33,284 | |||
Total revenues | 175,659 | 1,208,382 | 1,056,460 | 2,332,617 | |||
Operating costs and expenses: | |||||||
Production expenses | 64,673 | 112,430 | 183,151 | 219,396 | |||
Production taxes | 11,067 | 93,866 | 82,291 | 180,306 | |||
Transportation expenses | 32,305 | 53,393 | 92,807 | 102,531 | |||
Exploration expenses | 1,960 | 3,090 | 13,597 | 4,927 | |||
Crude oil and natural gas service operations | 6,062 | 11,206 | 11,972 | 18,392 | |||
Depreciation, depletion, amortization and accretion | 290,298 | 485,621 | 826,994 | 980,641 | |||
Property impairments | 23,929 | 21,339 | 246,458 | 46,655 | |||
General and administrative expenses | 41,529 | 47,226 | 84,440 | 94,844 | |||
Net (gain) loss on sale of assets and other | 612 | 364 | 5,114 | 112 | |||
Total operating costs and expenses | 472,435 | 828,535 | 1,546,824 | 1,647,804 | |||
Income (loss) from operations | (296,776) | 379,847 | (490,364) | 684,813 | |||
Other income (expense): | |||||||
Interest expense | (65,069) | (68,471) | (128,663) | (136,308) | |||
Gain on extinguishment of debt | 46,942 | - | 64,573 | - | |||
Other | 629 | 723 | 1,161 | 2,077 | |||
(17,498) | (67,748) | (62,929) | (134,231) | ||||
Income (loss) before income taxes | (314,274) | 312,099 | (553,293) | 550,582 | |||
(Provision) benefit for income taxes | 72,143 | (75,649) | 124,378 | (127,639) | |||
Net income (loss) | (242,131) | 236,450 | (428,915) | 422,943 | |||
Net loss attributable to noncontrolling interests | (2,845) | (107) | (3,965) | (590) | |||
Net income (loss) attributable to Continental Resources | $(239,286) | $ 236,557 | $ (424,950) | $ 423,533 | |||
Net income (loss) per share attributable to Continental Resources: | |||||||
Basic | $ (0.66) | $ 0.63 | $ (1.17) | $ 1.14 | |||
Diluted | $ (0.66) | $ 0.63 | $ (1.17) | $ 1.13 |
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Balance Sheets | ||||
In thousands | June 30, 2020 | December 31, 2019 | ||
Assets | ||||
Cash and cash equivalents | $ 6,656 | $ 39,400 | ||
Other current assets | 421,734 | 1,167,615 | ||
Net property and equipment (1) | 14,312,982 | 14,497,726 | ||
Other noncurrent assets | 24,986 | 23,166 | ||
Total assets | $14,766,358 | $ 15,727,907 | ||
Liabilities and equity | ||||
Current liabilities | $ 610,114 | $ 1,336,026 | ||
Long-term debt, net of current portion | 5,740,554 | 5,324,079 | ||
Other noncurrent liabilities | 1,844,438 | 1,959,451 | ||
Equity attributable to Continental Resources | 6,196,144 | 6,741,667 | ||
Equity attributable to noncontrolling interests | 375,108 | 366,684 | ||
Total liabilities and equity | $14,766,358 | $ 15,727,907 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $13.76 billion and $12.77 billion as of June 30, 2020 and December 31, 2019, respectively. |
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||
Three months ended June 30, | Six months ended June 30, | |||||||
In thousands | 2020 | 2019 | 2020 | 2019 | ||||
Net income (loss) | $(242,131) | $236,450 | $ (428,915) | $ 422,943 | ||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||
Non-cash expenses | 216,302 | 552,225 | 938,087 | 1,155,816 | ||||
Changes in assets and liabilities | 5,581 | (5,279) | 134,398 | (73,855) | ||||
Net cash provided by (used in) operating activities | (20,248) | 783,396 | 643,570 | 1,504,904 | ||||
Net cash used in investing activities | (312,204) | (804,674) | (1,018,943) | (1,557,745) | ||||
Net cash provided by (used in) financing activities | (178,463) | (36,626) | 342,629 | (23,456) | ||||
Effect of exchange rate changes on cash | - | 15 | - | 30 | ||||
Net change in cash and cash equivalents | (510,915) | (57,889) | (32,744) | (76,267) | ||||
Cash and cash equivalents at beginning of period | 517,571 | 264,371 | 39,400 | 282,749 | ||||
Cash and cash equivalents at end of period | $ 6,656 | $206,482 | $ 6,656 | $ 206,482 |
Non-GAAP Financial Measures
Non-GAAP adjusted net income (loss) and adjusted net income (loss) per share attributable to Continental
Our presentation of adjusted net income (loss) and adjusted net income (loss) per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income (loss) and adjusted net income (loss) per share represent net income (loss) and diluted net income (loss) per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and gains and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income (loss) and adjusted net income (loss) per share should not be considered in isolation or as an alternative to, or more meaningful than, net income (loss) or diluted net income (loss) per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile net income (loss) and diluted net income (loss) per share as determined under U.S. GAAP to adjusted net income (loss) and adjusted diluted net income (loss) per share for the periods presented.
Three months ended June 30, | ||||||||
2020 | 2019 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income (loss) attributable to Continental Resources (GAAP) | $(239,286) | $ (0.66) | $ 236,557 | $ 0.63 | ||||
Adjustments: | ||||||||
Non-cash (gain) loss on derivatives | 659 | (44,778) | ||||||
Property impairments | 23,929 | 21,339 | ||||||
Net (gain) loss on sale of assets and other | 612 | 364 | ||||||
Gain on extinguishment of debt | (46,942) | - | ||||||
Total tax effect of adjustments (1) | 5,326 | 5,654 | ||||||
Total adjustments, net of tax | (16,416) | (0.05) | (17,421) | (0.04) | ||||
Adjusted net income (loss) (non-GAAP) | $(255,702) | ($0.71) | $ 219,136 | $ 0.59 | ||||
Weighted average diluted shares outstanding | 360,204 | 374,009 | ||||||
Adjusted diluted net income (loss) per share (non-GAAP) | $ (0.71) | $ 0.59 | ||||||
Six months ended June 30, | ||||||||
2020 | 2019 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income (loss) attributable to Continental Resources (GAAP) | $(424,950) | $ (1.17) | $ 423,533 | $ 1.13 | ||||
Adjustments: | ||||||||
Non-cash (gain) loss on derivatives | 659 | (30,592) | ||||||
Property impairments | 246,458 | 46,655 | ||||||
Net (gain) loss on sale of assets and other | 5,114 | 112 | ||||||
Gain on extinguishment of debt | (64,573) | - | ||||||
Total tax effect of adjustments (1) | (45,976) | (3,962) | ||||||
Total adjustments, net of tax | 141,682 | 0.39 | 12,213 | 0.03 | ||||
Adjusted net income (loss) (non-GAAP) | $(283,268) | ($0.78) | $ 435,746 | $ 1.16 | ||||
Weighted average diluted shares outstanding | 362,804 | 374,557 | ||||||
Adjusted diluted net income (loss) per share (non-GAAP) | $ (0.78) | $ 1.16 |
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2020 and 2019 to the pre-tax amount of adjustments associated with our operations in the United States. |
Non-GAAP Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At June 30, 2020, the Company's total debt was $5.74 billion and its net debt amounted to $5.74 billion, representing total debt of $5.74 billion less cash and cash equivalents of $6.7 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Non-GAAP EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and gains and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income/loss or net cash provided by/used in operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by/used in operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income/loss to EBITDAX for the periods presented.
Three months ended June 30, | Six months ended June 30, | |||||||
In thousands | 2020 | 2019 | 2020 | 2019 | ||||
Net income (loss) | $(242,131) | $236,450 | $(428,915) | $ 422,943 | ||||
Interest expense | 65,069 | 68,471 | 128,663 | 136,308 | ||||
Provision (benefit) for income taxes | (72,143) | 75,649 | (124,378) | 127,639 | ||||
Depreciation, depletion, amortization and accretion | 290,298 | 485,621 | 826,994 | 980,641 | ||||
Property impairments | 23,929 | 21,339 | 246,458 | 46,655 | ||||
Exploration expenses | 1,960 | 3,090 | 13,597 | 4,927 | ||||
Impact from derivative instruments: | ||||||||
Total (gain) loss on derivatives, net | 7,782 | (53,448) | 7,782 | (52,324) | ||||
Total cash (paid) received on derivatives, net | (7,123) | 8,670 | (7,123) | 21,732 | ||||
Non-cash (gain) loss on derivatives, net | 659 | (44,778) | 659 | (30,592) | ||||
Non-cash equity compensation | 15,314 | 12,177 | 31,755 | 24,283 | ||||
Gain on extinguishment of debt | (46,942) | - | (64,573) | - | ||||
EBITDAX (non-GAAP) | $ 36,013 | $858,019 | $ 630,260 | $1,712,804 | ||||
The following table provides a reconciliation of our net cash provided by/used in operating activities to EBITDAX for the periods presented.
Three months ended June 30, | Six months ended June 30, | |||||||
In thousands | 2020 | 2019 | 2020 | 2019 | ||||
Net cash provided by (used in) operating activities | $ (20,248) | $783,396 | $ 643,570 | $1,504,904 | ||||
Current income tax provision (benefit) | - | - | (2,223) | - | ||||
Interest expense | 65,069 | 68,471 | 128,663 | 136,308 | ||||
Exploration expenses, excluding dry hole costs | 1,903 | 3,090 | 7,281 | 4,927 | ||||
Gain (loss) on sale of assets and other, net | (612) | (364) | (5,114) | (112) | ||||
Other, net | (4,518) | (1,853) | (7,519) | (7,078) | ||||
Changes in assets and liabilities | (5,581) | 5,279 | (134,398) | 73,855 | ||||
EBITDAX (non-GAAP) | $ 36,013 | $858,019 | $ 630,260 | $1,712,804 |
Non-GAAP Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following tables present a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.
Three months ended June 30, 2020 | Three months ended June 30, 2019 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $158,720 | $15,932 | $174,652 | $1,005,146 | $132,279 | $1,137,425 | ||||||
Less: Transportation expenses | (23,518) | (8,787) | (32,305) | (45,981) | (7,412) | (53,393) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $135,202 | $7,145 | $142,347 | $959,165 | $124,867 | $1,084,032 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 8,270 | 58,772 | 18,065 | 17,549 | 75,254 | 30,091 | ||||||
Net sales price (non-GAAP) | $16.35 | $0.12 | $7.88 | $54.66 | $1.66 | $36.03 | ||||||
Six months ended June 30, 2020 | Six months ended June 30, 2019 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $932,490 | $104,905 | $1,037,395 | $1,916,264 | $330,745 | $2,247,009 | ||||||
Less: Transportation expenses | (73,890) | (18,917) | (92,807) | (87,628) | (14,903) | (102,531) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $858,600 | $85,988 | $944,588 | $1,828,636 | $315,842 | $2,144,478 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 26,521 | 146,225 | 50,891 | 34,922 | 149,944 | 59,912 | ||||||
Net sales price (non-GAAP) | $32.37 | $0.59 | $18.56 | $52.36 | $2.11 | $35.79 |
Non-GAAP Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended June 30, | Six months ended June 30, | |||||||
2020 | 2019 | 2020 | 2019 | |||||
Total G&A per Boe (GAAP) | $2.30 | $1.57 | $1.66 | $1.58 | ||||
Less: Non-cash equity compensation per Boe | (0.85) | (0.40) | (0.62) | (0.40) | ||||
Cash G&A per Boe (non-GAAP) | $1.45 | $1.17 | $1.04 | $1.18 |
Non-GAAP Free Cash Flow
Our presentation of projected free cash flow is a non-GAAP measure. We define projected free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, excluding acquisitions, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our relationship with Franco-Nevada to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Management believes that this measure is useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. From time to time the Company provides forward-looking free cash flow estimates or targets; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Continental Resources, Inc. | |||
2020 Guidance | |||
As of August 3, 2020 | |||
2020 Original | 2020 Updated | ||
Full-year average oil production (Bopd) | 198,000 to 201,000 | 155,000 to 165,000 | |
Full-year average natural gas production (Mcfpd) | 935,000 to 960,000 | 800,000 to 820,000 | |
Capital expenditures budget | $2.65 Billion | $1.2 billion | |
Operating Expenses: | |||
Production expense per Boe | $3.50 to $4.00 | $3.50 to $4.00 | |
Production tax (% of net oil & gas revenue) | 8.3% to $8.5% | 8.3% to $8.5% | |
Cash G&A expense per Boe(1) | $1.10 to $1.40 | $1.10 to $1.40 | |
Non-cash equity compensation per Boe | $0.50 to $0.60 | $0.50 to $0.60 | |
DD&A per Boe | $15.00 to $17.00 | $15.00 to $17.00 | |
Average Price Differentials: | |||
NYMEX WTI crude oil(2)(per barrel of oil) | ($4.50) to ($5.50) | ($5.50) to ($6.50) | |
Henry Hub natural gas(3)(per Mcf) | ($0.50) to ($1.00) | ($0.75) to ($1.25) |
1. | Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is a projected range of $1.60 to $2.00 per Boe. | ||
2. | Includes second half 2020 guidance of ($5.00) to ($5.50). | ||
3. | Includes natural gas liquids production in differential range. Includes second half 2020 guidance of ($0.50) to ($1.00). |
2020 Capital Expenditures | ||||
The following table provides the breakout of budgeted capital expenditures: | ||||
($ in Millions) | North D&C | South D&C | Leasehold, Facilities, Other | |
Capex | $635 | $315 | $250 | |
2020 Operational Detail | ||||
The following table provides additional operational detail for wells expected to have first production in 2020: | ||||
Asset | Average Rigs | Gross Operated Wells | Net Operated Wells | Total Net Wells(1) |
North | 3.4 | 116 | 76 | 100 |
South | 4.3 | 54 | 38 | 42 |
Total | 7.7 | 170 | 114 | 142 |
1. Represents projected net operated and non-operated wells with first production. |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-second-quarter-2020-results-and-updates-guidance-301105016.html
SOURCE Continental Resources
OKLAHOMA CITY, July 15, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") plans to announce second quarter 2020 results on Monday, August 3, 2020 after the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss second quarter 2020 results on Tuesday, August 4, 2020 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
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Time and date: | 12 p.m. ET, Tuesday, August 4, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8636766 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10146341 |
The Company plans to publish a second quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Tuesday, August 4, 2020.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-second-quarter-2020-results-on-monday-august-3-2020-301094332.html
SOURCE Continental Resources
OKLAHOMA CITY, June 29, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced that its Founder and Executive Chairman, Harold Hamm, purchased 4,736,264 shares of Continental common stock on the open market from June 22, 2020 to June 25, 2020, at market prices. This brings Mr. Hamm's total holdings, as of June 25, 2020, to 289,659,385 shares, or approximately 79.3% of the Company's total common shares outstanding at April 30, 2020.
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In addition, Mr. Hamm entered into a 10b5-1 plan pursuant to Rule 10b5-1 under the Securities Exchange Act of 1934, as amended ("Rule 10b5-1"). It is Mr. Hamm's intention to acquire shares of the Company's common stock consistent with certain timing, volume and price limitations. The 10b5-1 trading plan was entered into on June 25, 2020.
"I firmly believe Continental's current share price reflects an uncommon value as the global pandemic has negatively impacted worldwide crude oil demand. Recent purchases underscore my confidence in the Company's continued operational excellence and strong financial performance. Continental is poised to deliver significant shareholder value for many years to come and I believe there is no management team more aligned with shareholders than Continental," said Harold Hamm, Executive Chairman.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-founder-and-executive-chairman-harold-hamm-purchases-4-736-264-shares-of-company-stock-adopts-10b5-1-purchase-plan-301085294.html
SOURCE Continental Resources
OKLAHOMA CITY, June 18, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced an update on its voluntary production curtailments.
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The Company previously announced it would curtail 70% of operated oil production in May, with continued curtailments into June. In July, the Company expects to partially begin resuming production but still expects to curtail approximately 50% of its operated oil production.
June 2020 total production is expected to average 150,000 to 160,000 Boepd. Second quarter 2020 total production is expected to average 200,000 to 205,000 Boepd. July 2020 total production is expected to average 225,000 to 250,000 Boepd.
"Continental elected to defer production in order to preserve shareholder value over volumes, and maximize the economics of the barrels we produce. As oil prices have stabilized and begun to recover, we have partially resumed production. As improved supply and demand fundamentals benefit oil prices, we expect to continue restoring production in subsequent months," said Bill Berry, Chief Executive Officer.
The Company expects to further revisit previously suspended guidance when announcing second quarter 2020 results.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact are forward-looking statements, including, but not limited to, statements, information, forecasts or expectations regarding the Company's business and future plans, including those relating to its share repurchase program, payment of dividends, debt reduction goals, free cash flow generation and liquidity expectations, and its expectations regarding the achievement of ROCE goals. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-update-on-voluntary-production-curtailments-301079848.html
SOURCE Continental Resources
OKLAHOMA CITY, June 15, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today highlighted its longstanding commitment to Environmental, Social and Corporate Governance (ESG) practices and initiatives with the release of its 2019 ESG report.
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"Continental will continue to play a significant role in the American energy renaissance, providing a reliable and low-cost energy source for our nation and our world. We will continue to accomplish this in an environmentally and socially responsible manner, producing light, sweet crude oil the world needs to reduce emissions, while improving lives. In every credible scenario from government and independent forecasts, growth in demand for hydrocarbons is anticipated for the next several decades," said Harold Hamm, Executive Chairman.
Continental's 2019 report provides a comprehensive assessment of the Company's environmental, social and governance practices. The report utilizes a new and better framework that reflects the significant contributions hydrocarbons make to the human element of modern life, and the world's reliance on hydrocarbons for energy supply in the foreseeable future. The report provides the Company's stakeholders – employees, shareholders and communities in which it operates – a view of the Company's unwavering commitment to the low-cost and responsible development of hydrocarbon reserves.
In developing Continental's ESG report, the Company conducted a thorough assessment to identify and prioritize the most significant impact on the Company's stakeholders and operations.
Our assessment included:
"Long before there was an ESG movement, Continental was responsibly managing its operations. We continue those practices today. We are proud to be a leader in developing credible ESG standards and remain committed to delivering results in a clean, efficient manner, while at the same time powering the world," said Bill Berry, Chief Executive Officer.
For more information regarding the Company's ESG philosophy, as well as its 2019 report, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact are forward-looking statements, including, but not limited to, statements, information, forecasts or expectations regarding the Company's business and future plans, including those relating to its share repurchase program, payment of dividends, debt reduction goals, free cash flow generation and liquidity expectations, and its expectations regarding the achievement of ROCE goals. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-highlights-longstanding-commitment-to-esg-issues-2019-report-301077185.html
SOURCE Continental Resources
OKLAHOMA CITY, May 11, 2020 /PRNewswire/ --
360,841 Boepd Average Daily 1Q20 Production; up 9% YoY (56% Oil)
Lowest Cost Producer amongst Oil-Weighted Peers
• $3.61 Production Expense per Boe and $1.31 Total G&A per Boe in 1Q20
Approx. $55 MM Reduction to 2020 G&A through Ongoing Cost Savings Evaluation
$650.7 MM Capex in 1Q20; 2020 Capex Tracking 3% to 5% below Previously Revised $1.2 B Budget
• Zero Stim Crews in the Bakken and Averaging 1 Stim Crew in OK through Remainder of 2020
• Rigs Reduced to 4 by YE20 (80% Reduction from Jan 2020)
$139 MM of Bonds Retired in March/April at a 53% Weighted Average Discount to Par
Strong Portfolio Optionality and Liquidity: Positions Company for Market Recovery
• 70% of Operated Oil Production Voluntarily Curtailed in May (60% Boepd Curtailed)
Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced first quarter 2020 operating and financial results.
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The Company reported a net loss of $185.7 million, or $0.51 per diluted share, for the quarter ended March 31, 2020. In first quarter 2020, typically excluded items in aggregate represented $158.1 million, or $0.43 per diluted share, of Continental's reported net loss. Adjusted net loss for first quarter 2020 was $27.6 million, or $0.08 per diluted share (non-GAAP). Net cash provided by operating activities for first quarter 2020 was $663.8 million and EBITDAX was $594.2 million (non-GAAP).
Adjusted net loss, adjusted net loss per share, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
"This has been an unprecedented global market environment, which has seen crude oil demand fall by approximately 30% due to the COVID-19 pandemic. Continental is committed to preserving value over volumes. Our assets are secure and we are confident that this deferred production will bring more value to our shareholders in the months to come," said Bill Berry, Chief Executive Officer.
Mr. Berry continued, "Our first quarter results underscore the capital efficient and low cost nature of our assets. Continental is financially strong with ample liquidity and no imminent debt maturities. We remain keenly focused on preserving both our assets and shareholder value for better commodity prices in the future. I want to thank our teams for their safe, efficient and best-in-class operations during this time. We look towards a bright future for both Continental and the U.S. oil and natural gas industry."
Production Update
First quarter 2020 total production increased 9% over first quarter 2019, averaging 360,841 Boepd. First quarter 2020 oil production increased 3% over first quarter 2019, averaging 200,671 Bopd. First quarter 2020 natural gas production increased 16% over first quarter 2019, averaging 961.0 MMcfpd.
The following table provides the Company's average daily production by region for the periods presented.
1Q | 1Q | |||
Boe per day | 2020 | 2019 | ||
Bakken | 201,502 | 199,423 | ||
South | 152,010 | 124,335 | ||
All other | 7,329 | 8,478 | ||
Total | 360,841 | 332,236 |
Operations Update
"Our assets continued to deliver consistent and repeatable results in the first quarter. Ongoing operating improvements also drove further capital efficiencies, that continued to increase the barrels produced per dollar spent in both the Bakken and Oklahoma. Importantly, Continental remains a low cost leader amongst our oil-weighted peers. First quarter 2020 production expense per Boe and DD&A per Boe fell within our previous guidance and cash G&A per Boe was materially better. This is a testament to the commitment to excellence by our teams and the unmatched shareholder alignment that are fundamental parts of the culture here at Continental," said Jack Stark, President and Chief Operating Officer.
The Company is currently tracking 3% to 5% below its previously revised $1.2 billion Capex budget. The Company also expects to reduce 2020 G&A by approximately $55 million through its ongoing cost savings evaluation. The Company has 70% of operated oil production voluntarily curtailed in May, or 60% of total operated production on a Boe basis. With the added optionality of having over 75% of its world class assets held by production, the Company is well-positioned for a recovery in market conditions. The Company is currently operating 5 rigs and expects to reduce to 4 rigs by year end 2020. This is an 80% reduction from the beginning of 2020. The Company currently has zero stim crews running in the Bakken and expects to average 1 stim crew in the South for the remainder of 2020. Efficiencies continue to build across all aspects of the Company's operations that are positively impacting performance and reducing costs on a sustainable ongoing basis.
Bakken
In first quarter 2020, Bakken total production averaged 201,502 Boepd and oil production averaged 145,481 Bopd. During the quarter, the Company completed 47 gross (33 net) operated wells with first production. Early results from the Company's 2020 Bakken program continue to perform in line with Bakken program wells completed over the past three years. The Company is operating 2 rigs in the Bakken through year end 2020.
South
In first quarter 2020, South total production averaged 152,010 Boepd and oil production averaged 47,838 Bopd. During the quarter, the Company completed 31 gross (21 net) operated wells with first production. The Company is currently operating 3 rigs in the South, targeting 2 rigs by year end 2020.
Property Impairments
Property impairments increased to $222.5 million for first quarter 2020, compared to $25.3 million for first quarter 2019. Impairments of proved oil and gas properties totaled $181.0 million for first quarter 2020, which resulted from the significant decrease in commodity prices during the quarter. The impairments were recognized on legacy properties in the Red River Units ($166.5 million) and other various non-core properties in the North and South regions. Additionally, in response to decreased crude oil prices, the Company recognized a $24.5 million impairment in first quarter 2020 to reduce the value of its crude oil inventory to estimated net realizable value at March 31, 2020.
Financial Update
Given the uncertainty and volatility of rapidly evolving market conditions, as well as the execution of production curtailments across its operations, the Company is withdrawing all previously issued guidance for 2020 and suspending further guidance. The Company intends to monitor market conditions and issue new guidance at the appropriate time.
1Q20 Financial Update | Three Months Ended March 31, 2020 | |
Cash and Cash Equivalents | $517.6 million | |
Total Debt | $5.97 billion | |
Net Debt (non-GAAP)(1) | $5.45 billion | |
Average Net Sales Price (non-GAAP)(1) | ||
Per Barrel of Oil | $39.64 | |
Per Mcf of Gas | $0.90 | |
Per Boe | $24.44 | |
Production Expense per Boe | $3.61 | |
Total G&A Expenses per Boe | $1.31 | |
Crude Oil Differential per Barrel | ($6.26) | |
Natural Gas Differential per Mcf | ($1.05) | |
Non-Acquisition Capital Expenditures | $650.7 million | |
Exploration & Development Drilling & Completion | $544.0 million | |
Leasehold | $19.3 million | |
Minerals, of which 80% was Recouped from FNV | $20.6 million | |
Workovers, Recompletions and Other | $66.8 million |
(1) Net debt and net sales prices represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended March 31, | |||
2020 | 2019 | ||
Average daily production: | |||
Crude oil (Bbl per day) | 200,671 | 193,921 | |
Natural gas (Mcf per day) | 961,022 | 829,891 | |
Crude oil equivalents (Boe per day) | 360,841 | 332,236 | |
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||
Crude oil ($/Bbl) | $ 39.64 | $ 50.05 | |
Natural gas ($/Mcf) | $ 0.90 | $ 2.56 | |
Crude oil equivalents ($/Boe) | $ 24.44 | $ 35.56 | |
Production expenses ($/Boe) | $ 3.61 | $ 3.59 | |
Production taxes (% of net crude oil and gas sales) | 8.9% | 8.2% | |
DD&A ($/Boe) | $ 16.35 | $ 16.60 | |
Total general and administrative expenses ($/Boe) (2) | $ 1.31 | $ 1.60 | |
Net income (loss) attributable to Continental Resources (in thousands) | $ (185,664) | $ 186,976 | |
Diluted net income (loss) per share attributable to Continental Resources | $ (0.51) | $ 0.50 | |
Adjusted net income (loss) (non-GAAP) (in thousands) (1) | $ (27,567) | $ 216,610 | |
Adjusted diluted net income (loss) per share (non-GAAP) (1) | $ (0.08) | $ 0.58 | |
Net cash provided by operating activities (in thousands) | $ 663,818 | $ 721,508 | |
EBITDAX (non-GAAP) (in thousands) (1) | $ 594,247 | $ 854,785 |
(1) Net sales prices, adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $0.81 and $1.19 for 1Q 2020 and 1Q 2019, respectively. Non-cash equity compensation expense per Boe was $0.50 and $0.41 for 1Q 2020 and 1Q 2019, respectively. |
First Quarter Earnings Conference Call
The Company plans to host a conference call to discuss first quarter 2020 results on Monday, May 11, 2020 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Monday, May 11, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 7881245 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10141773 |
The Company plans to publish a first quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Monday, May 11, 2020.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein, if any, remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
Continental Resources, Inc. and Subsidiaries | |||
Three months ended March 31, | |||
2020 | 2019 | ||
Revenues: | In thousands, except per share data | ||
Crude oil and natural gas sales | $ 862,743 | $1,109,584 | |
Loss on natural gas derivatives, net | - | (1,124) | |
Crude oil and natural gas service operations | 18,058 | 15,774 | |
Total revenues | 880,801 | 1,124,234 | |
Operating costs and expenses: | |||
Production expenses | 118,478 | 106,966 | |
Production taxes | 71,224 | 86,441 | |
Transportation expenses | 60,502 | 49,139 | |
Exploration expenses | 11,637 | 1,837 | |
Crude oil and natural gas service operations | 5,910 | 7,186 | |
Depreciation, depletion, amortization and accretion | 536,696 | 495,019 | |
Property impairments | 222,529 | 25,316 | |
General and administrative expenses | 42,911 | 47,617 | |
Net (gain) loss on sale of assets and other | 4,502 | (252) | |
Total operating costs and expenses | 1,074,389 | 819,269 | |
Income (loss) from operations | (193,588) | 304,965 | |
Other income (expense): | |||
Interest expense | (63,594) | (67,837) | |
Gain on extinguishment of debt | 17,631 | - | |
Other | 532 | 1,355 | |
(45,431) | (66,482) | ||
Income (loss) before income taxes | (239,019) | 238,483 | |
(Provision) benefit for income taxes | 52,235 | (51,990) | |
Net income (loss) | (186,784) | 186,493 | |
Net loss attributable to noncontrolling interests | (1,120) | (483) | |
Net income (loss) attributable to Continental Resources | $(185,664) | $ 186,976 | |
Net income (loss) per share attributable to Continental Resources: | |||
Basic | $ (0.51) | $ 0.50 | |
Diluted | $ (0.51) | $ 0.50 |
Continental Resources, Inc. and Subsidiaries | ||||
In thousands | March 31, 2020 | December 31, 2019 | ||
Assets | ||||
Cash and cash equivalents | $ 517,571 | $ 39,400 | ||
Other current assets | 777,601 | 1,167,615 | ||
Net property and equipment (1) | 14,436,112 | 14,497,726 | ||
Other noncurrent assets | 25,427 | 23,166 | ||
Total assets | $ 15,756,711 | $ 15,727,907 | ||
Liabilities and equity | ||||
Current liabilities | $ 1,082,208 | $ 1,336,026 | ||
Long-term debt, net of current portion | 5,964,589 | 5,324,079 | ||
Other noncurrent liabilities | 1,912,656 | 1,959,451 | ||
Equity attributable to Continental Resources | 6,420,362 | 6,741,667 | ||
Equity attributable to noncontrolling interests | 376,896 | 366,684 | ||
Total liabilities and equity | $ 15,756,711 | $ 15,727,907 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $13.47 billion and $12.77 billion as of March 31, 2020 and December 31, 2019, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||
Three months ended March 31, | ||||
In thousands | 2020 | 2019 | ||
Net income (loss) | $ (186,784) | $ 186,493 | ||
Adjustments to reconcile net income (loss) to net | ||||
Non-cash expenses | 721,785 | 603,591 | ||
Changes in assets and liabilities | 128,817 | (68,576) | ||
Net cash provided by operating activities | 663,818 | 721,508 | ||
Net cash used in investing activities | (706,739) | (753,071) | ||
Net cash provided by financing activities | 521,092 | 13,170 | ||
Effect of exchange rate changes on cash | - | 15 | ||
Net change in cash and cash equivalents | 478,171 | (18,378) | ||
Cash and cash equivalents at beginning of period | 39,400 | 282,749 | ||
Cash and cash equivalents at end of period | $ 517,571 | $ 264,371 |
Non-GAAP Financial Measures
Non-GAAP adjusted net income (loss) and adjusted net income (loss) per share attributable to Continental
Our presentation of adjusted net income (loss) and adjusted net income (loss) per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income (loss) and adjusted net income (loss) per share represent net income (loss) and diluted net income (loss) per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and gains and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income (loss) and adjusted net income (loss) per share should not be considered in isolation or as an alternative to, or more meaningful than, net income (loss) or diluted net income (loss) per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile net income (loss) and diluted net income (loss) per share as determined under U.S. GAAP to adjusted net income (loss) and adjusted diluted net income (loss) per share for the periods presented.
Three months ended March 31, | ||||||||||||||
2020 | 2019 | |||||||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||||||||
Net income (loss) attributable to Continental Resources (GAAP) | $ (185,664) | $ (0.51) | $ 186,976 | $ 0.50 | ||||||||||
Adjustments: | ||||||||||||||
Non-cash loss on derivatives | - | 14,186 | ||||||||||||
Property impairments | 222,529 | 25,316 | ||||||||||||
Net (gain) loss on sale of assets and other | 4,502 | (252) | ||||||||||||
Gain on extinguishment of debt | (17,631) | - | ||||||||||||
Total tax effect of adjustments (1) | (51,303) | (9,616) | ||||||||||||
Total adjustments, net of tax | 158,097 | 0.43 | 29,634 | 0.08 | ||||||||||
Adjusted net income (loss) (non-GAAP) | $ (27,567) | ($0.08) | $ 216,610 | $0.58 | ||||||||||
Weighted average diluted shares outstanding | 365,403 | 374,474 | ||||||||||||
Adjusted diluted net income (loss) per share (non-GAAP) | $ (0.08) | $ 0.58 |
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2020 and 2019 to the pre-tax amount of adjustments associated with our operations in the United States. |
Non-GAAP Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At March 31, 2020, the Company's total debt was $5.97 billion and its net debt amounted to $5.45 billion, representing total debt of $5.97 billion less cash and cash equivalents of $517.6 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Non-GAAP EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and gains and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income/loss or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income/loss to EBITDAX for the periods presented.
Three months ended March 31, | ||||
In thousands | 2020 | 2019 | ||
Net income (loss) | $ (186,784) | $ 186,493 | ||
Interest expense | 63,594 | 67,837 | ||
Provision (benefit) for income taxes | (52,235) | 51,990 | ||
Depreciation, depletion, amortization and accretion | 536,696 | 495,019 | ||
Property impairments | 222,529 | 25,316 | ||
Exploration expenses | 11,637 | 1,837 | ||
Impact from derivative instruments: | ||||
Total loss on derivatives, net | - | 1,124 | ||
Total cash received on derivatives, net | - | 13,062 | ||
Non-cash loss on derivatives, net | - | 14,186 | ||
Non-cash equity compensation | 16,441 | 12,107 | ||
Gain on extinguishment of debt | (17,631) | - | ||
EBITDAX (non-GAAP) | $ 594,247 | $ 854,785 | ||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended March 31, | ||||
In thousands | 2020 | 2019 | ||
Net cash provided by operating activities | $ 663,818 | $ 721,508 | ||
Current income tax provision (benefit) | (2,223) | - | ||
Interest expense | 63,594 | 67,837 | ||
Exploration expenses, excluding dry hole costs | 5,378 | 1,837 | ||
Gain (loss) on sale of assets and other, net | (4,502) | 252 | ||
Other, net | (3,001) | (5,225) | ||
Changes in assets and liabilities | (128,817) | 68,576 | ||
EBITDAX (non-GAAP) | $ 594,247 | $ 854,785 |
Non-GAAP Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following tables present a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.
Three months ended March 31, 2020 | Three months ended March 31, 2019 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $773,770 | $88,973 | $862,743 | $911,118 | $198,466 | $1,109,584 | ||||||
Less: Transportation expenses | (50,372) | (10,130) | (60,502) | (41,648) | (7,491) | (49,139) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $723,398 | $78,843 | $802,241 | $869,470 | $190,975 | $1,060,445 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 18,251 | 87,453 | 32,826 | 17,373 | 74,690 | 29,821 | ||||||
Net sales price (non-GAAP) | $39.64 | $0.90 | $24.44 | $50.05 | $2.56 | $35.56 |
Non-GAAP Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended March 31, | ||||
2020 | 2019 | |||
Total G&A per Boe (GAAP) | $1.31 | $1.60 | ||
Less: Non-cash equity compensation per Boe | (0.50) | (0.41) | ||
Cash G&A per Boe (non-GAAP) | $0.81 | $1.19 |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-first-quarter-2020-results-301056347.html
SOURCE Continental Resources
OKLAHOMA CITY, April 27, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") plans to announce first quarter 2020 results on Monday, May 11, 2020 before the open of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss first quarter 2020 results on Monday, May 11, 2020 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Monday, May 11, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 7881245 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10141773 |
The Company plans to publish a first quarter 2020 summary presentation to its website at www.CLR.com prior to the start of its conference call on Monday, May 11, 2020.
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About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-first-quarter-2020-results-on-monday-may-11-2020-301047765.html
SOURCE Continental Resources
OKLAHOMA CITY, April 24, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced that, due to the public health and safety concerns related to the coronavirus (COVID-19) pandemic and recommendations and orders from federal and Oklahoma authorities, the location of its annual meeting has been changed to a virtual format.
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As previously announced, the annual meeting will be held on Thursday, May 14, 2020 at 10:00 a.m., Central Daylight Time ("CDT"). Online access to the meeting will begin at 9:45 a.m. CDT. The annual meeting will be presented in audio only format. Shareholders will not be able to attend the annual meeting in person. Information regarding attending the virtual meeting, including the meeting rules, can be found by visiting www.CLR.com.
Registering to Attend the Virtual Meeting as a Shareholder of Record
If you were a shareholder of record as of March 18, 2020 (i.e., you held your shares in your own name as reflected in the records of our transfer agent, American Stock Transfer & Trust Company ("AST")), you can attend the meeting and register to participate in the annual meeting by accessing https://web.lumiagm.com/294221297 and selecting the button "I have a Control Number." You will then be directed to a screen where you will enter: (i) the 11-digit control number on the proxy card previously sent to you by AST; and (ii) the meeting password "continental2020". Please note the meeting password is case sensitive. Once you have completed these steps, select the "login" button, which will take you to the annual meeting page where you can vote, submit written questions and listen to the meeting (referred to in this release as the "Meeting Page").
Registering to Attend the Annual Meeting as a Beneficial Owner
If you were a beneficial owner of record as of March 18, 2020 (i.e., you held your shares in an account at a brokerage firm, bank or other similar agent), you will need to obtain a legal proxy from your broker, bank or other agent to register to participate in the annual meeting. Once you have received a legal proxy from your broker, bank or other agent, it should be emailed to our transfer agent, AST, at proxy@astfinancial.com, and should be labeled "request for Co. #15389 control number" in the subject line. Requests for registration must be received by AST no later than 5:00 p.m. Eastern Daylight Time, on Friday, May 8, 2020. You will then receive a confirmation of your registration, with an 11-digit control number, by email from AST. At the time of the meeting, follow the directions appearing above under the heading "Registering to Attend the Virtual Meeting as a Shareholder of Record", except you will enter the 11-digit control number received as a result of submitting your legal proxy to AST.
Only shareholders of record and beneficial owners of record who have registered as described above will be allowed to vote and ask questions during the annual meeting.
Asking Questions
If you are attending the annual meeting as a shareholder of record or beneficial owner, who has registered for the meeting, you can ask questions by clicking the messaging icon on the right side of the toolbar appearing at the top of the Meeting Page and then typing and submitting your question.
Voting Shares
If you are attending the annual meeting as a shareholder of record or beneficial owner and you have registered for the meeting, you can vote during the meeting by clicking the link "Proxy Voting Site" on the Meeting Page and following the prompts.
Whether you plan to attend the annual meeting, we urge you to vote in advance of the meeting by one of the methods described in the proxy materials for the annual meeting.
The proxy materials previously distributed, including the proxy card sent to registered holders and the notice regarding the availability of proxy materials sent to beneficial owners, will not be updated to reflect the change in location and may continue to be used to vote your shares in connection with the annual meeting.
Attending the Annual Meeting as a Guest
If you are a record holder or beneficial owner and would like to enter the annual meeting as a guest in listen-only mode, go to https://web.lumiagm.com/294221297 and select the button "I am a guest". Please note you will not have the ability to ask questions or vote during the meeting if you participate as a guest.
Inspection of Shareholder Lists
Continental's offices are currently closed to the public in compliance with recommendations and orders from federal and Oklahoma authorities related to the coronavirus (COVID-19) pandemic. Shareholders wishing to inspect shareholder lists in advance of the annual meeting should send an email to ShareholderList@clr.com and follow the instructions received in response to the email.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-changes-its-annual-shareholders-meeting-to-a-virtual-format-301047011.html
SOURCE Continental Resources
OKLAHOMA CITY, April 7, 2020 /PRNewswire/ -- In response to the demand destruction attributable to COVID-19, Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced the following:
"Continental will continue to take decisive action to maximize cash flow generation, accomplish cost savings initiatives and prioritize the strength of our balance sheet," said Bill Berry, Chief Executive Officer. "Global crude oil and product demand is estimated to have been impacted by 30% due to COVID-19. Accordingly, we are reducing our production for April and May 2020 in a similar range."
Furthermore, the Board of Directors has made the decision to suspend the quarterly dividend until further notice. This is part of the Company's proactive strategy to manage cash flow in a challenging commodity price environment.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact are forward-looking statements, including, but not limited to, statements, information, forecasts or expectations regarding the Company's business and future plans, including those relating to its share repurchase program, payment of dividends, debt reduction goals, free cash flow generation and liquidity expectations, and its expectations regarding the achievement of ROCE goals. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
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View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-suspension-of-quarterly-dividend-and-production-update-301036333.html
SOURCE Continental Resources
OKLAHOMA CITY, March 19, 2020 /PRNewswire/ -- In response to the significant drop in commodity prices, Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced a revised 2020 capital budget of $1.2 billion, representing a 55% decrease in capital spend from the Company's original budget of $2.65 billion. The Company expects to be cash flow neutral under $30 per barrel WTI.
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The Company will be reducing its average rig count from 9 to approximately 3 in the Bakken and 10.5 to approximately 4 in Oklahoma. The Company has taken action to implement cost saving initiatives across its operations as part of its ongoing commitment to remain free cash flow positive.
"With a solid balance sheet, peer-leading operating costs and minimal long-term service or supply contracts, Continental will remain flexible and nimble as we optimize development and monitor market conditions," said Bill Berry, Chief Executive Officer. "Continental has a proven track record of adjusting activity and delivering cost savings to maximize cash flow generation in lower price environments."
Harold Hamm, Executive Chairman, said, "This budget adjustment has been precipitated by the collapse of crude oil prices due to the market manipulation of Saudi Arabia and Russia. Illegal dumping of crude oil by these countries began earlier this month at a time of low demand during this unprecedented pandemic of Coronavirus. The U.S. Department of Commerce has been asked by U.S. Senator James Inhofe, Chairman of the Senate Armed Services Committee, to initiate an immediate investigation and to take action under Section 232 of the Trade Expansion Act of 1962 to protect national security and counter this illegal activity. We believe this is a short demand cycle which could see some near-term correction when this illegal dumping practice is halted."
With the revised budget, the Company anticipates 2020 production to be down less than 5% year-over-year. The Company plans to provide additional details surrounding its 2020 guidance updates as part of its first quarter 2020 earnings release, based on its ongoing evaluation of evolving business and market conditions.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact are forward-looking statements, including, but not limited to, statements, information, forecasts or expectations regarding the Company's business and future plans, including those relating to its share repurchase program, payment of dividends, debt reduction goals, free cash flow generation and liquidity expectations, and its expectations regarding the achievement of ROCE goals. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-revised-2020-capital-budget-of-1-2-billion-and-provides-operational-update-301026552.html
SOURCE Continental Resources
OKLAHOMA CITY, Feb. 26, 2020 /PRNewswire/ --
Full-Year 2019 Results
$775.6 Million (MM) in Net Income, or $2.08 per Diluted Share
• $838.7 MM Adjusted Net Income, or $2.25 per Diluted Share (Non-GAAP)
340,395 Boepd Average Daily Production, up 14% Year-over-Year (YoY)
• 197,991 Bopd Average Daily Oil Production; up 18% YoY
$3.1 Billion (B) of Cash Flow from Operations; $608 MM of Free Cash Flow (non-GAAP)
$406 MM in Shareholder Capital Return
• $190 MM Share Repurchases and $18 MM Quarterly Dividend
• $442 MM Total Debt Reduction; $198 MM Net Debt Reduction (Non-GAAP)
No. 1 Oil Producer in Both the Bakken and Oklahoma
• Bakken: 148,416 Average Daily Oil Production up 14% YoY
• South: 41,695 Average Daily Oil Production up 43% YoY
4Q19 Results
$193.9 MM in Net Income, or $0.53 per Diluted Share
• $203.6 MM Adjusted Net Income, or $0.55 per Diluted Share
365,341 Boepd Average Daily Production; up 13% YoY
• 206,249 Bopd Average Daily Oil Production; up 10% over 4Q18
2020 Capital Budget & Guidance
$2.9 B to $3.0 B of Cash Flow from Operations; $350 MM to $400 MM of Free Cash Flow
• Budgeted at $55 WTI and $2.50 HH; $5 Change in WTI = Approx. $300 MM in Cash Flow
Targeting 4% to 6% Production Growth YoY Delivers Average Approx. 10% CAGR for 2019-2020
• Large Projects in 2020 Projected to Drive Double Digit Growth from FY 2020 to 4Q21
$2.65 B Capital Spend in 2020; Flat Capital Spend YoY
• $2.2 B Drilling & Completions; $125 MM for Mineral Acquisitions ($100 MM Funded by FNV)
• Approx. 20% Lower Capital Spend in 2020 than Original Five Year Vision Estimate
• Approx. $700 MM Capital Spend in 2020 with First Production Expected in 2021
Expect to Continue Delivering Lowest Cost Operations Amongst Oil-Weighted Peers
• $3.50 to $4.00 LOE per Boe | $1.60 to $2.00 Total G&A per Boe
Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced its full-year 2019 and fourth quarter 2019 operating and financial results, as well as its 2020 capital expenditures budget and operating plan.
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The Company reported full-year 2019 net income of $775.6 million, or $2.08 per diluted share. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." For full-year 2019, typically excluded items in aggregate represented $63.1 million, or $0.17 per diluted share. Adjusted net income for full-year 2019 was $838.7 million, or $2.25 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2019 was $3.12 billion and EBITDAX was $3.45 billion (non-GAAP).
The Company reported net income of $193.9 million, or $0.53 per diluted share, for the quarter ended December 31, 2019. In fourth quarter 2019, typically excluded items in aggregate represented $9.7 million, or $0.02 per diluted share, of Continental's reported net income. Adjusted net income for fourth quarter 2019 was $203.6 million, or $0.55 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2019 was $803.8 million and EBITDAX was $905.5 million (non-GAAP).
Adjusted net income, adjusted net income per share, EBITDAX, free cash flow, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
2019 Production Update
Full-year 2019 production increased 14% over full-year 2018, averaging 340,395 barrels of oil equivalent per day (Boepd). 2019 oil production increased 18% over 2018, averaging 197,991 barrels of oil per day (Bopd). 2019 natural gas production increased 10% over 2018, averaging 854.4 million cubic feet per day (MMcfpd).
Fourth quarter 2019 total production increased 13% over fourth quarter 2018, averaging 365,341 Boepd. Fourth quarter 2019 oil production increased 10% over fourth quarter 2018, averaging 206,249 Bopd. Fourth quarter 2019 natural gas production increased 16% over fourth quarter 2018, averaging 954.6 MMcfpd.
The following table provides the Company's average daily production by region for the periods presented.
4Q | 4Q | FY | FY | |||||
Boe per day | 2019 | 2018 | 2019 | 2018 | ||||
Bakken | 194,156 | 183,836 | 194,691 | 167,800 | ||||
South | 163,552 | 131,088 | 137,579 | 121,265 | ||||
All other | 7,633 | 9,077 | 8,125 | 9,125 | ||||
Total | 365,341 | 324,001 | 340,395 | 298,190 |
2019 Operations Update
"Operationally, 2019 was an exceptional year. We met or exceeded all of our guidance and delivered 18% oil production growth year-over-year. We also consummated strategic trades, bolt-on acquisitions and leasing in Continental-dominated core areas for approximately $165 million, adding up to 370 gross operated locations to our deep inventory position," said Harold Hamm, Executive Chairman.
CLR Bakken: #1 Bakken Oil Producer; 148,416 Average Daily 2019 Oil Production up 14% over 2018
In 2019, Bakken oil production increased 14% over 2018, averaging 148,416 Bopd. Bakken total production increased 16% over 2018, averaging 194,691 Boepd. During the year, the Company completed 172 gross (119 net) operated wells with first production. These 2019 Bakken program wells are performing in line with wells completed in the Company's 2017 and 2018 Bakken programs, each of which paid out in approximately one year. The 2019 program wells are approximately 75% paid out, as of January 2020. The 2020 Bakken program is projected to continue this performance trend.
CLR South: #1 OK Oil Producer; 41,695 Average Daily 2019 Oil Production up 43% over 2018
In 2019, South oil production increased 43% over 2018, averaging 41,695 Bopd. South total production increased 13% over 2018, averaging 137,579 Boepd. During the year, the Company completed 140 gross (98 net) operated wells with first production in the South. In SCOOP, Project SpringBoard produced an average 25,006 net Bopd, outperforming the Company's expectations announced in third quarter 2018 by 50%.
Year-End 2019 Proved Reserves
The Company's year-end 2019 proved reserves grew 6% year-over-year to 1,619 MMBoe, as of December 31, 2019. These additions equate to a reserve replacement ratio of 178% for 2019 (defined as total change in proved reserves, excluding production, divided by production). SEC prices used for calculating proved reserves were approximately $10.00 less per barrel WTI and $0.50 less per Mcf gas than the SEC prices used in the prior year. The Company's proved reserves have grown by 32% since December 31, 2015 and these additions equate to a four year reserve replacement ratio of 198%.
2019 Financial Update
"In 2019, Continental maintained capital discipline and generated strong corporate returns with an 11% return on capital employed (ROCE). The Company also delivered $190 million in share repurchases, approximately $200 million in net debt reduction and the initiation of the Company's quarterly dividend," said John Hart, Chief Financial Officer.
Three Months Ended | Year Ended | |||
2019 Financial Update | December 31, 2019 | December 31, 2019 | ||
Cash and Cash Equivalents | $39.4 million | |||
Total Debt | $5.33 billion | |||
Net Debt (non-GAAP)(1) | $5.29 billion | |||
Average Net Sales Price (non-GAAP)(1) | ||||
Per Barrel of Oil | $51.33 | $51.82 | ||
Per Mcf of Gas | $1.73 | $1.77 | ||
Per Boe | $33.49 | $34.56 | ||
Production Expense per Boe | $3.31 | $3.58 | ||
Total G&A Expenses per Boe | $1.59 | $1.57 | ||
Crude Oil Differential per Barrel | ($5.52) | ($5.15) | ||
Natural Gas Differential per Mcf | ($0.77) | ($0.86) | ||
Non-Acquisition Capital Expenditures | $541.3 million | $2.66 billion | ||
Exploration & Development Drilling & Completion | $467.8 million | $2.2 billion | ||
Leasehold | $18.1 million | $86.8 million | ||
Minerals, of which 80% was Recouped from FNV | $10.3 million | $130.0 million | ||
Workovers, Recompletions and Other | $45.1 million | $198.3 million |
(1) Net debt and net sales prices represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
2020 Capital Budget & Guidance
"In 2020, Continental will prioritize maximizing shareholder capital return in the form of share repurchases, debt reduction and dividends. With our strong portfolio and disciplined approach to value creation, we will continue to increase capital and corporate returns for our shareholders," said Bill Berry, Chief Executive Officer.
The 2020 capital budget is projected to generate $2.9 to $3.0 billion of cash flow from operations and $350 to $400 million of free cash flow for full-year 2020 at $55 per barrel WTI and $2.50 per Mcf Henry Hub. A $5 change per barrel WTI is estimated to impact annual cash flow by approximately $300 million.
Annual crude oil production is projected to range between 198,000 to 201,000 Bopd. Annual natural gas production is projected to range between 935,000 to 960,000 Mcfpd. The Company is targeting 4% to 6% annual production growth year-over-year, which is expected to average an approximately 10% CAGR for 2019 and 2020. The Company believes the projected growth range is appropriate given prevailing market conditions and outperformance in 2019. Cumulative volumes are projected to be on track with the Company's original Five Year Vision estimates for 2019 and 2020.
The Company's 2020 capital expenditures budget is flat year-over-year at $2.65 billion. Estimated Capex spend is approximately 20% lower than the Company's original Five Year Vision estimate for 2020. An estimated $700 million of capital to be spent in 2020 will not realize first production until 2021 as the Company prioritizes large scale multi-pad development projects in SCOOP and Bakken Long Creek.
Consequently, at year-end 2020, the Company expects to have a working backlog of approximately 242 gross operated wells in progress in various stages of completion, which is 12% higher than year-end 2019. This includes 188 gross operated wells in the Bakken, which is 42% higher than year-end 2019.
The Company is allocating approximately $2.2 billion to drilling and completion (D&C) activities, of which approximately 60% is allocated to the Bakken and approximately 40% to Oklahoma. The non-D&C capital is planned to be primarily focused on leasehold, mineral acquisitions, workovers and facilities.
The Company is allocating approximately $125 million to the previously announced mineral royalty agreement. With a carry structure in place, $100 million of capital costs will be funded by Franco-Nevada and the Company expects to earn 50% of total revenue generated from this strategic relationship in 2020.
In 2020, the Company plans to deliver approximately 8% ROCE at $55 WTI.
"Looking to 2020 and beyond, Continental expects to continue to be the low cost leader among our oil-weighted peers as we maximize performance and returns from our growing, high quality assets," said Jack Stark, President and Chief Operating Officer.
The Company's full 2020 guidance, capital expenditures budget and operating details can be found at the conclusion of this press release.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended December 31, | Year ended December 31, | ||||||
2019 | 2018 | 2019 | 2018 | ||||
Average daily production: | |||||||
Crude oil (Bbl per day) | 206,249 | 186,934 | 197,991 | 168,177 | |||
Natural gas (Mcf per day) | 954,556 | 822,402 | 854,424 | 780,083 | |||
Crude oil equivalents (Boe per day) | 365,341 | 324,001 | 340,395 | 298,190 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||||
Crude oil ($/Bbl) | $ 51.33 | $ 50.06 | $ 51.82 | $ 59.19 | |||
Natural gas ($/Mcf) | $ 1.73 | $ 3.26 | $ 1.77 | $ 3.01 | |||
Crude oil equivalents ($/Boe) | $ 33.49 | $ 37.13 | $ 34.56 | $ 41.25 | |||
Production expenses ($/Boe) | $ 3.31 | $ 3.50 | $ 3.58 | $ 3.59 | |||
Production taxes (% of net crude oil and gas sales) | 8.1% | 8.2% | 8.3% | 7.9% | |||
DD&A ($/Boe) | $ 16.45 | $ 16.41 | $ 16.25 | $ 17.09 | |||
Total general and administrative expenses ($/Boe) (2) | $ 1.59 | $ 1.65 | $ 1.57 | $ 1.69 | |||
Net income attributable to Continental Resources (in thousands) | $193,946 | $197,738 | $ 775,641 | $ 988,317 | |||
Diluted net income per share attributable to Continental Resources | $ 0.53 | $ 0.53 | $ 2.08 | $ 2.64 | |||
Adjusted net income (non-GAAP) (in thousands) (1) | $203,589 | $201,686 | $ 838,723 | $1,066,237 | |||
Adjusted diluted net income per share (non-GAAP) (1) | $ 0.55 | $ 0.54 | $ 2.25 | $ 2.84 | |||
Net cash provided by operating activities (in thousands) | $803,812 | $955,267 | $3,115,688 | $3,456,008 | |||
EBITDAX (non-GAAP) (in thousands) (1) | $905,525 | $850,640 | $3,447,033 | $3,623,373 |
(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.15, $1.18, $1.15, and $1.25 for 4Q 2019, 4Q 2018, FY 2019 and FY 2018, respectively. Non-cash equity compensation expense per Boe was $0.44, $0.47, $0.42, and $0.44 for 4Q 2019, 4Q 2018, FY 2019 and FY 2018, respectively. |
Fourth Quarter Earnings Conference Call
The Company plans to host a conference call to discuss full-year 2019 and 4Q19 results on Thursday, February 27, 2020 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Thursday, February 27, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8554062 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10138250 |
The Company plans to publish a full-year 2019 and 4Q19 summary presentation to its website at www.CLR.com prior to the start of its conference call on Thursday, February 27, 2020.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the effects of any national or international health crisis; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, and once filed, for the year ended December 31, 2019, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
Continental Resources, Inc. and Subsidiaries Consolidated Statements of Income | |||||||
Three months ended December 31, | Year ended December 31, | ||||||
2019 | 2018 | 2019 | 2018 | ||||
Revenues: | In thousands, except per share data | ||||||
Crude oil and natural gas sales | $1,185,980 | $1,154,104 | $4,514,389 | $4,678,722 | |||
Gain (loss) on natural gas derivatives, net | (4,436) | (19,394) | 49,083 | (23,930) | |||
Crude oil and natural gas service operations | 13,590 | 14,584 | 68,475 | 54,794 | |||
Total revenues | 1,195,134 | 1,149,294 | 4,631,947 | 4,709,586 | |||
Operating costs and expenses: | |||||||
Production expenses | 111,203 | 104,258 | 444,649 | 390,423 | |||
Production taxes | 90,751 | 90,393 | 357,988 | 353,140 | |||
Transportation expenses | 61,080 | 49,028 | 225,649 | 191,587 | |||
Exploration expenses | 7,268 | 3,295 | 14,667 | 7,642 | |||
Crude oil and natural gas service operations | 6,614 | 4,205 | 33,230 | 21,639 | |||
Depreciation, depletion, amortization and accretion | 552,711 | 488,416 | 2,017,383 | 1,859,327 | |||
Property impairments | 19,348 | 38,494 | 86,202 | 125,210 | |||
General and administrative expenses | 53,465 | 49,201 | 195,302 | 183,569 | |||
Net gain on sale of assets and other | (1,182) | (8,410) | (535) | (16,671) | |||
Total operating costs and expenses | 901,258 | 818,880 | 3,374,535 | 3,115,866 | |||
Income from operations | 293,876 | 330,414 | 1,257,412 | 1,593,720 | |||
Other income (expense): | |||||||
Interest expense | (64,981) | (69,441) | (269,379) | (293,032) | |||
Loss on extinguishment of debt | - | - | (4,584) | (7,133) | |||
Other | 516 | 1,016 | 3,713 | 3,247 | |||
(64,465) | (68,425) | (270,250) | (296,918) | ||||
Income before income taxes | 229,411 | 261,989 | 987,162 | 1,296,802 | |||
Provision for income taxes | (35,303) | (62,868) | (212,689) | (307,102) | |||
Net income | 194,108 | 199,121 | 774,473 | 989,700 | |||
Net income (loss) attributable to noncontrolling interests | 162 | 1,383 | (1,168) | 1,383 | |||
Net income attributable to Continental Resources | $ 193,946 | $ 197,738 | $ 775,641 | $ 988,317 | |||
Net income per share attributable to Continental Resources: | |||||||
Basic | $ 0.53 | $ 0.53 | $ 2.09 | $ 2.66 | |||
Diluted | $ 0.53 | $ 0.53 | $ 2.08 | $ 2.64 |
Continental Resources, Inc. and Subsidiaries Consolidated Balance Sheets | ||||
In thousands | December 31, 2019 | December 31, 2018 | ||
Assets | ||||
Cash and cash equivalents | $ 39,400 | $ 282,749 | ||
Other current assets | 1,167,615 | 1,129,612 | ||
Net property and equipment (1) | 14,497,726 | 13,869,800 | ||
Other noncurrent assets | 23,166 | 15,786 | ||
Total assets | $ 15,727,907 | $ 15,297,947 | ||
Liabilities and equity | ||||
Current liabilities | $ 1,336,026 | $ 1,387,509 | ||
Long-term debt, net of current portion | 5,324,079 | 5,765,989 | ||
Other noncurrent liabilities | 1,959,451 | 1,722,588 | ||
Equity attributable to Continental Resources | 6,741,667 | 6,145,133 | ||
Equity attributable to noncontrolling interests | 366,684 | 276,728 | ||
Total liabilities and equity | $ 15,727,907 | $ 15,297,947 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $12.77 billion and $10.81 billion as of December 31, 2019 and December 31, 2018, respectively. |
Continental Resources, Inc. and Subsidiaries Consolidated Statements of Cash Flows | ||||||||
Three months ended December 31, | Year ended December 31, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net income | $ 194,108 | $ 199,121 | $ 774,473 | $ 989,700 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Non-cash expenses | 641,495 | 576,033 | 2,400,708 | 2,340,600 | ||||
Changes in assets and liabilities | (31,791) | 180,113 | (59,493) | 125,708 | ||||
Net cash provided by operating activities | 803,812 | 955,267 | 3,115,688 | 3,456,008 | ||||
Net cash used in investing activities | (518,029) | (756,689) | (2,771,956) | (2,860,172) | ||||
Net cash (used in) provided by financing activities | (281,650) | 71,319 | (587,108) | (356,934) | ||||
Effect of exchange rate changes on cash | 7 | (44) | 27 | (55) | ||||
Net change in cash and cash equivalents | 4,140 | 269,853 | (243,349) | 238,847 | ||||
Cash and cash equivalents at beginning of period | 35,260 | 12,896 | 282,749 | 43,902 | ||||
Cash and cash equivalents at end of period | $ 39,400 | $ 282,749 | $ 39,400 | $ 282,749 |
Non-GAAP Financial Measures
Non-GAAP adjusted net income and adjusted net income per share attributable to Continental
Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.
Three months ended December 31, | |||||||||
2019 | 2018 | ||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | |||||
Net income attributable to Continental Resources (GAAP) | $193,946 | $ 0.53 | $ 197,738 | $ 0.53 | |||||
Adjustments: | |||||||||
Non-cash (gain) loss on derivatives | 16,915 | (25,022) | |||||||
Property impairments | 19,348 | 38,494 | |||||||
Gain on sale of assets, net | (1,182) | (8,410) | |||||||
Total tax effect of adjustments (1) | (8,578) | (1,114) | |||||||
Tax benefit from sale of Canadian subsidiary | (16,860) | - | |||||||
Total adjustments, net of tax | 9,643 | 0.02 | 3,948 | 0.01 | |||||
Adjusted net income (non-GAAP) | $203,589 | $0.55 | $ 201,686 | $0.54 | |||||
Weighted average diluted shares outstanding | 368,825 | 374,525 | |||||||
Adjusted diluted net income per share (non-GAAP) | $ 0.55 | $ 0.54 | |||||||
Year ended December 31, | |||||||||
2019 | 2018 | ||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | |||||
Net income attributable to Continental Resources (GAAP) | $775,641 | $ 2.08 | $ 988,317 | $ 2.64 | |||||
Adjustments: | |||||||||
Non-cash (gain) loss on derivatives | 15,612 | (13,009) | |||||||
Property impairments | 86,202 | 125,210 | |||||||
Gain on sale of assets, net | (535) | (16,671) | |||||||
Loss on extinguishment of debt | 4,584 | 7,133 | |||||||
Total tax effect of adjustments (1) | (25,921) | (24,743) | |||||||
Tax benefit from sale of Canadian subsidiary | (16,860) | - | |||||||
Total adjustments, net of tax | 63,082 | 0.17 | 77,920 | 0.20 | |||||
Adjusted net income (non-GAAP) | $838,723 | $2.25 | $1,066,237 | $2.84 | |||||
Weighted average diluted shares outstanding | 372,538 | 374,838 | |||||||
Adjusted diluted net income per share (non-GAAP) | $ 2.25 | $ 2.84 |
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2019 and 2018 to the pre-tax amount of adjustments associated with our operations in the United States. |
Non-GAAP Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At December 31, 2019, the Company's total debt was $5.33 billion and its net debt amounted to $5.29 billion, representing total debt of $5.33 billion less cash and cash equivalents of $39.4 million. At December 31, 2018, the Company's total debt was $5.77 billion and its net debt amounted to $5.49 billion, representing total debt of $5.77 billion less cash and cash equivalents of $282.7 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Non-GAAP EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
Three months ended December 31, | Year ended December 31, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net income | $ 194,108 | $ 199,121 | $ 774,473 | $ 989,700 | ||||
Interest expense | 64,981 | 69,441 | 269,379 | 293,032 | ||||
Provision for income taxes | 35,303 | 62,868 | 212,689 | 307,102 | ||||
Depreciation, depletion, amortization and accretion | 552,711 | 488,416 | 2,017,383 | 1,859,327 | ||||
Property impairments | 19,348 | 38,494 | 86,202 | 125,210 | ||||
Exploration expenses | 7,268 | 3,295 | 14,667 | 7,642 | ||||
Impact from derivative instruments: | ||||||||
Total (gain) loss on derivatives, net | 4,436 | 19,394 | (49,083) | 23,930 | ||||
Total cash (paid) received on derivatives, net | 12,479 | (44,416) | 64,695 | (36,939) | ||||
Non-cash (gain) loss on derivatives, net | 16,915 | (25,022) | 15,612 | (13,009) | ||||
Non-cash equity compensation | 14,891 | 14,027 | 52,044 | 47,236 | ||||
Loss on extinguishment of debt | - | - | 4,584 | 7,133 | ||||
EBITDAX (non-GAAP) | $ 905,525 | $ 850,640 | $ 3,447,033 | $ 3,623,373 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended December 31, | Year ended December 31, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net cash provided by operating activities | $ 803,812 | $ 955,267 | $ 3,115,688 | $ 3,456,008 | ||||
Current income tax provision | - | 2 | - | (7,776) | ||||
Interest expense | 64,981 | 69,441 | 269,379 | 293,032 | ||||
Exploration expenses, excluding dry hole costs | 7,268 | 3,149 | 14,667 | 7,495 | ||||
Gain on sale of assets, net | 1,182 | 8,410 | 535 | 16,671 | ||||
Other, net | (3,509) | (5,516) | (12,729) | (16,349) | ||||
Changes in assets and liabilities | 31,791 | (180,113) | 59,493 | (125,708) | ||||
EBITDAX (non-GAAP) | $ 905,525 | $ 850,640 | $ 3,447,033 | $ 3,623,373 |
Non-GAAP Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following tables present a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.
Three months ended December 31, 2019 | Three months ended December 31, 2018 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $1,024,432 | $161,548 | $1,185,980 | $900,872 | $253,232 | $1,154,104 | ||||||
Less: Transportation expenses | (51,332) | (9,748) | (61,080) | (42,373) | (6,655) | (49,028) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $973,100 | $151,800 | $1,124,900 | $858,499 | $246,577 | $1,105,076 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 18,956 | 87,819 | 33,593 | 17,149 | 75,661 | 29,759 | ||||||
Net sales price (non-GAAP) | $51.33 | $1.73 | $33.49 | $50.06 | $3.26 | $37.13 | ||||||
Year ended December 31, 2019 | Year ended December 31, 2018 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $3,929,994 | $584,395 | $4,514,389 | $3,792,594 | $886,128 | $4,678,722 | ||||||
Less: Transportation expenses | (191,998) | (33,651) | (225,649) | (162,312) | (29,275) | (191,587) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $3,737,996 | $550,744 | $4,288,740 | $3,630,282 | $856,853 | $4,487,135 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 72,136 | 311,865 | 124,113 | 61,332 | 284,730 | 108,787 | ||||||
Net sales price (non-GAAP) | $51.82 | $1.77 | $34.56 | $59.19 | $3.01 | $41.25 |
Non-GAAP Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended December 31, | Year ended December 31, | |||||||
2019 | 2018 | 2019 | 2018 | |||||
Total G&A per Boe (GAAP) | $ 1.59 | $ 1.65 | $ 1.57 | $ 1.69 | ||||
Less: Non-cash equity compensation per Boe | (0.44) | (0.47) | (0.42) | (0.44) | ||||
Cash G&A per Boe (non-GAAP) | $ 1.15 | $ 1.18 | $ 1.15 | $ 1.25 |
Non-GAAP Free Cash Flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, excluding acquisitions, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our relationship formed with Franco-Nevada in 2018 to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Management believes that this measure is useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. From time to time the Company provides forward-looking free cash flow estimates or targets; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
The following table reconciles net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the year ended December 31, 2019.
In thousands | 2019 | |
Net cash provided by operating activities (GAAP) | $ 3,115,688 | |
Exclude: Changes in working capital items | 59,493 | |
Less: Capital expenditures (1) | (2,661,794) | |
Plus: Contributions from noncontrolling interest | 109,137 | |
Less: Distributions to noncontrolling interest | (14,164) | |
Free cash flow (non-GAAP) | $ 608,360 | |
(1) Capital expenditures are calculated as follows: | ||
In thousands | 2019 | |
Cash paid for capital expenditures | $ 2,860,690 | |
Less: Total acquisitions | (147,398) | |
Plus: Change in accrued capital expenditures & other | (54,761) | |
Plus: Exploratory seismic costs | 3,263 | |
Capital expenditures | $ 2,661,794 |
Calculation of Return on Capital Employed (ROCE)
The following table shows the calculation of ROCE for 2019.
In thousands | 2019 | |
Net income attributable to Continental Resources | $ 775,641 | |
Impact from derivative instruments: | ||
Total gain on derivatives, net | (49,083) | |
Total cash received, net | 64,695 | |
Non-cash loss on derivatives, net | 15,612 | |
Provision for income taxes | 212,689 | |
Non-cash equity compensation | 52,044 | |
Interest expense | 269,379 | |
Loss on extinguishment of debt | 4,584 | |
Adjusted EBIT | $ 1,329,949 | |
Equity attributable to Continental Resources - beginning of period | $ 6,145,133 | |
Total debt - beginning of period | 5,768,349 | |
Capital employed - beginning of period | 11,913,482 | |
Equity attributable to Continental Resources - end of period | 6,741,667 | |
Total debt - end of period | 5,326,514 | |
Capital employed - end of period | 12,068,181 | |
Average capital employed | $ 11,990,832 | |
ROCE | 11.1% |
Continental Resources, Inc. | ||
2020 Guidance | ||
As of February 26, 2020 | ||
2020 | ||
Full-year average oil production (Bopd) | 198,000 to 201,000 | |
Full-year average natural gas production (Mcfpd) | 935,000 to 960,000 | |
Capital expenditures budget | $2.65 Billion | |
Operating Expenses: | ||
Production expense per Boe | $3.50 to $4.00 | |
Production tax (% of net oil & gas revenue) | 8.3% to $8.5% | |
Cash G&A expense per Boe(1) | $1.10 to $1.40 | |
Non-cash equity compensation per Boe | $0.50 to $0.60 | |
DD&A per Boe | $15.00 to $17.00 | |
Average Price Differentials: | ||
NYMEX WTI crude oil (per barrel of oil) | ($4.50) to ($5.50) | |
Henry Hub natural gas (per Mcf) | ($0.50) to ($1.00) |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is a projected range of $1.60 to $2.00 per Boe. |
Continental Resources, Inc. | |||
2020 Capital Expenditures | |||
The following table provides the breakout of budgeted capital expenditures: | |||
($ in Millions) | North D&C | South D&C | Leasehold, Facilities, Other(1) |
Capex | $1,368 | $843 | $439 |
1. Includes $125 million allocated to minerals royalty acquisitions, of which $100 million will be recouped from Franco-Nevada. |
Continental Resources, Inc. | ||||
2020 Operational Detail | ||||
The following table provides additional operational detail for wells expected to have first production in 2020: | ||||
Asset | Average Rigs | Gross Operated Wells | Net Operated Wells | Total Net Wells(1) |
North | 9 | 177 | 122 | 154 |
South | 10.5 | 126 | 84 | 91 |
Total | 19.5 | 303 | 206 | 245 |
1. Represents projected net operated and non-operated wells. |
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SOURCE Continental Resources
OKLAHOMA CITY, Jan. 27, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced that its Board of Directors has declared a quarterly dividend of $0.05 per share on the Company's outstanding common stock, payable on February 21, 2020 to stockholders of record on February 7, 2020.
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Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact are forward-looking statements, including, but not limited to, statements, information, forecasts or expectations regarding the Company's business and future plans, including those relating to its share repurchase program, payment of dividends, debt reduction goals, free cash flow generation and liquidity expectations, and its expectations regarding the achievement of ROCE goals. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Lucy Guttenberger Investor Relations Analyst 405-774-5878 |
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SOURCE Continental Resources
OKLAHOMA CITY, Jan. 22, 2020 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) plans to announce full-year 2019 and 4Q19 results on Wednesday, February 26, 2020 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss full-year 2019 and 4Q19 results on Thursday, February 27, 2020 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Thursday, February 27, 2020 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8554062 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10138250 |
The Company plans to publish a full-year 2019 and 4Q19 summary presentation to its website at www.CLR.com prior to the start of its conference call on Thursday, February 27, 2020.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2020, the Company will celebrate 53 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-full-year-2019-and-4q19-results-on-wednesday-february-26-2020-300991699.html
SOURCE Continental Resources
OKLAHOMA CITY, Dec. 11, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE-CLR) announced today that effective January 1, 2020, Founder and Chief Executive Officer, Harold Hamm will step up to the role of Executive Chairman. William Berry has been appointed Chief Executive Officer and President Jack Stark will assume the additional role of Chief Operating Officer.
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"Bill gives us an extraordinary opportunity to expand our leadership. He brings a notable resume and track record of success second to none," said Mr. Hamm, Founder, CEO and majority shareholder. "Like me, his DNA is oil and gas exploration and production. What makes Bill special is his ability to identify and nurture talent. Plus, his extensive global energy market experience will serve the Company well. He's deeply rooted in our culture and leadership at Continental, having served on our board for the past five years. He has been my personal confidant and is a trusted advisor that has helped guide our executive team."
"It's a great honor to step into a leadership role at Continental. Harold and his team have built one of the greatest energy companies in America," stated Mr. Berry. "I know firsthand the people at Continental are among the most talented, motivated, and innovative in the industry. We are perfectly positioned for the future because of Continental's ability to produce highly sustainable, low-cost, light sweet oil and natural gas," he continued. "This is a high performance, high ambition company. I look forward to partnering with Harold, and working with Jack and the entire Continental team on the next chapter of this remarkable Company's future."
Mr. Stark, President, had this to say, "Bill is the perfect fit for Continental. He enthusiastically embraces our culture and the way we conduct our business. I am right where I want to be and Bill has the full support of myself and the entire leadership team as we continue to grow our great Company."
Hamm added, "As for me, I'm not going anywhere. I'm an oil finder and geologist at heart. Working together, Bill and I will help the Company cultivate new strategic opportunities. This is the right time to bring him on board: Continental has never been stronger, and we are enjoying record production coupled with strong free cash flow. As most everyone knows, I have a long history of buying, not selling our stock and that will not change. We are living in the new oil era, driven by the American Energy Renaissance. The result is a stronger economy, a stronger energy independent America, and a safer world. With Bill, Jack and our extraordinary team, we will define that new era going forward. Continental is a company with a very bright future. Our Company is built to last."
Bill Berry has spent over four decades in the oil and gas business, serving in a variety of roles, including as an executive with ConocoPhillips where he was responsible for global operations managing over 10,000 employees and over $12 billion in capital expenditures. He has served on the Continental Board of Directors in a variety of roles since 2014. Bill holds a bachelor's and master's degree in petroleum engineering from Mississippi State University.
Harold Hamm started Continental 52 years ago. In the decades that followed, no one has been a stronger advocate for the American independent oil and gas producers, nor a greater champion of what affordable, sustainable energy means to every citizen and business in the U.S. He is credited with leading the effort to end the export ban in 2015, which has resulted in huge economic and environmental benefits to the United States and our allies that will last for decades to come. His leadership and vision have inspired generations of people who are as passionate about the business as he is.
Today, Continental is the dominant oil producer in the Bakken of North Dakota and the dominant oil producer in Oklahoma from its SCOOP and STACK assets. Production has reached record levels and the Company is routinely the lowest cost operator among its oil-weighted peers. Continental continues to deliver on its financial metrics, reducing debt by $1.6 billion in less than three years, delivering its first dividend in November 2019 and repurchasing $187 million in stock to date as of third quarter 2019. Ours is a formula designed to deliver long-term sustainable results for the Company and its investors.
An accompanying video news release is available at https://vimeo.com/378443939.
The Company plans to host a conference call to discuss this announcement on Thursday, December 12, 2019 at 10:30 AM ET (9:30 AM CT). Those wishing to listen to the conference call may do so via the Company's website at www.clr.com or by phone:
Dial-in Information
Continental Resources Inc.
December 12, 2019 at 10:30 AM Eastern Time (9:30 AM Central Time)
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 5065634 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10137463 |
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
Lucy.Guttenberger@CLR.com |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
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SOURCE Continental Resources
OKLAHOMA CITY, Nov. 20, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) today announced the Continental Board of Directors elected Tim Taylor to the Board as a Class II Director, effective November 20, 2019.
Mr. Taylor served as President of Phillips 66, an integrated downstream company with refining, midstream, and chemical operations, from 2014 until his retirement in 2017. He was Executive Vice President of commercial, marketing, transportation and business development from 2012-2014. Mr. Taylor has over 35 year of experience in the oil and gas industry serving in various executive management positions in midstream and downstream businesses. He holds a Bachelor of Science in Chemical Engineering from Kansas State University.
"Continental is delighted to welcome Tim to Continental's Board of Directors," said Harold Hamm, Chairman and Chief Executive Officer. "His extensive experience in domestic and international midstream, refining, transportation, and marketing as well as his project, business development and financial expertise will prove to be a tremendous asset to Continental as we continue to produce low-cost oil and natural gas and market it around the world."
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
P/F: 405.234.9620 | 405-234-9480 |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019 the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
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SOURCE Continental Resources
OKLAHOMA CITY, Oct. 30, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced third quarter 2019 operating and financial results.
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The Company reported net income of $158.2 million, or $0.43 per diluted share, for the quarter ended September 30, 2019. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In third quarter 2019, these typically excluded items in aggregate represented $41.2 million, or $0.11 per diluted share, of Continental's reported net income. Adjusted net income for third quarter 2019 was $199.4 million, or $0.54 per diluted share (non-GAAP). Net cash provided by operating activities for third quarter 2019 was $807.0 million and EBITDAX was $828.7 million (non-GAAP).
Adjusted net income, adjusted net income per share, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
"Continental teams continue to operate at a high performance level across the Bakken and Oklahoma. With an oil-weighted portfolio, investment grade level debt and a total shareholder return strategy, no other E&P company is more aligned with shareholders," said Harold Hamm, Chairman and Chief Executive Officer.
Production Update: 3Q19 Average Daily Oil Production up 20% over 3Q18
Third quarter 2019 oil production increased 20% over third quarter 2018, averaging 198,074 barrels of oil per day (Bopd). Third quarter 2019 total production increased 12% over third quarter 2018, averaging 332,315 Boe per day (Boepd). Third quarter 2019 natural gas production increased 1% over third quarter 2018, averaging 805.4 million cubic feet per day (MMcfpd). The following table provides the Company's average daily production by region for the periods presented.
3Q | 3Q | YTD | YTD | |||||
Boe per day | 2019 | 2018 | 2019 | 2018 | ||||
Bakken | 191,268 | 167,643 | 194,872 | 162,396 | ||||
SCOOP | 80,115 | 63,270 | 73,127 | 63,360 | ||||
STACK | 53,070 | 56,129 | 55,585 | 53,733 | ||||
All other | 7,862 | 9,862 | 8,405 | 10,003 | ||||
Total | 332,315 | 296,904 | 331,989 | 289,492 |
"Approximately 50% of Continental's third quarter oil production growth, year-over-year, came from our Oklahoma assets," said Jack Stark, President. "This growth was driven by the outstanding results being realized from our ongoing development of SCOOP SpringBoard and STACK."
Bakken: 145,436 Average Daily 3Q19 Oil Production up 13% over 3Q18
In third quarter 2019, average daily Bakken oil production increased 13% over third quarter 2018, averaging 145,436 Bopd. The Company's third quarter 2019 total Bakken production increased 14% over third quarter 2018, averaging 191,268 Boepd. During the quarter, the Company completed 57 gross (37 net) operated wells with first production flowing at an average initial 24-hour rate per well of 2,313 Boepd.
The Company moved into manufacturing mode in the Bakken in 2017. Since then, the Company has focused almost exclusively on the multi-zone unit development of the Middle Bakken, Three Forks 1 and Three Forks 2 reservoirs. During this time, the Company has completed 440 gross operated unit wells with an average initial 24-hour rate per well of approximately 2,300 Boepd, with an average 80% oil. Both the 2017 and 2018 Bakken programs have paid out in approximately one year.
"We are more than two years into manufacturing mode and our Bakken assets are delivering remarkably consistent results with some of the best returns in the industry," said Jack Stark, President. "These results provide a great snapshot of the quality of our Bakken assets and reinforce the confidence we have in the Bakken as a key driver of Continental's growth for years to come."
South: 44,854 Average Daily 3Q19 Oil Production up 62% over 3Q18
In third quarter 2019, average daily South oil production increased 62% over third quarter 2018, averaging 44,854 Bopd. The Company's third quarter 2019 total South production increased 11% over third quarter 2018, averaging 133,266 Boepd. In third quarter 2019, the Company completed 80 gross (56 net) operated wells with first production in the South.
The Company exceeded its SCOOP Project SpringBoard oil production target for third quarter 2019 by 31%, averaging 23,641 Bopd. This outperformance was driven by operational efficiencies that brought wells on line ahead of schedule, as well as the outstanding Springer well performance in Rows 2 and 3. These wells flowed at an average initial 24-hour rate of 1,650 Boepd per well, with approximately 80% being oil. As expected, the 52 Springer wells combined in Rows 1, 2 and 3 are performing on average, in line with the blended 1.3 MMBoe unit type curve provided during the January SpringBoard conference call. The Company has raised its SpringBoard oil production target for fourth quarter 2019 from 22,000 Bopd to approximately 24,000 Bopd. To date, approximately 8.7 million gross barrels of oil have been produced from Project SpringBoard alone.
In the Continental STACK, the Reba Jo and Schulte oil units flowed at a combined initial 24-hour rate of 57,292 Boepd, of which 67% was oil, or 38,320 Bopd. Combined, the two units contained 14 unit wells that flowed at an average initial 24-hour rate of 4,092 Boepd per well. Since second quarter 2018, the Company has completed 8 units in the over-pressured window that have outperformed expectations and unit type curves for the STACK.
"Continental's South assets in the SCOOP and over-pressured STACK window continue to deliver outstanding results driven by our geologically superior acreage position, proper unit density design and excellent execution from our operational teams," said Pat Bent, Senior Vice President, Operations.
Total Shareholder Return Strategy Update: Share Repurchases and Quarterly Dividend
The Company has executed $187 million of share repurchases for 5.5 million shares, as of October 29, 2019. As previously announced, an initial share repurchase of up to $1 billion has been authorized by the Board of Directors, which is expected to continue through 2020. Share repurchases will be made at times and levels deemed appropriate by Company management and the Company intends to purchase shares opportunistically using available funds while maintaining sufficient liquidity to fund operating needs, capital program, and dividend payments.
The Company will be distributing its first quarterly dividend of $0.05 per share on the Company's outstanding common stock to stockholders of record on November 7, 2019. This will be payable on November 21, 2019.
Financial Update
"During 2019, Continental has strategically focused on building shareholder value by balancing significant cash flow generation with strong production growth. This has enabled the Company to repurchase $187 million in shares and complete strategic bolt-on acquisitions that add to our deep, oil-focused inventory," said John Hart, Chief Financial Officer.
As of September 30, 2019, the Company's balance sheet included approximately $35.3 million in cash and cash equivalents, $5.57 billion in total debt and $5.54 billion in net debt (non-GAAP).
In third quarter 2019, the Company's average net sales prices excluding the effects of derivative positions were $51.28 per barrel of oil and $1.12 per Mcf of gas, or $33.30 per Boe. Production expense per Boe was $3.73 for third quarter 2019. Total G&A expenses per Boe were $1.54 for third quarter 2019.
The Company's third quarter 2019 crude oil differential was $5.15 per barrel below the NYMEX daily average for the period. The wellhead natural gas price for third quarter 2019 was $1.11 per Mcf below the average NYMEX Henry Hub benchmark price.
Through September 30, 2019, the Company has realized approximately $52 million of cash gains from its natural gas hedges. As of September 30, 2019, the Company's unrealized non-cash mark-to-market gain on its natural gas hedges totaled approximately $17 million.
Non-acquisition capital expenditures for third quarter 2019 totaled approximately $681.5 million, including $578.1 million in exploration and development drilling and completion, $31.4 million in leasehold, $24.5 million in minerals, of which 80% was recouped from Franco-Nevada, and $47.5 million in workovers, recompletions and other.
The Company's full 2019 guidance can be found at the conclusion of this press release.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended September 30, | Nine months ended September 30, | ||||||
2019 | 2018 | 2019 | 2018 | ||||
Average daily production: | |||||||
Crude oil (Bbl per day) | 198,074 | 164,605 | 195,209 | 161,856 | |||
Natural gas (Mcf per day) | 805,446 | 793,793 | 820,679 | 765,821 | |||
Crude oil equivalents (Boe per day) | 332,315 | 296,904 | 331,989 | 289,492 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||||
Crude oil ($/Bbl) | $ 51.28 | $ 65.78 | $ 51.99 | $ 62.73 | |||
Natural gas ($/Mcf) | $ 1.12 | $ 3.12 | $ 1.78 | $ 2.92 | |||
Crude oil equivalents ($/Boe) | $ 33.30 | $ 44.85 | $ 34.95 | $ 42.80 | |||
Production expenses ($/Boe) | $ 3.73 | $ 3.77 | $ 3.68 | $ 3.62 | |||
Production taxes (% of net crude oil and gas sales) | 8.5% | 8.0% | 8.4% | 7.8% | |||
DD&A ($/Boe) | $ 15.81 | $ 17.15 | $ 16.18 | $ 17.35 | |||
Total general and administrative expenses ($/Boe) (2) | $ 1.54 | $ 1.61 | $ 1.57 | $ 1.70 | |||
Net income attributable to Continental Resources (in thousands) | $ 158,162 | $ 314,169 | $ 581,695 | $ 790,580 | |||
Diluted net income per share attributable to Continental Resources | $ 0.43 | $ 0.84 | $ 1.56 | $ 2.11 | |||
Adjusted net income (non-GAAP) (in thousands) (1) | $ 199,389 | $ 337,017 | $ 635,135 | $ 865,033 | |||
Adjusted diluted net income per share (non-GAAP) (1) | $ 0.54 | $ 0.90 | $ 1.70 | $ 2.31 | |||
Net cash provided by operating activities (in thousands) | $ 806,972 | $ 860,748 | $ 2,311,876 | $ 2,500,741 | |||
EBITDAX (non-GAAP) (in thousands) (1) | $ 828,704 | $ 999,882 | $ 2,541,508 | $ 2,772,733 |
(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.12, $1.18, $1.16, and $1.28 for 3Q 2019, 3Q 2018, YTD 2019, and YTD 2018, respectively. Non-cash equity compensation expense per Boe was $0.42, $0.43, $0.41, and $0.42 for 3Q 2019, 3Q 2018, YTD 2019, and YTD 2018, respectively. |
Third Quarter Earnings Conference Call
The Company plans to host a conference call to discuss third quarter 2019 results on Thursday, October 31, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Thursday, October 31, 2019 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 0869596 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10135294 |
The Company plans to publish a third quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on October 31, 2019.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: | |
Rory Sabino | Kristin Thomas | |
Vice President, Investor Relations | Senior Vice President, Public Relations | |
405-234-9620 | 405-234-9480 | |
Lucy Guttenberger | ||
Investor Relations Analyst | ||
405-774-5878 | ||
Continental Resources, Inc. and Subsidiaries | |||||||
Three months ended September 30, | Nine months ended September 30, | ||||||
2019 | 2018 | 2019 | 2018 | ||||
Revenues: | In thousands, except per share data | ||||||
Crude oil and natural gas sales | $ 1,081,400 | $ 1,273,238 | $ 3,328,409 | $ 3,524,618 | |||
Gain (loss) on natural gas derivatives, net | 1,195 | (2,025) | 53,519 | (4,536) | |||
Crude oil and natural gas service operations | 21,602 | 10,938 | 54,886 | 40,210 | |||
Total revenues | 1,104,197 | 1,282,151 | 3,436,814 | 3,560,292 | |||
Operating costs and expenses: | |||||||
Production expenses | 114,050 | 103,032 | 333,446 | 286,165 | |||
Production taxes | 86,931 | 98,572 | 267,237 | 262,747 | |||
Transportation expenses | 62,038 | 46,008 | 164,569 | 142,559 | |||
Exploration expenses | 2,472 | 2,324 | 7,399 | 4,347 | |||
Crude oil and natural gas service operations | 8,224 | 5,163 | 26,616 | 17,434 | |||
Depreciation, depletion, amortization and accretion | 484,031 | 469,333 | 1,464,672 | 1,370,912 | |||
Property impairments | 20,199 | 23,770 | 66,854 | 86,715 | |||
General and administrative expenses | 46,993 | 44,151 | 141,837 | 134,368 | |||
Net (gain) loss on sale of assets and other | 535 | (1,510) | 647 | (8,261) | |||
Total operating costs and expenses | 825,473 | 790,843 | 2,473,277 | 2,296,986 | |||
Income from operations | 278,724 | 491,308 | 963,537 | 1,263,306 | |||
Other income (expense): | |||||||
Interest expense | (68,090) | (73,409) | (204,398) | (223,590) | |||
Loss on extinguishment of debt | (4,584) | (7,133) | (4,584) | (7,133) | |||
Other | 1,119 | 869 | 3,196 | 2,231 | |||
(71,555) | (79,673) | (205,786) | (228,492) | ||||
Income before income taxes | 207,169 | 411,635 | 757,751 | 1,034,814 | |||
Provision for income taxes | (49,747) | (97,466) | (177,386) | (244,234) | |||
Net income | 157,422 | 314,169 | 580,365 | 790,580 | |||
Net loss attributable to noncontrolling interests | (740) | - | (1,330) | - | |||
Net income attributable to Continental Resources | $ 158,162 | $ 314,169 | $ 581,695 | $ 790,580 | |||
Net income per share attributable to Continental Resources: | |||||||
Basic | $ 0.43 | $ 0.84 | $ 1.56 | $ 2.13 | |||
Diluted | $ 0.43 | $ 0.84 | $ 1.56 | $ 2.11 |
Continental Resources, Inc. and Subsidiaries | ||||
In thousands | September 30, 2019 | December 31, 2018 | ||
Assets | ||||
Cash and cash equivalents | $ 35,260 | $ 282,749 | ||
Other current assets | 1,190,424 | 1,129,612 | ||
Net property and equipment (1) | 14,520,573 | 13,869,800 | ||
Other noncurrent assets | 25,098 | 15,786 | ||
Total assets | $ 15,771,355 | $ 15,297,947 | ||
Liabilities and equity | ||||
Current liabilities | $ 1,371,769 | $ 1,387,509 | ||
Long-term debt, net of current portion | 5,568,413 | 5,765,989 | ||
Other noncurrent liabilities | 1,916,993 | 1,722,588 | ||
Equity attributable to Continental Resources | 6,551,985 | 6,145,133 | ||
Equity attributable to noncontrolling interests | 362,195 | 276,728 | ||
Total liabilities and equity | $ 15,771,355 | $ 15,297,947 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $12.29 billion and $10.81 billion as of September 30, 2019 and December 31, 2018, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net income | $ 157,422 | $ 314,169 | $ 580,365 | $ 790,580 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Non-cash expenses | 603,397 | 619,284 | 1,759,213 | 1,764,566 | ||||
Changes in assets and liabilities | 46,153 | (72,705) | (27,702) | (54,405) | ||||
Net cash provided by operating activities | 806,972 | 860,748 | 2,311,876 | 2,500,741 | ||||
Net cash used in investing activities | (696,182) | (759,880) | (2,253,927) | (2,103,483) | ||||
Net cash used in financing activities | (282,002) | (217,976) | (305,458) | (428,253) | ||||
Effect of exchange rate changes on cash | (10) | 15 | 20 | (11) | ||||
Net change in cash and cash equivalents | (171,222) | (117,093) | (247,489) | (31,006) | ||||
Cash and cash equivalents at beginning of period | 206,482 | 129,989 | 282,749 | 43,902 | ||||
Cash and cash equivalents at end of period | $ 35,260 | $ 12,896 | $ 35,260 | $ 12,896 |
Non-GAAP Financial Measures
Adjusted net income and adjusted net income per share attributable to Continental
Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.
Three months ended September 30, | ||||||||
2019 | 2018 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income attributable to Continental Resources (GAAP) | $158,162 | $ 0.43 | $314,169 | $ 0.84 | ||||
Adjustments: | ||||||||
Non-cash loss on derivatives | 29,289 | 548 | ||||||
Property impairments | 20,199 | 23,770 | ||||||
(Gain) loss on sale of assets, net | 535 | (1,510) | ||||||
Loss on extinguishment of debt | 4,584 | 7,133 | ||||||
Total tax effect of adjustments (1) | (13,380) | (7,093) | ||||||
Total adjustments, net of tax | 41,227 | 0.11 | 22,848 | 0.06 | ||||
Adjusted net income (non-GAAP) | $199,389 | $ 0.54 | $337,017 | $0.90 | ||||
Weighted average diluted shares outstanding | 370,676 | 374,623 | ||||||
Adjusted diluted net income per share (non-GAAP) | $ 0.54 | $ 0.90 | ||||||
Nine months ended September 30, | ||||||||
2019 | 2018 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income attributable to Continental Resources (GAAP) | $581,695 | $ 1.56 | $790,580 | $ 2.11 | ||||
Adjustments: | ||||||||
Non-cash (gain) loss on derivatives | (1,303) | 12,013 | ||||||
Property impairments | 66,854 | 86,715 | ||||||
(Gain) loss on sale of assets, net | 647 | (8,261) | ||||||
Loss on extinguishment of debt | 4,584 | 7,133 | ||||||
Total tax effect of adjustments (1) | (17,342) | (23,147) | ||||||
Total adjustments, net of tax | 53,440 | 0.14 | 74,453 | 0.20 | ||||
Adjusted net income (non-GAAP) | $635,135 | $ 1.70 | $865,033 | $2.31 | ||||
Weighted average diluted shares outstanding | 373,506 | 374,762 | ||||||
Adjusted diluted net income per share (non-GAAP) | $ 1.70 | $ 2.31 |
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2019 and 24.0% in effect for 2018 to the pre-tax amount of adjustments associated with our operations in the United States. |
Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At September 30, 2019, the Company's total debt was $5.57 billion and its net debt amounted to $5.54 billion, representing total debt of $5.57 billion less cash and cash equivalents of $35.3 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net income | $ 157,422 | $ 314,169 | $ 580,365 | $ 790,580 | ||||
Interest expense | 68,090 | 73,409 | 204,398 | 223,590 | ||||
Provision for income taxes | 49,747 | 97,466 | 177,386 | 244,234 | ||||
Depreciation, depletion, amortization and accretion | 484,031 | 469,333 | 1,464,672 | 1,370,912 | ||||
Property impairments | 20,199 | 23,770 | 66,854 | 86,715 | ||||
Exploration expenses | 2,472 | 2,324 | 7,399 | 4,347 | ||||
Impact from derivative instruments: | ||||||||
Total (gain) loss on derivatives, net | (1,195) | 2,025 | (53,519) | 4,536 | ||||
Total cash received (paid) on derivatives, net | 30,484 | (1,477) | 52,216 | 7,477 | ||||
Non-cash (gain) loss on derivatives, net | 29,289 | 548 | (1,303) | 12,013 | ||||
Non-cash equity compensation | 12,870 | 11,730 | 37,153 | 33,209 | ||||
Loss on extinguishment of debt | 4,584 | 7,133 | 4,584 | 7,133 | ||||
EBITDAX (non-GAAP) | $ 828,704 | $ 999,882 | $ 2,541,508 | $ 2,772,733 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net cash provided by operating activities | $ 806,972 | $ 860,748 | $ 2,311,876 | $ 2,500,741 | ||||
Current income tax provision | - | (7,778) | - | (7,778) | ||||
Interest expense | 68,090 | 73,409 | 204,398 | 223,590 | ||||
Exploration expenses, excluding dry hole costs | 2,472 | 2,324 | 7,399 | 4,346 | ||||
Gain (loss) on sale of assets, net | (535) | 1,510 | (647) | 8,261 | ||||
Other, net | (2,142) | (3,036) | (9,220) | (10,832) | ||||
Changes in assets and liabilities | (46,153) | 72,705 | 27,702 | 54,405 | ||||
EBITDAX (non-GAAP) | $ 828,704 | $ 999,882 | $ 2,541,508 | $ 2,772,733 |
Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following tables present a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.
Three months ended September 30, 2019 | Three months ended September 30, 2018 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $989,297 | $92,103 | $1,081,400 | $1,038,558 | $234,680 | $1,273,238 | ||||||
Less: Transportation expenses | (53,038) | (9,000) | (62,038) | (39,336) | (6,672) | (46,008) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $936,259 | $83,103 | $1,019,362 | $999,222 | $228,008 | $1,227,230 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 18,258 | 74,101 | 30,608 | 15,190 | 73,029 | 27,361 | ||||||
Net sales price (non-GAAP) | $51.28 | $1.12 | $33.30 | $65.78 | $3.12 | $44.85 | ||||||
Nine months ended September 30, 2019 | Nine months ended September 30, 2018 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $2,905,561 | $422,848 | $3,328,409 | $2,891,722 | $632,896 | $3,524,618 | ||||||
Less: Transportation expenses | (140,666) | (23,903) | (164,569) | (119,939) | (22,620) | (142,559) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $2,764,895 | $398,945 | $3,163,840 | $2,771,783 | $610,276 | $3,382,059 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 53,179 | 224,045 | 90,520 | 44,183 | 209,069 | 79,028 | ||||||
Net sales price (non-GAAP) | $51.99 | $1.78 | $34.95 | $62.73 | $2.92 | $42.80 |
Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||
2019 | 2018 | 2019 | 2018 | |||||
Total G&A per Boe (GAAP) | $1.54 | $1.61 | $1.57 | $1.70 | ||||
Less: Non-cash equity compensation per Boe | (0.42) | (0.43) | (0.41) | (0.42) | ||||
Cash G&A per Boe (non-GAAP) | $1.12 | $1.18 | $1.16 | $1.28 |
Continental Resources, Inc. | ||
2019 Guidance | ||
As of October 30, 2019 | ||
2019 | ||
Full-year average oil production | 195,000 to 200,000 Bopd | |
Full-year average natural gas production | 820,000 to 840,000 Mcfpd | |
Capital expenditures budget | $2.6 billion | |
Operating Expenses: | ||
Production expense per Boe | $3.50 to $4.00 | |
Production tax (% of net oil & gas revenue) | 8.5% | |
Cash G&A expense per Boe(1) | $1.15 to $1.35 | |
Non-cash equity compensation per Boe | $0.40 to $0.50 | |
DD&A per Boe | $15.00 to $17.00 | |
Average Price Differentials: | ||
NYMEX WTI crude oil (per barrel of oil) | ($4.50) to ($5.50) | |
Henry Hub natural gas (per Mcf) | ($0.50) to ($1.00) |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.55 to $1.85 per Boe. |
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SOURCE Continental Resources
OKLAHOMA CITY, Sept. 30, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) plans to announce third quarter 2019 results on Wednesday, October 30, 2019 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss third quarter 2019 results on Thursday, October 31, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Thursday, October 31, 2019 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 0869596 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10135294 |
The Company plans to publish a third quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on October 31, 2019.
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About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: | |
Rory Sabino | Kristin Thomas | |
Vice President, Investor Relations | Senior Vice President, Public Relations | |
405-234-9620 | 405-234-9480 | |
Lucy Guttenberger | ||
Investor Relations Analyst | ||
405-774-5878 | ||
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-third-quarter-2019-results-on-wednesday-october-30-2019-300928068.html
SOURCE Continental Resources
OKLAHOMA CITY, Aug. 7, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today that it will redeem $500 million in aggregate principal amount, representing approximately 31% of the $1.6 billion in aggregate principal amount currently outstanding, of its 5% Senior Notes due 2022 (the "Notes") on September 12, 2019, the redemption date for the Notes.
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The redemption price for the Notes called for redemption will be equal to 100.833% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the redemption date in accordance with the terms of the Notes and the indenture under which the Notes were issued. The Notes to be redeemed will be selected in accordance with the procedures of The Depository Trust Company. Interest on the portion of the Notes selected for redemption will cease to accrue on and after the redemption date.
Additional information concerning the terms and conditions of the redemption is contained in the notice distributed to holders of the Notes. Beneficial holders with any questions about the redemption should contact their respective brokerage firm or financial institution.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance and financial condition, are forward-looking statements. When used in this press release, the word "will" is intended to identify forward-looking statements, although not all forward-looking statements contain this identifying word.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, the ability to complete the redemption and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-partial-redemption-of-5-senior-notes-due-2022-300897515.html
SOURCE Continental Resources
OKLAHOMA CITY, Aug. 5, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced second quarter 2019 operating and financial results.
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The Company reported net income of $236.6 million, or $0.63 per diluted share, for the quarter ended June 30, 2019. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In second quarter 2019, these typically excluded items in aggregate represented $17.4 million, or $0.04 per diluted share, of Continental's reported net income. Adjusted net income for second quarter 2019 was $219.1 million, or $0.59 per diluted share (non-GAAP). Net cash provided by operating activities for second quarter 2019 was $783.4 million and EBITDAX was $858.0 million (non-GAAP).
Adjusted net income, adjusted net income per share, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
"Since announcing our total shareholder return strategy, $92 million in share repurchases have been executed by the Company. This reflects Continental's alignment with shareholders and commitment to delivering value and returns," said Harold Hamm, Chairman and Chief Executive Officer.
Production Update: 2Q19 Average Daily Oil Production up 23% over 2Q18
Second quarter 2019 oil production increased 23% over second quarter 2018, averaging 193,586 barrels of oil per day (Bopd). Second quarter 2019 total production increased 17% over second quarter 2018, averaging 331,414 Boe per day (Boepd). Second quarter 2019 natural gas production increased 9% over second quarter 2018, averaging 827.0 million cubic feet per day (MMcfpd). The following table provides the Company's average daily production by region for the periods presented.
2Q | 1Q | 2Q | YTD | YTD | ||||||
Boe per day | 2019 | 2019 | 2018 | 2019 | 2018 | |||||
Bakken | 194,014 | 199,423 | 158,119 | 196,704 | 159,729 | |||||
SCOOP | 71,471 | 67,659 | 64,786 | 69,576 | 63,406 | |||||
STACK | 57,209 | 56,513 | 51,722 | 56,863 | 52,515 | |||||
All other | 8,720 | 8,641 | 9,432 | 8,680 | 10,075 | |||||
Total | 331,414 | 332,236 | 284,059 | 331,823 | 285,725 |
2019 Production Guidance Increased; LOE and G&A Expense Guidance Decreased
The Company improved 2019 annual oil production guidance to 195,000 to 200,000 Bopd, versus previous guidance of 190,000 to 200,000 Bopd. The Company also increased natural gas production guidance to 820,000 to 840,000 MMcfpd, versus previous guidance of 790,000 to 810,000 Mcfpd. In addition, the Company is releasing 7 rigs in the South by year-end 2019 due to Springer & Woodford efficiency gains.
Total G&A expense, which is comprised of cash and non-cash G&A expense, has been lowered to $1.55 to $1.85 per Boe for 2019, a reduction from the previous guidance of $1.70 to $2.00. Of this total, cash G&A expense is expected to be $1.15 to $1.35 per Boe, a reduction from the previous guidance of $1.25 to $1.45. Non-cash compensation expense per Boe is expected to be $0.40 to $0.50, a reduction from the previous guidance of $0.45 to $0.55. The Company is also lowering its 2019 guidance for production expense per Boe to $3.50 to $4.00 per Boe for the year, a reduction from the previous guidance of $3.75 to $4.25.
The Company is guiding natural gas differentials wider based on lower NGL realizations and expects natural gas differentials to be in a range of ($0.50) to ($1.00) per Mcf in 2019, a change from the previous guidance of $0.00 to ($0.50). The Company is also guiding production tax to approximately 8.5% due to the higher level of production in North Dakota.
The Company's full 2019 revised guidance is stated at the conclusion of this press release.
$92 Million of Share Repurchases Executed through August 2, 2019
As previously announced, the Company's Board of Directors authorized an initial share-repurchase program of up to $1 billion. The share-repurchase program commenced in the second quarter 2019 and is expected to continue through 2020. Share repurchases will be made at times and levels deemed appropriate by Company management. The Company intends to purchase shares under the program opportunistically using available funds while maintaining sufficient liquidity to fund operating needs, capital program, and dividend payments. As of August 2, 2019, the Company has executed $92 million of share repurchases for 2.4 million shares.
As also previously announced as part of the Company's total shareholder return strategy, the Company's Board of Directors approved the initiation of a quarterly dividend of $0.05 per share on the Company's outstanding common stock, payable on November 21, 2019 to stockholders of record on November 7, 2019.
$85 Million Divestiture of Eastern STACK Water Handling Facility
As previously announced, the Company sold its eastern STACK water handling facilities in Blaine County, Oklahoma for $85 million to Lagoon Water Solutions. The Company owns and operates three additional water handling facilities in Oklahoma as well as ten additional systems in the Bakken.
Bakken: 149,078 Average Daily 2Q19 Oil Production; Up 22% over 2Q18
In second quarter 2019, average daily Bakken oil production increased 22% over second quarter 2018, averaging 149,078 Bopd. The Company's second quarter 2019 total Bakken production increased 23% over second quarter 2018, averaging 194,014 Boepd. The Company completed 35 gross (23 net) operated wells with first production during the quarter.
The Company is developing the Long Creek Bakken Unit, which covers 10-square miles and includes approximately 6,400 gross (5,600 net) contiguous acres. The Company anticipates up to 56 wells will be drilled in Long Creek, with 5 existing producers. The Company will operate these wells with an average working interest of approximately 87%. First production is expected in third quarter 2020, with oil production expected to peak in the second half of 2021 at up to 20,000 Bopd. Pipeline infrastructure is currently being constructed to handle all produced volumes.
"The Long Creek Bakken Unit is another high impact oil project for Continental, much like our Project SpringBoard in Oklahoma. Forming this large unit allows Continental to maximize the value of these assets by capitalizing on the efficiencies that come with row development," said Jack Stark, President.
South: 36,337 Average Daily 2Q19 Oil Production; Up 35% over 2Q18
In second quarter 2019, average daily South oil production increased 35% over second quarter 2018, averaging 36,337 Bopd. This increase was driven by the strategic shift to oil-weighted assets and commencing Project SpringBoard in 2018. The Company's second quarter 2019 total South production increased 10% over second quarter 2018, averaging 128,777 Boepd. In second quarter 2019, the Company completed 22 gross (16 net) operated wells with first production in the South.
The Company is on track to achieve its SpringBoard oil production growth target of 18,000 Bopd in third quarter 2019. The Company's SpringBoard oil production averaged approximately 19,000 Bopd in July 2019. The Company is targeting 22,000 Bopd from SpringBoard in fourth quarter 2019. The Company expects to bring approximately 30 additional SpringBoard wells on line in the second half of 2019.
Financial Update
"Continental is performing at a high level with significant net income driven by solid corporate returns and production. Additionally, we continue to realize strong free cash flow and have commenced our share-repurchase program, which we believe will further enhance shareholder value," said John Hart, Chief Financial Officer.
As of June 30, 2019, the Company's balance sheet included approximately $206.5 million in cash and cash equivalents, $5.77 billion in total debt and $5.56 billion in net debt (non-GAAP).
In second quarter 2019, the Company's average net sales prices excluding the effects of derivative positions were $54.66 per barrel of oil and $1.66 per Mcf of gas, or $36.03 per Boe. Production expense per Boe was $3.74 for second quarter 2019. Total G&A expenses per Boe were $1.57 for second quarter 2019.
The Company's second quarter 2019 crude oil differential was $5.11 per barrel below the NYMEX daily average for the period. The wellhead natural gas price for second quarter 2019 was $0.98 per Mcf below the average NYMEX Henry Hub benchmark price.
As of August 2, 2019, the Company has realized approximately $43 million of cash gains from its natural gas hedges. For the balance of 2019, natural gas is hedged 577,000 MMBtus per day at an average NYMEX Henry Hub price of $2.80. As of August 2, 2019, the Company's unrealized non-cash mark-to-market gain on its natural gas hedges totaled approximately $41 million.
Non-acquisition capital expenditures for second quarter 2019 totaled approximately $688.8 million, including $569.7 million in exploration and development drilling and completion, $22.6 million in leasehold, $43.8 million in minerals, of which 80% was recouped from Franco-Nevada, and $52.7 million in workovers, recompletions and other.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended June 30, | Six months ended June 30, | ||||||
2019 | 2018 | 2019 | 2018 | ||||
Average daily production: | |||||||
Crude oil (Bbl per day) | 193,586 | 157,116 | 193,753 | 160,458 | |||
Natural gas (Mcf per day) | 826,969 | 761,653 | 828,422 | 751,603 | |||
Crude oil equivalents (Boe per day) | 331,414 | 284,059 | 331,823 | 285,725 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||||
Crude oil ($/Bbl) | $ 54.66 | $ 63.35 | $ 52.36 | $ 61.14 | |||
Natural gas ($/Mcf) | $ 1.66 | $ 2.65 | $ 2.11 | $ 2.81 | |||
Crude oil equivalents ($/Boe) | $ 36.03 | $ 42.16 | $ 35.79 | $ 41.71 | |||
Production expenses ($/Boe) | $ 3.74 | $ 3.49 | $ 3.66 | $ 3.54 | |||
Production taxes (% of net crude oil and gas sales) | 8.7% | 7.7% | 8.4% | 7.6% | |||
DD&A ($/Boe) | $ 16.14 | $ 17.29 | $ 16.37 | $ 17.45 | |||
Total general and administrative expenses ($/Boe) (2) | $ 1.57 | $ 1.82 | $ 1.58 | $ 1.75 | |||
Net income attributable to Continental Resources (in thousands) | $236,557 | $242,464 | $ 423,533 | $ 476,410 | |||
Diluted net income per share attributable to Continental Resources | $ 0.63 | $ 0.65 | $ 1.13 | $ 1.27 | |||
Adjusted net income (non-GAAP) (in thousands) (1) | $219,136 | $272,877 | $ 435,746 | $ 528,016 | |||
Adjusted diluted net income per share (non-GAAP) (1) | $ 0.59 | $ 0.73 | $ 1.16 | $ 1.41 | |||
Net cash provided by operating activities (in thousands) | $783,396 | $753,802 | $1,504,904 | $1,639,993 | |||
EBITDAX (non-GAAP) (in thousands) (1) | $858,019 | $896,654 | $1,712,804 | $1,772,850 |
(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. | |||||||||||||||
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.17, $1.41, $1.18, and $1.33 for 2Q 2019, 2Q 2018, YTD 2019, and YTD 2018, respectively. Non-cash equity compensation expense per Boe was $0.40, $0.41, $0.40, and $0.42 for 2Q 2019, 2Q 2018, YTD 2019, and YTD 2018, respectively. |
Second Quarter Earnings Conference Call
The Company plans to host a conference call to discuss second quarter 2019 results on Tuesday, August 6, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, August 6, 2019 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8142074 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10132642 |
The Company plans to publish a second quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on August 6, 2019.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; our ability to pay future dividends or complete share repurchases; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: | |
Rory Sabino | Kristin Thomas | |
Vice President, Investor Relations | Senior Vice President, Public Relations | |
405-234-9620 | 405-234-9480 | |
Lucy Guttenberger | ||
Investor Relations Analyst | ||
405-774-5878 | ||
Continental Resources, Inc. and Subsidiaries | |||||||
Unaudited Condensed Consolidated Statements of Income | |||||||
Three months ended June 30, | Six months ended June 30, | ||||||
2019 | 2018 | 2019 | 2018 | ||||
Revenues: | In thousands, except per share data | ||||||
Crude oil and natural gas sales | $1,137,425 | $ 1,137,528 | $ 2,247,009 | $ 2,251,380 | |||
Gain (loss) on natural gas derivatives, net | 53,448 | (12,685) | 52,324 | (2,511) | |||
Crude oil and natural gas service operations | 17,509 | 12,270 | 33,284 | 29,272 | |||
Total revenues | 1,208,382 | 1,137,113 | 2,332,617 | 2,278,141 | |||
Operating costs and expenses: | |||||||
Production expenses | 112,430 | 90,171 | 219,396 | 183,133 | |||
Production taxes | 93,866 | 83,595 | 180,306 | 164,175 | |||
Transportation expenses | 53,393 | 47,254 | 102,531 | 96,551 | |||
Exploration expenses | 3,090 | 303 | 4,927 | 2,023 | |||
Crude oil and natural gas service operations | 11,206 | 7,688 | 18,392 | 12,271 | |||
Depreciation, depletion, amortization and accretion | 485,621 | 447,200 | 980,641 | 901,578 | |||
Property impairments | 21,339 | 29,162 | 46,655 | 62,946 | |||
General and administrative expenses | 47,226 | 47,174 | 94,844 | 90,217 | |||
Net (gain) loss on sale of assets and other | 364 | (6,710) | 112 | (6,751) | |||
Total operating costs and expenses | 828,535 | 745,837 | 1,647,804 | 1,506,143 | |||
Income from operations | 379,847 | 391,276 | 684,813 | 771,998 | |||
Other income (expense): | |||||||
Interest expense | (68,471) | (74,288) | (136,308) | (150,182) | |||
Other | 723 | 708 | 2,077 | 1,362 | |||
(67,748) | (73,580) | (134,231) | (148,820) | ||||
Income before income taxes | 312,099 | 317,696 | 550,582 | 623,178 | |||
Provision for income taxes | (75,649) | (75,232) | (127,639) | (146,768) | |||
Net income | 236,450 | 242,464 | 422,943 | 476,410 | |||
Net loss attributable to noncontrolling interests | (107) | - | (590) | - | |||
Net income attributable to Continental Resources | $ 236,557 | $ 242,464 | $ 423,533 | $ 476,410 | |||
Net income per share attributable to Continental Resources: | |||||||
Basic | $ 0.63 | $ 0.65 | $ 1.14 | $ 1.28 | |||
Diluted | $ 0.63 | $ 0.65 | $ 1.13 | $ 1.27 |
Continental Resources, Inc. and Subsidiaries | ||||
Unaudited Condensed Consolidated Balance Sheets | ||||
In thousands | June 30, 2019 | December 31, 2018 | ||
Assets | ||||
Cash and cash equivalents | $ 206,482 | $ 282,749 | ||
Other current assets | 1,207,193 | 1,129,612 | ||
Net property and equipment (1) | 14,387,960 | 13,869,800 | ||
Other noncurrent assets | 27,787 | 15,786 | ||
Total assets | $ 15,829,422 | $ 15,297,947 | ||
Liabilities and equity | ||||
Current liabilities | $ 1,368,346 | $ 1,387,509 | ||
Long-term debt, net of current portion | 5,767,316 | 5,765,989 | ||
Other noncurrent liabilities | 1,863,925 | 1,722,588 | ||
Equity attributable to Continental Resources | 6,483,503 | 6,145,133 | ||
Equity attributable to noncontrolling interests | 346,332 | 276,728 | ||
Total liabilities and equity | $ 15,829,422 | $ 15,297,947 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $11.78 billion and $10.81 billion as of June 30, 2019 and December 31, 2018, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||
Three months ended June 30, | Six months ended June 30, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net income | $236,450 | $242,464 | $ 422,943 | $ 476,410 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Non-cash expenses | 552,225 | 576,109 | 1,155,816 | 1,145,283 | ||||
Changes in assets and liabilities | (5,279) | (64,771) | (73,855) | 18,300 | ||||
Net cash provided by operating activities | 783,396 | 753,802 | 1,504,904 | 1,639,993 | ||||
Net cash used in investing activities | (804,674) | (715,392) | (1,557,745) | (1,343,603) | ||||
Net cash used in financing activities | (36,626) | (6,553) | (23,456) | (210,277) | ||||
Effect of exchange rate changes on cash | 15 | (13) | 30 | (26) | ||||
Net change in cash and cash equivalents | (57,889) | 31,844 | (76,267) | 86,087 | ||||
Cash and cash equivalents at beginning of period | 264,371 | 98,145 | 282,749 | 43,902 | ||||
Cash and cash equivalents at end of period | $206,482 | $129,989 | $ 206,482 | $ 129,989 |
Non-GAAP Financial Measures
Adjusted net income and adjusted net income per share attributable to Continental
Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, and gains and losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.
Three months ended June 30, | ||||||||
2019 | 2018 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income attributable to Continental Resources (GAAP) | $236,557 | $ 0.63 | $242,464 | $ 0.65 | ||||
Adjustments: | ||||||||
Non-cash (gain) loss on derivatives | (44,778) | 17,443 | ||||||
Property impairments | 21,339 | 29,162 | ||||||
(Gain) loss on sale of assets, net | 364 | (6,711) | ||||||
Total tax effect of adjustments (1) | 5,654 | (9,481) | ||||||
Total adjustments, net of tax | (17,421) | (0.04) | 30,413 | 0.08 | ||||
Adjusted net income (non-GAAP) | $219,136 | $ 0.59 | $272,877 | $0.73 | ||||
Weighted average diluted shares outstanding | 374,009 | 374,505 | ||||||
Adjusted diluted net income per share (non-GAAP) | $ 0.59 | $ 0.73 | ||||||
Six months ended June 30, | ||||||||
2019 | 2018 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income attributable to Continental Resources (GAAP) | $423,533 | $ 1.13 | $476,410 | $ 1.27 | ||||
Adjustments: | ||||||||
Non-cash (gain) loss on derivatives | (30,592) | 11,465 | ||||||
Property impairments | 46,655 | 62,946 | ||||||
(Gain) loss on sale of assets, net | 112 | (6,751) | ||||||
Total tax effect of adjustments (1) | (3,962) | (16,054) | ||||||
Total adjustments, net of tax | 12,213 | 0.03 | 51,606 | 0.14 | ||||
Adjusted net income (non-GAAP) | $435,746 | $ 1.16 | $528,016 | $1.41 | ||||
Weighted average diluted shares outstanding | 374,557 | 374,583 | ||||||
Adjusted diluted net income per share (non-GAAP) | $ 1.16 | $ 1.41 |
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2019 and 24.0% in effect for 2018 to the pre-tax amount of adjustments associated with our operations in the United States. |
Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At June 30, 2019, the Company's total debt was $5.77 billion and its net debt amounted to $5.56 billion, representing total debt of $5.77 billion less cash and cash equivalents of $206.5 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
Three months ended June 30, | Six months ended June 30, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net income | $ 236,450 | $ 242,464 | $ 422,943 | $ 476,410 | ||||
Interest expense | 68,471 | 74,288 | 136,308 | 150,182 | ||||
Provision for income taxes | 75,649 | 75,232 | 127,639 | 146,768 | ||||
Depreciation, depletion, amortization and accretion | 485,621 | 447,200 | 980,641 | 901,578 | ||||
Property impairments | 21,339 | 29,162 | 46,655 | 62,946 | ||||
Exploration expenses | 3,090 | 303 | 4,927 | 2,023 | ||||
Impact from derivative instruments: | ||||||||
Total (gain) loss on derivatives, net | (53,448) | 12,685 | (52,324) | 2,511 | ||||
Total cash (paid) received on derivatives, net | 8,670 | 4,758 | 21,732 | 8,954 | ||||
Non-cash (gain) loss on derivatives, net | (44,778) | 17,443 | (30,592) | 11,465 | ||||
Non-cash equity compensation | 12,177 | 10,562 | 24,283 | 21,478 | ||||
EBITDAX (non-GAAP) | $ 858,019 | $ 896,654 | $ 1,712,804 | $ 1,772,850 |
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended June 30, | Six months ended June 30, | |||||||
In thousands | 2019 | 2018 | 2019 | 2018 | ||||
Net cash provided by operating activities | $ 783,396 | $ 753,802 | $ 1,504,904 | $ 1,639,993 | ||||
Current income tax provision | - | - | - | - | ||||
Interest expense | 68,471 | 74,288 | 136,308 | 150,182 | ||||
Exploration expenses, excluding dry hole costs | 3,090 | 303 | 4,927 | 2,022 | ||||
Gain (loss) on sale of assets, net | (364) | 6,711 | (112) | 6,751 | ||||
Other, net | (1,853) | (3,221) | (7,078) | (7,798) | ||||
Changes in assets and liabilities | 5,279 | 64,771 | 73,855 | (18,300) | ||||
EBITDAX (non-GAAP) | $ 858,019 | $ 896,654 | $ 1,712,804 | $ 1,772,850 |
Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.
Three months ended June 30, 2019 | Three months ended June 30, 2018 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $1,005,146 | $132,279 | $1,137,425 | $946,884 | $190,644 | $1,137,528 | ||||||
Less: Transportation expenses | (45,981) | (7,412) | (53,393) | (40,217) | (7,037) | (47,254) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $959,165 | $124,867 | $1,084,032 | $906,667 | $183,607 | $1,090,274 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 17,549 | 75,254 | 30,091 | 14,311 | 69,310 | 25,863 | ||||||
Net sales price (non-GAAP) | $54.66 | $1.66 | $36.03 | $63.35 | $2.65 | $42.16 | ||||||
Six months ended June 30, 2019 | Six months ended June 30, 2018 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $1,916,264 | $330,745 | $2,247,009 | $1,853,165 | $398,215 | $2,251,380 | ||||||
Less: Transportation expenses | (87,628) | (14,903) | (102,531) | (80,603) | (15,948) | (96,551) | ||||||
Net crude oil and natural gas sales (non-GAAP) | $1,828,636 | $315,842 | $2,144,478 | $1,772,562 | $382,267 | $2,154,829 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 34,922 | 149,944 | 59,912 | 28,993 | 136,040 | 51,667 | ||||||
Net sales price (non-GAAP) | $52.36 | $2.11 | $35.79 | $61.14 | $2.81 | $41.71 |
Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended June 30, | Six months ended June 30, | |||||||
2019 | 2018 | 2019 | 2018 | |||||
Total G&A per Boe (GAAP) | $1.57 | $1.82 | $1.58 | $1.75 | ||||
Less: Non-cash equity compensation per Boe | (0.40) | (0.41) | (0.40) | (0.42) | ||||
Cash G&A per Boe (non-GAAP) | $1.17 | $1.41 | $1.18 | $1.33 |
Continental Resources, Inc. | ||
2019 Guidance(1) | ||
As of August 5, 2019 | ||
2019 | ||
Full-year average oil production | 195,000 to 200,000 Bopd | |
Full-year average natural gas production | 820,000 to 840,000 Mcfpd | |
Capital expenditures budget | $2.6 billion | |
Operating Expenses: | ||
Production expense per Boe | $3.50 to $4.00 | |
Production tax (% of net oil & gas revenue) | 8.5% | |
Cash G&A expense per Boe(2) | $1.15 to $1.35 | |
Non-cash equity compensation per Boe | $0.40 to $0.50 | |
DD&A per Boe | $15.00 to $17.00 | |
Average Price Differentials: | ||
NYMEX WTI crude oil (per barrel of oil) | ($4.50) to ($5.50) | |
Henry Hub natural gas (per Mcf) | ($0.50) to ($1.00) |
(1) Changed items are shown in bold. | ||
(2) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.55 to $1.85 per Boe. |
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SOURCE Continental Resources
DENVER, July 31, 2019 /PRNewswire/ -- One of the largest independent upstream oil and gas-focused investor conferences—The Oil & Gas Conference®—will take place Aug. 11-14, 2019, at the Denver Downtown Westin hotel.
The event is EnerCom's 24th annual Denver investment conference. At this year's conference, c-level leadership of leading oil and gas companies will present their plans for drilling and completing wells, discuss well results and capital efficiency, and estimate capital expenditures and production for the balance of 2019 and into 2020.
For the buyside investment community, the EnerCom conference provides top level access to oil and gas company c-suites. The four-day conference allows institutional investors to set one-on-one meetings with company management teams. Meetings are limited to buyside principals, portfolio managers, CIOs and securities analysts. Individual company meeting requests must be made in advance as part of the online conference registration process.
The publicly traded companies that make up the exclusive group of energy producers and oilfield service and royalty companies at the EnerCom conference represent a combined total of:
Presenting companies represent oil and gas operations in all of North America's shale basins, Latin America's conventional oil plays, the Gulf of Mexico and other international oil and gas plays. The EnerCom conference is a convenient way for portfolio managers and analysts to see approximately 85+ oil and gas companies together at a single venue where informal networking and one-on-one access to company management is part of the conference experience.
The complete daily schedule of presenters is posted on the website (presenters, days, times are subject to change). The conference investor presentations begin at 8:00 a.m. and run through 4:30 p.m.
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.
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.
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; Tudor Pickering & Holt, Savills, Shearman & Sterling, Kayrros, 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 offers investor relations consulting and it 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 – March 4-5, 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.
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.
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
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.
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.
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.
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 .
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.
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.
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.
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.
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.
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.
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.
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/
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.
KAYRROS
Kayrros is the leading advanced data analytics company helping global energy market players make better investment decisions. Kayrros experts extract value from the integration of alternative and market data into unique product offerings across the energy chain. With more than 140 employees representing over 15 nationalities working in Paris, Houston, London, New York and Singapore, Kayrros delivers actionable information in near realtime using cutting-edge technologies such as satellite imagery, AI and machine learning. Kayrros solutions are rapidly scalable and continually expanded to new geographies and new sources of data that help provide greater transparency into energy markets worldwide. For more information, please visit www.kayrros.com
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SOURCE EnerCom, Inc.
OKLAHOMA CITY, July 31, 2019 /PRNewswire/ -- Lagoon Water Solutions; Oklahoma's premier water midstream provider, closed on an $85 million purchase of Continental's eastern STACK water recycling facility, gathering system and three related disposal wells in Blaine County, Oklahoma. Along with the transaction, Lagoon has entered into a long-term arrangement with Continental to gather and dispose of produced water and source recycled water for Continental.
Lagoon, under the terms of the agreement, will be the first midstream company to provide recycled water for completion operations in Oklahoma. Additionally, this deal, negotiated by the new management team at Lagoon, will bring the company's total miles of pipe to 200, more than any other water midstream operator in the state.
"We believe strongly in our commitment to being the premier solution for oil and gas operators' water midstream needs and are excited about our management team securing such a significant deal with a respected, top-tier operator like Continental," said Kevin Lafferty, President and CEO, Lagoon Water Solutions. "This acquisition expands our network of reliable gathering and disposal assets in the core of the STACK play and further guarantees reliable takeaway water solutions for STACK operators."
Lagoon Water Solutions is committed to supporting its customers' water midstream needs with a focus on long-term water infrastructure solutions that reduce customers' operating costs and provide flow assurance, making Lagoon a trusted provider and reliable partner to oil and gas operators. Closing on a long-term deal with Continental allows Lagoon to expand into water recycling and water supply operations for its customers, while also providing sustainable water sourcing solutions.
"Environmental excellence is a core value at Lagoon and a critical aspect of our management philosophy," said Caitlyn Jackson, Senior Vice President of Commercial and Business Development, Lagoon Water Solutions. "We are driven to be innovative and our team has created a culture geared to not only providing industry-leading customer support but also furthering industry's efforts to recycle produced water to preserve basin water resources."
About Lagoon Water Solutions
Lagoon Water Solutions is Oklahoma's premier water midstream solution, developing and operating midstream water infrastructure throughout the Anadarko Basin. For more information about Lagoon and their new management team, visit www.LagoonWS.com
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Media Contacts:
Lagoon Water Solutions
Joshua Harlow
(405) 850-4471
Harlow@freemarketconsultingusa.com
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SOURCE Lagoon Water Solutions
OKLAHOMA CITY, July 31, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced the sale of its eastern STACK water gathering and recycling system in Blaine County, Oklahoma for $85 million to Lagoon Water Solutions ("Lagoon"). Along with the divestiture, Continental has entered into a long-term arrangement with Lagoon to provide water sourcing, gathering and disposal services for Continental's future development in the area.
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Continental owns and operates three additional water infrastructure systems in Oklahoma, as well as ten additional systems in the Bakken. "The divestiture of this water handling facility for $85 million underscores Continental's ability to innovatively generate value from its assets. This system represents a small portion of the water handling facilities Continental owns, which we value at approximately $1 billion," said Harold Hamm, Chairman and Chief Executive Officer. "These facilities contain significant added value for our shareholders."
The Company also announced the following strategic initiatives:
These strategic initiatives will add significant value for the Company's shareholders in 2020 and beyond. The Company remains disciplined and is committed to its corporate objectives. Excluding the aforementioned unbudgeted items, the Company is tracking towards its $2.6 billion capital expenditures budget.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact are forward-looking statements, including, but not limited to, statements, information, forecasts or expectations regarding the Company's business and future plans. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-85-million-divestiture-of-water-handling-facility-in-stack-and-strategic-initiatives-300893663.html
SOURCE Continental Resources
OKLAHOMA CITY, July 9, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) plans to announce second quarter 2019 results on Monday, August 5, 2019 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss second quarter 2019 results on Tuesday, August 6, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, August 6, 2019 |
Dial-in: | 1-888-317-6003 |
Intl. dial-in: | 1-412-317-6061 |
Conference ID: | 8142074 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 1-877-344-7529 |
Intl. replay: | 1-412-317-0088 |
Conference ID: | 10132642 |
The Company plans to publish a second quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on August 6, 2019.
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About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: | |
Rory Sabino | Kristin Thomas | |
Vice President, Investor Relations | Senior Vice President, Public Relations | |
405-234-9620 | 405-234-9480 | |
Lucy Guttenberger | ||
Investor Relations Analyst | ||
405-774-5878 | ||
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-second-quarter-2019-results-on-monday-august-5-2019-300882029.html
SOURCE Continental Resources
DENVER, June 25, 2019 /PRNewswire/ -- The oil and gas companies presenting at EnerCom's 24th annual The Oil & Gas Conference® are largely independent exploration and production companies developing oil and gas assets. The conference affords oil and gas analysts, portfolio managers, family offices and other buyside investors an extensive view of U.S. and Canadian shale companies, Latin American conventionals and U.S. offshore drillers–all in one place: Denver, Colorado.
The 24th edition of one of the industry's largest independent upstream oil and gas-focused conferences takes place Aug. 11-14, 2019, at Denver, Colorado's downtown Westin hotel.
Additional Presenting Companies on Day Two of the 2019 EnerCom Conference
The second day of the EnerCom conference includes the following oil and gas company management teams:
The daily schedule of presenters is also posted on the website (presenters, days, times are subject to change). The conference investor presentations begin at 7:30 a.m. and run through 4:30 p.m.
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.
On Aug. 13th, Harvard PhD (Economics) and CIBC Capital Markets CIBC (NYSE: CM) Chief Economist Avery Shenfeld, repeat winner of Dow Jones MarketWatch forecasting award and Bloomberg Markets' awards for forecasting accuracy, will deliver his views on where oil and gas markets are headed.
Tuesday's keynote luncheon is a "Fireside Chat" with outspoken, legendary oilman Continental Resources (NYSE: CLR) Chairman and CEO Harold Hamm.
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 – March 4-5, 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.
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.
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
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.
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.
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.
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 .
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.
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.
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.
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.
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.
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.
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.
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/
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-announces-further-presenting-companies-at-the-oil--gas-conference-2019-300873059.html
SOURCE EnerCom, Inc.
DENVER, June 19, 2019 /PRNewswire/ -- EnerCom has released the presentation schedule of oil and gas companies presenting on day two of its 24th annual The Oil & Gas Conference® which runs Aug. 11-14, 2019, in Denver, Colorado.
Presenting Companies at the 2019 EnerCom Conference on Day Two, Aug. 13, 2019
The second day of the EnerCom conference features E&Ps and operators producing from the U.S., Canadian and Latin American oil and gas plays, including:
Complete List of Day Two Presenters at EnerCom's 2019 The Oil & Gas Conference
The daily schedule of presenters is also posted on the website (presenters, days, times are subject to change). The conference investor presentations begin at 7:30 a.m. and run through 4:30 p.m.
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.
On Aug. 13th, Harvard PhD (Economics) and CIBC Capital Markets CIBC (NYSE: CM) Chief Economist Avery Shenfeld, repeat winner of Dow Jones MarketWatch forecasting award and Bloomberg Markets' awards for forecasting accuracy, will deliver his views on where oil and gas markets are headed.
Tuesday's keynote luncheon is a "Fireside Chat" with outspoken, legendary oilman Continental Resources (NYSE: CLR) Chairman and CEO Harold Hamm.
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 throughthe 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 – March 4-5, 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.
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.
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
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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/
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.
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SOURCE EnerCom, Inc.
DENVER, June 5, 2019 /PRNewswire/ -- EnerCom is pleased to announce that global oil and gas giant Eni, SpA Vice President Andrew Lees will deliver the keynote luncheon address at EnerCom's The Oil & Gas Conference® on Aug. 14, 2019.
Eni, SpA
Eni, SpA (NYSE: E) is an Italian global oil and gas and energy company operating in 67 countries worldwide, with 30,000 employees in upstream, midstream and downstream operations. Eni reported daily production for oil and gas of 1.85 MMBOPD for 2018. The company's adjusted operating profit for 2018 more than doubled its 2017 operating profit and represented Eni's best performance of the past eight years, Eni reports.
In 2018 Eni, SpA's upstream exploration group operated in:
Goliat has been developed using the world's largest and most sophisticated cylindrical floating production and storage unit - FPSO—it is the largest and most sophisticated cylindrical FPSO ever built with production capacity of a million barrels of oil.
"With the increasing integration of Upstream and Mid-downstream and due to the massive amount of gas we have discovered, we are turning into a gas and power company with an evolving model that is that is still tied to retail but linked to Upstream," Eni said.
Andrew Lees
Andrew Lees is vice president of North America investor relations for Eni, SpA.
Lees draws on a wealth of energy investing, analysis and oil and gas finance and capital experience in his leadership of Eni, SpA's North American investor relations duties. Before joining Eni in 2015, he was principal at Gadsden Enterprises, LLC. Lees previously served as Invesco's lead portfolio manager for both the energy team and the gold and precious metals team. He entered the investment industry in 1994 and worked for Invesco from 2005 to 2013. Before Invesco Lees served as director of investment banking with Trinity Capital Services, director and research analyst with RBC Capital Markets, VP and senior analyst for Stifel, Nicolaus & Co., senior analyst for Petrie Parkman & Co., and as a research analyst for A.G. Edwards.
How to Hear the Speakers: Completing online registration well in advance of The Oil & Gas Conference® will provide your best chance to gain insight from global supermajor Eni during Mr. Lees' luncheon as well as hearing the luncheon discussions with Continental Resources Chairman and CEO Harold Hamm and Occidental Petroleum SVP and chief financial officer Cedric Burgher earlier in the conference.
Online Registration is Open for EnerCom's 24TH Annual The Oil & Gas Conference®: The conference is August 11-14, 2019, at the Westin Denver Downtown hotel. Buyside investors and oil and gas company professionals may register for the event through the conference website.
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 forum fosters healthy dialogue and informal networking opportunities for attendees.
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 list of EnerCom's 2019 presenting companies includes (but is not limited to) the following companies:
Additional 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, the U.S. becoming a net energy exporter, frac sand supply and logistics, and capital sources for energy development.
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 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; 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 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 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.
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SOURCE EnerCom, Inc.
OKLAHOMA CITY, June 3, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced that its Board of Directors approved the initiation of a quarterly dividend of $0.05 per share ($0.20 per share annualized) on the Company's common stock and an initial $1 billion share-repurchase program. Continental maintains its 2019 guidance as announced on February 13, 2019, reaffirming the Company's commitment to its corporate objectives and a strong alignment with shareholders.
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"Today marks another milestone in Continental's history as we initiate a total shareholder return strategy," said Harold Hamm, Chairman and Chief Executive Officer. "Our disciplined approach to balancing capital-efficient growth and reducing debt has enabled us to approve both an initial $0.20 per share annualized dividend and an initial $1 billion share-repurchase program. This demonstrates the confidence we have in the quality and sustainability of our assets and our commitment to maximizing shareholder value. We see the current value of our equity as being unreasonably low, making the acquisition of our stock the best use of excess cash at this time."
For over 50 years, Continental has grown organically through exploration and will continue to do so. Although there has been much market speculation, the Company's five year projection does not contemplate corporate M&A transactions. Continental remains keenly focused on capital efficiency and total shareholder returns.
The Company's total shareholder return strategy now includes:
Under the stock repurchase program, the Company may repurchase shares from time to time at management's discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. In addition, shares may also be repurchased pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934, which would permit shares to be repurchased when the Company might otherwise be precluded from doing so under insider trading laws. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume, general market conditions, legal requirements, general business conditions and corporate considerations determined by the Company's management, such as liquidity and capital needs. The stock repurchase program may be modified, suspended or terminated at any time by the Company's Board of Directors. The Company intends to fund repurchases under the program from existing cash or future cash flow.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact are forward-looking statements, including, but not limited to, statements, information, forecasts or expectations regarding the Company's business and future plans, including those relating to its share repurchase program, payment of dividends, debt reduction goals, free cash flow generation and liquidity expectations, and its expectations regarding the achievement of ROCE goals. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Non-GAAP Financial Measures
Free Cash Flow
Our presentation of projected free cash flow is a non-GAAP measure. We define projected free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our relationship formed with Franco-Nevada in 2018 to fund a portion of certain mineral acquisitions, which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Management believes that this measure is useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. From time to time, the Company provides forward-looking free cash flow estimates or targets; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At March 31, 2019, the Company's net debt amounted to $5.50 billion (representing total debt of $5.77 billion less cash and cash equivalents of $264.4 million), which represents a $1.7 billion decrease compared to $7.19 billion of net debt at March 31, 2016 (representing total debt of $7.21 billion less cash and cash equivalents of $12.9 million). From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
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SOURCE Continental Resources
DENVER, May 29, 2019 /PRNewswire/ -- EnerCom is pleased to announce that legendary oilman Harold G. Hamm, chairman and CEO of Continental Resources (NYSE: CLR), will take the stage for a discussion about U.S. shale and look at the prospects for U.S. oil and gas exploration in a "fireside chat" Tuesday, August 13, 2019, during EnerCom's The Oil & Gas Conference® in downtown Denver's Westin hotel.
Limited space is available for conference registrants to join the discussion with Mr. Hamm. Completing online registration well in advance of The Oil & Gas Conference® will provide your best chance to participate in Mr. Hamm's luncheon discussion during the 2019 EnerCom conference.
Harold Hamm and Continental Resources
Harold Hamm is founder, chairman and chief executive officer of Continental Resources, one of North America's iconic oil and gas explorers and producers and one of the leading oil producers in the Bakken oil play in the Williston Basin and the STACK/SCOOP plays in Oklahoma. With a market capitalization of $14.5 billion, Continental ranks in the top ten largest U.S. independent exploration and production companies, sharing the top of the list with companies like ConocoPhillips ($COP), EOG Resources ($EOG) and Occidental Petroleum (NYSE: OXY), whose CFO Cedric Burgher will give a luncheon keynote address at The Oil & Gas Conference® on Monday, Aug. 12.
Mr. Hamm is heavily involved with furthering the success of the U.S. oil and gas industry on a global scale. He co-founded and serves as chairman of the Domestic Energy Producers Alliance, whose goal is to preserve the millions of jobs and billions of dollars in economic activity and tax revenues generated by onshore drilling and production activities within the United States. Through his work with DEPA, Mr. Hamm is widely recognized as the man who led the charge to lift America's 40-year-old ban on U.S. crude oil exports, opening new global markets for America's oil producers.
Hamm, the youngest of 13 children born to a family of sharecroppers, began working in the oilfields as a teenager and founded Continental Resources in 1967 at the age of 21. He is a frequent guest on business and financial cable networks and global business publications. Mr. Hamm has been recognized by numerous industry groups as Executive of the Year, Wildcatter of the Year, Chief Roughneck, CEO of the Year and Entrepreneur of the Year. In 2012 Harold Hamm was named by TIME Magazine as one of the "100 Most Influential People in the World."
Online registration is open for EnerCom's 24TH annual The Oil & Gas Conference®
The conference is August 11-14, 2019, at the Westin Denver Downtown hotel. Buyside investors and oil and gas company professionals may register for the event through the conference website.
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 forum fosters healthy dialogue and informal networking opportunities for attendees.
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 list of EnerCom's 2019 presenting companies includes (but is not limited to) the following companies:
Additional 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, the U.S. becoming a net energy exporter, frac sand supply and logistics, and capital sources for energy development.
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 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; 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 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 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.
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SOURCE EnerCom, Inc.
OKLAHOMA CITY, April 29, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced first quarter 2019 operating and financial results.
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
The Company reported net income of $187.0 million, or $0.50 per diluted share, for the quarter ended March 31, 2019. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In first quarter 2019, these typically excluded items in aggregate represented $29.6 million, or $0.08 per diluted share, of Continental's reported net income. Adjusted net income for first quarter 2019 was $216.6 million, or $0.58 per diluted share (non-GAAP). Net cash provided by operating activities for first quarter 2019 was $721.5 million and EBITDAX was $854.8 million (non-GAAP).
Adjusted net income, adjusted net income per share, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
"Continental's outstanding first quarter 2019 results reflect our commitment to our formula for success. The combination of high quality Bakken and Oklahoma assets with efficient, low cost operations translates to strong corporate returns and sustainable cash flow generation," said Harold Hamm, Chairman and Chief Executive Officer.
Production Update: 1Q19 Average Daily Oil Production up 18% over 1Q18
First quarter 2019 production increased 16% over first quarter 2018, averaging 332,236 Boe per day. First quarter 2019 oil production increased 18% over first quarter 2018, averaging 193,921 barrels of oil (Bo) per day. First quarter 2019 natural gas production increased 12% over first quarter 2018, averaging 829.9 million cubic feet (MMcf) per day. The following table provides the Company's average daily production by region for the periods presented.
1Q | 4Q | 1Q | ||||
Boe per day | 2019 | 2018 | 2018 | |||
Bakken | 199,423 | 183,836 | 161,356 | |||
SCOOP | 67,659 | 67,244 | 62,012 | |||
STACK | 56,513 | 62,947 | 53,361 | |||
All other | 8,641 | 9,974 | 10,681 | |||
Total | 332,236 | 324,001 | 287,410 |
Bakken: 3 Strategic Step-Out Wells Deliver Excellent Results
The Company's first quarter 2019 Bakken production increased 24% over first quarter 2018, averaging 199,423 Boe per day. In first quarter 2019, average daily Bakken oil production increased 8% over fourth quarter 2018 and the Company completed 55 gross (40 net) operated wells with first production. These wells flowed at an average initial 24-hour rate per well of 2,300 Boe per day, with 80% of the production being oil.
In first quarter 2019, the Company completed 3 strategic step-out wells in North Dakota and Montana Bakken. The wells were the Company's first tests of its optimized completion technology in these extended portions of its Bakken leasehold. The tests proved successful, as the wells are outperforming offsetting legacy producers by as much as 110% in the first 60 days. In Montana, the Baird Federal 2-34H flowed at an initial rate of 1,680 Boe per day (85% oil), outperforming the legacy well by 110% at 60 days. In southern Billings County, North Dakota, the Burian 4-27H1 flowed at an initial rate of 2,400 Boe per day (80% oil), outperforming the legacy well by 80% at 60 days. In eastern Williams County, North Dakota, the three-mile lateral McClintock 8-1H1 flowed at an initial rate of 2,440 Boe per day (80% oil), outperforming the two-mile legacy well by 100% at 60 days.
"These strategic step-outs provide further proof that our optimized completion technology is uplifting well performance across all of our Bakken leasehold, even into Montana. This is great news for our shareholders as the value of our Bakken inventory of approximately 4,000 wells continues to grow," said Jack Stark, President.
SpringBoard: Oil Growth Ahead of Schedule; Avg. ~14,000 Net Bopd in April (28 Days)
The Company's first quarter 2019 SCOOP production increased 9% over first quarter 2018, averaging 67,659 Boe per day. The Company completed 15 gross (13 net) operated wells with first production in first quarter 2019.
Project SpringBoard oil production is growing ahead of schedule, averaging ~14,000 Bo per day in the first 28 days of April 2019. The Company has updated its SpringBoard oil production growth target to 18,000 Bo per day in third quarter 2019, compared to the initial target of 16,500 Bo per day. Cycle time improvements and higher early time well productivity are accelerating production growth and enabling the Company to achieve its objectives for 2019 with 25% fewer rigs. The Company currently has 9 rigs drilling, 33 wells waiting on completion and 39 wells producing in Project SpringBoard.
In first quarter 2019, the Company completed the first 6 Woodford wells in Project SpringBoard, which flowed at a combined initial rate of 9,960 Boe per day, averaging 1,660 Boe per day per well, which includes 1,245 Bo per day per well. These wells are currently outperforming the legacy 1.5 MMBoe Woodford legacy oil type curve.
STACK: Continues to Deliver Outstanding Results
The Company's first quarter 2019 STACK production increased 6% over first quarter 2018, averaging 56,513 Boe per day. During the quarter, the Company completed 9 gross (5 net) operated wells with first production in 2019.
In the over-pressured condensate window, the 5-well Tolbert unit flowed at a combined initial rate of 18,700 Boe per day, averaging 3,740 Boe per day per well, which includes 1,180 Bo per day per well. In the over-pressured oil window, the 3-well Lugene unit flowed at a combined initial rate of 9,270 Boe per day, averaging 3,090 Boe per day per well, which includes 1,540 Bo per day per well. The Tolbert unit was developed with 2-mile laterals and the Lugene unit with 1-mile laterals. The Company also completed its first 3-mile Meramec well in STACK. The Blondie 1-6-7-18XHM 3-mile lateral flowed at an initial rate of 3,400 Boe per day, which includes 2,460 Bo per day per well.
Financial Update
"Continental's capital-efficient and highly productive first quarter 2019 results underscore our commitment to delivering shareholder value in 2019. We are extremely pleased with our execution on cost metrics and the potential for favorable updates to these targets later in the year," said John Hart, Chief Financial Officer.
As of March 31, 2019, the Company's balance sheet included approximately $264.4 million in cash and cash equivalents, $5.77 billion in total debt and $5.50 billion in net debt (non-GAAP). The Company anticipates further reducing net debt to $5 billion in 2019.
In first quarter 2019, the Company's average net sales prices excluding the effects of derivative positions were $50.05 per barrel of oil and $2.56 per Mcf of gas, or $35.56 per Boe. Production expense per Boe was $3.59 for first quarter 2019, below annual guidance of $3.75 to $4.25 per Boe. Total G&A expenses per Boe were $1.60 for first quarter 2019, also below annual guidance of $1.70 to $2.00 per Boe.
The Company's first quarter 2019 crude oil differential was $4.77 per barrel below the NYMEX daily average for the period, a 43% improvement over fourth quarter 2018 and within annual guidance of $4.50 to $5.50 per barrel. The wellhead natural gas price for first quarter 2019 was $0.60 per Mcf below the average NYMEX Henry Hub benchmark price. The Company expects further improvement to the natural gas differential in 2019.
The Company realized approximately $13 million of cash gains from natural gas hedges in the first quarter. For the balance of 2019, natural gas is hedged 577,000 MMBtus per day at an average NYMEX Henry Hub price of $2.80.
Non-acquisition capital expenditures for first quarter 2019 totaled approximately $750.2 million, including $631.1 million in exploration and development drilling and completion, $14.8 million in leasehold, $51.3 million in minerals, of which 80% was recouped from Franco-Nevada, and $53.0 million in workovers, recompletions and other. Our first quarter capital expenditures reflect an accelerated pace of development due to improved cycle times and efficiency gains which resulted in 8 more net wells being completed and 6 more net wells being spud during the quarter than budgeted while using the same number of rigs and completion crews. The Company maintains its $2.6 billion capital expenditures guidance for 2019.
The Company's full 2019 guidance remains as announced on February 13, 2019 and can be found at the conclusion of this press release.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
1Q | 4Q | 1Q | |||
2019 | 2018 | 2018 | |||
Average daily production: | |||||
Crude oil (Bbl per day) | 193,921 | 186,934 | 163,837 | ||
Natural gas (Mcf per day) | 829,891 | 822,402 | 741,442 | ||
Crude oil equivalents (Boe per day) | 332,236 | 324,001 | 287,410 | ||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||
Crude oil ($/Bbl) | $50.05 | $50.06 | $58.98 | ||
Natural gas ($/Mcf) | $2.56 | $3.26 | $2.98 | ||
Crude oil equivalents ($/Boe) | $35.56 | $37.13 | $41.26 | ||
Production expenses ($/Boe) | $3.59 | $3.50 | $3.60 | ||
Production taxes (% of net crude oil and gas sales) | 8.2% | 8.2% | 7.6% | ||
DD&A ($/Boe) | $16.60 | $16.41 | $17.61 | ||
Total general and administrative expenses ($/Boe) (2) | $1.60 | $1.65 | $1.67 | ||
Net income attributable to Continental Resources (in thousands) | $186,976 | $197,738 | $233,946 | ||
Diluted net income per share attributable to Continental Resources | $0.50 | $0.53 | $0.63 | ||
Adjusted net income (non-GAAP) (in thousands) (1) | $216,610 | $201,686 | $255,140 | ||
Adjusted diluted net income per share (non-GAAP) (1) | $0.58 | $0.54 | $0.68 | ||
Net cash provided by operating activities (in thousands) | $721,508 | $955,267 | $886,191 | ||
EBITDAX (non-GAAP) (in thousands) (1) | $854,785 | $850,640 | $876,196 |
(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.19, $1.18, and $1.25 for 1Q 2019, 4Q 2018, and 1Q 2018, respectively. Non-cash equity compensation expense per Boe was $0.41, $0.47, and $0.42 for 1Q 2019, 4Q 2018, and 1Q 2018, respectively. |
First Quarter Earnings Conference Call
The Company plans to host a conference call to discuss first quarter 2019 results on Tuesday, April 30, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, April 30, 2019 |
Dial-in: | 844-309-6572 |
Intl. dial-in: | 484-747-6921 |
Conference ID: | 4290299 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 855-859-2056 or 404-537-3406 |
Intl. replay: | 800-585-8367 |
Conference ID: | 4290299 |
The Company plans to publish a first quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on April 30, 2019.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
Continental Resources, Inc. and Subsidiaries | |||
Three months ended March 31, | |||
2019 | 2018 | ||
Revenues: | In thousands, except per share data | ||
Crude oil and natural gas sales | $ 1,109,584 | $ 1,113,852 | |
Gain (loss) on natural gas derivatives, net | (1,124) | 10,174 | |
Crude oil and natural gas service operations | 15,774 | 17,002 | |
Total revenues | 1,124,234 | 1,141,028 | |
Operating costs and expenses: | |||
Production expenses | 106,966 | 92,962 | |
Production taxes | 86,441 | 80,580 | |
Transportation expenses | 49,139 | 49,297 | |
Exploration expenses | 1,837 | 1,720 | |
Crude oil and natural gas service operations | 7,186 | 4,583 | |
Depreciation, depletion, amortization and accretion | 495,019 | 454,378 | |
Property impairments | 25,316 | 33,784 | |
General and administrative expenses | 47,617 | 43,043 | |
Net gain on sale of assets and other | (252) | (41) | |
Total operating costs and expenses | 819,269 | 760,306 | |
Income from operations | 304,965 | 380,722 | |
Other income (expense): | |||
Interest expense | (67,837) | (75,894) | |
Other | 1,355 | 654 | |
(66,482) | (75,240) | ||
Income before income taxes | 238,483 | 305,482 | |
Provision for income taxes | (51,990) | (71,536) | |
Net income | 186,493 | 233,946 | |
Net loss attributable to noncontrolling interests | (483) | - | |
Net income attributable to Continental Resources | $ 186,976 | $ 233,946 | |
Net income per share attributable to Continental Resources: | |||
Basic | $ 0.50 | $ 0.63 | |
Diluted | $ 0.50 | $ 0.63 |
Continental Resources, Inc. and Subsidiaries | ||||
In thousands | March 31, 2019 | December 31, 2018 | ||
Assets | ||||
Cash and cash equivalents | $ 264,371 | $ 282,749 | ||
Other current assets | 1,219,691 | 1,129,612 | ||
Net property and equipment (1) | 14,118,264 | 13,869,800 | ||
Other noncurrent assets | 31,597 | 15,786 | ||
Total assets | $ 15,633,923 | $ 15,297,947 | ||
Liabilities and equity | ||||
Current liabilities | $ 1,445,451 | $ 1,387,509 | ||
Long-term debt, net of current portion | 5,766,647 | 5,765,989 | ||
Other noncurrent liabilities | 1,783,522 | 1,722,588 | ||
Equity attributable to Continental Resources | 6,323,710 | 6,145,133 | ||
Equity attributable to noncontrolling interests | 314,593 | 276,728 | ||
Total liabilities and equity | $ 15,633,923 | $ 15,297,947 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $11.30 billion and $10.81 billion as of March 31, 2019 and December 31, 2018, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||
Three months ended March 31, | ||||
In thousands | 2019 | 2018 | ||
Net income | $186,493 | $233,946 | ||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||
Non-cash expenses | 603,591 | 569,174 | ||
Changes in assets and liabilities | (68,576) | 83,071 | ||
Net cash provided by operating activities | 721,508 | 886,191 | ||
Net cash used in investing activities | (753,071) | (628,211) | ||
Net cash (used in) provided by financing activities | 13,170 | (203,724) | ||
Effect of exchange rate changes on cash | 15 | (13) | ||
Net change in cash and cash equivalents | (18,378) | 54,243 | ||
Cash and cash equivalents at beginning of period | 282,749 | 43,902 | ||
Cash and cash equivalents at end of period | $264,371 | $ 98,145 |
Non-GAAP Financial Measures
Non-GAAP adjusted net income and adjusted net income per share attributable to Continental
Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, and gains and losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.
1Q 2019 | 4Q 2018 | 1Q 2018 | ||||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | $ | Diluted EPS | ||||||
Net income attributable to Continental Resources (GAAP) | $186,976 | $ 0.50 | $197,738 | $ 0.53 | $233,946 | $ 0.63 | ||||||
Adjustments: | ||||||||||||
Non-cash (gain) loss on derivatives | 14,186 | (25,022) | (5,978) | |||||||||
Property impairments | 25,316 | 38,494 | 33,784 | |||||||||
Gain on sale of assets, net | (252) | (8,410) | (41) | |||||||||
Total tax effect of adjustments (1) | (9,616) | (1,114) | (6,571) | |||||||||
Total adjustments, net of tax | 29,634 | 0.08 | 3,948 | 0.01 | 21,194 | 0.05 | ||||||
Adjusted net income (non-GAAP) | $216,610 | $ 0.58 | $201,686 | $0.54 | $255,140 | $ 0.68 | ||||||
Weighted average diluted shares outstanding | 374,474 | 374,525 | 374,181 | |||||||||
Adjusted diluted net income per share (non-GAAP) | $ 0.58 | $0.54 | $ 0.68 |
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 1Q 2019 and 4Q 2018 and 24.0% in effect for 1Q 2018 to the pre-tax amount of adjustments associated with our operations in the United States. |
Non-GAAP Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At March 31, 2019, the Company's total debt was $5.77 billion and its net debt amounted to $5.50 billion, representing total debt of $5.77 billion less cash and cash equivalents of $264.4 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Non-GAAP EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
1Q | 4Q | 1Q | ||||
In thousands | 2019 | 2018 | 2018 | |||
Net income | $ 186,493 | $ 199,121 | $ 233,946 | |||
Interest expense | 67,837 | 69,441 | 75,894 | |||
Provision for income taxes | 51,990 | 62,868 | 71,536 | |||
Depreciation, depletion, amortization and accretion | 495,019 | 488,416 | 454,378 | |||
Property impairments | 25,316 | 38,494 | 33,784 | |||
Exploration expenses | 1,837 | 3,295 | 1,720 | |||
Impact from derivative instruments: | ||||||
Total (gain) loss on derivatives, net | 1,124 | 19,394 | (10,174) | |||
Total cash (paid) received on derivatives, net | 13,062 | (44,416) | 4,196 | |||
Non-cash (gain) loss on derivatives, net | 14,186 | (25,022) | (5,978) | |||
Non-cash equity compensation | 12,107 | 14,027 | 10,916 | |||
EBITDAX (non-GAAP) | $ 854,785 | $ 850,640 | $ 876,196 |
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
1Q | 4Q | 1Q | ||||
In thousands | 2019 | 2018 | 2018 | |||
Net cash provided by operating activities | $ 721,508 | $ 955,267 | $ 886,191 | |||
Current income tax provision | - | 2 | - | |||
Interest expense | 67,837 | 69,441 | 75,894 | |||
Exploration expenses, excluding dry hole costs | 1,837 | 3,149 | 1,719 | |||
Gain on sale of assets, net | 252 | 8,410 | 41 | |||
Other, net | (5,225) | (5,516) | (4,578) | |||
Changes in assets and liabilities | 68,576 | (180,113) | (83,071) | |||
EBITDAX (non-GAAP) | $ 854,785 | $ 850,640 | $ 876,196 |
Non-GAAP Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the periods presented.
Three months ended March 31, 2019 | ||||||
In thousands | Crude oil | Natural gas | Total | |||
Crude oil and natural gas sales (GAAP) | $911,118 | $198,466 | $1,109,584 | |||
Less: Transportation expenses | (41,648) | (7,491) | (49,139) | |||
Net crude oil and natural gas sales (non-GAAP) | $869,470 | $190,975 | $1,060,445 | |||
Sales volumes (MBbl/MMcf/MBoe) | 17,373 | 74,690 | 29,821 | |||
Net sales price (non-GAAP) | $50.05 | $2.56 | $35.56 | |||
Three months ended December 31, 2018 | ||||||
In thousands | Crude oil | Natural gas | Total | |||
Crude oil and natural gas sales (GAAP) | $900,872 | $253,232 | $1,154,104 | |||
Less: Transportation expenses | (42,373) | (6,655) | (49,028) | |||
Net crude oil and natural gas sales (non-GAAP) | $858,499 | $246,577 | $1,105,076 | |||
Sales volumes (MBbl/MMcf/MBoe) | 17,149 | 75,661 | 29,759 | |||
Net sales price (non-GAAP) | $50.06 | $3.26 | $37.13 | |||
Three months ended March 31, 2018 | ||||||
In thousands | Crude oil | Natural gas | Total | |||
Crude oil and natural gas sales (GAAP) | $906,281 | $207,571 | $1,113,852 | |||
Less: Transportation expenses | (40,386) | (8,911) | (49,297) | |||
Net crude oil and natural gas sales (non-GAAP) | $865,895 | $198,660 | $1,064,555 | |||
Sales volumes (MBbl/MMcf/MBoe) | 14,682 | 66,730 | 25,804 | |||
Net sales price (non-GAAP) | $58.98 | $2.98 | $41.26 |
Non-GAAP Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
1Q | 4Q | 1Q | ||||
2019 | 2018 | 2018 | ||||
Total G&A per Boe (GAAP) | $1.60 | $1.65 | $1.67 | |||
Less: Non-cash equity compensation per Boe | (0.41) | (0.47) | (0.42) | |||
Cash G&A per Boe (non-GAAP) | $1.19 | $1.18 | $1.25 |
Continental Resources, Inc. | ||
2019 Guidance | ||
As of April 29, 2019 | ||
2019 | ||
Full-year average oil production | 190,000 to 200,000 Bo per day | |
Full-year average natural gas production | 790,000 to 810,000 Mcf per day | |
Capital expenditures budget | $2.6 billion | |
Operating Expenses: | ||
Production expense per Boe | $3.75 to $4.25 | |
Production tax (% of net oil & gas revenue) | 8.0% to 8.3% | |
Cash G&A expense per Boe(1) | $1.25 to $1.45 | |
Non-cash equity compensation per Boe | $0.45 to $0.55 | |
DD&A per Boe | $15.00 to $17.00 | |
Average Price Differentials: | ||
NYMEX WTI crude oil (per barrel of oil) | ($4.50) to ($5.50) | |
Henry Hub natural gas (per Mcf) | $0.00 to ($0.50) |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.00 per Boe. |
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SOURCE Continental Resources
OKLAHOMA CITY, March 28, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) plans to announce first quarter 2019 results on Monday, April 29, 2019 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss first quarter 2019 results on Tuesday, April 30, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, April 30, 2019 |
Dial-in: | 844-309-6572 |
Intl. dial-in: | 484-747-6921 |
Conference ID: | 4290299 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 855-859-2056 or 404-537-3406 |
Intl. replay: | 800-585-8367 |
Conference ID: | 4290299 |
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The Company plans to publish a first quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on April 30, 2019.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Investor Relations Analyst | |
405-774-5878 | |
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SOURCE Continental Resources
OKLAHOMA CITY, Feb. 18, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced full-year 2018 and fourth quarter 2018 operating and financial results.
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The Company reported full-year 2018 net income of $988.3 million, or $2.64 per diluted share. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." Typically excluded items in aggregate represented $77.9 million, or $0.20 per diluted share. Adjusted net income for full-year 2018 was $1.07 billion, or $2.84 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2018 was $3.46 billion and EBITDAX was $3.62 billion (non-GAAP).
The Company reported net income of $197.7 million, or $0.53 per diluted share, for the quarter ended December 31, 2018. In fourth quarter 2018, typically excluded items in aggregate represented $3.9 million, or $0.01 per diluted share, of Continental's reported net income. Adjusted net income for fourth quarter 2018 was $201.7 million, or $0.54 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2018 was $955.3 million and EBITDAX was $850.6 million (non-GAAP).
Adjusted net income, adjusted net income per share, free cash flow, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release. Also presented at the end of this press release is the Company's calculation of return on capital employed for 2018.
"2018 was a breakout year of performance for Continental with significant cash flow generation and debt reduction, as well as corporate returns that compare favorably against our peers and are competitive with other industries," said Harold Hamm, Chairman and Chief Executive Officer. "In 2019, we will continue to deliver strong corporate returns coupled with growth that can adjust to various market conditions."
Production Update: 4Q18 Oil Production up 14% over 3Q18
Full-year 2018 production increased 23% over full-year 2017, averaging 298,190 Boe per day. 2018 oil production increased 21% over 2017, averaging 168,177 barrels of oil (Bo) per day. 2018 natural gas production averaged 780.1 million cubic feet (MMcf) per day.
Fourth quarter 2018 production increased 9% over third quarter 2018 and 13% over fourth quarter 2017, averaging 324,001 Boe per day. Fourth quarter 2018 oil production increased 14% over third quarter 2018 and 11% over fourth quarter 2017, averaging 186,934 Bo per day. Fourth quarter 2018 natural gas production averaged 822.4 MMcf per day.
The following table provides the Company's average daily production by region for the periods presented.
4Q | 3Q | 4Q | FY | FY | ||||||
Boe per day | 2018 | 2018 | 2017 | 2018 | 2017 | |||||
North Region: | ||||||||||
North Dakota Bakken | 177,358 | 161,008 | 158,640 | 161,231 | 125,577 | |||||
Montana Bakken | 6,478 | 6,635 | 6,958 | 6,569 | 7,415 | |||||
Other | 9,077 | 9,015 | 9,965 | 9,125 | 10,182 | |||||
South Region: | ||||||||||
SCOOP | 67,244 | 63,270 | 62,242 | 64,339 | 60,693 | |||||
STACK | 62,947 | 56,129 | 47,914 | 56,055 | 36,220 | |||||
Other(1) | 897 | 847 | 1,266 | 871 | 2,550 | |||||
Total | 324,001 | 296,904 | 286,985 | 298,190 | 242,637 |
(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017. |
Bakken: 183,836 Boepd Average Daily 4Q18 Production; up 10% over 3Q18
The Company's full-year 2018 Bakken production increased 26% over 2017, averaging 167,800 Boe per day. The Company's fourth quarter 2018 Bakken production increased 10% over third quarter 2018 and 11% over fourth quarter 2017, averaging 183,836 Boe per day. During the quarter, the Company completed 52 gross (34 net) operated wells with first production flowing at an average initial 24-hour rate per well of 2,800 Boe per day.
"Continental has entered a new era of optimized full field development in the Bakken where technology and operational efficiencies have uplifted performance across the play," said Jack Stark, President. "As we look to 2019 and beyond, the Bakken will continue to underpin Continental's sustainable, value-driven and oil-weighted growth."
STACK: Another Over-Pressured Condensate Unit Outperforms Parent Type Curve
The Company's fourth quarter 2018 STACK production increased 12% over third quarter 2018 and 31% over fourth quarter 2017, averaging 62,947 Boe per day. During the quarter, the Company completed 19 gross (9 net) operated wells with first production flowing at an average initial 24-hour rate per well of 3,645 Boe per day.
The Company recently completed another outstanding Meramec unit in the over-pressured condensate window of STACK. The Boden unit flowed at an impressive combined initial 24-hour rate of 14,071 Boe per day, averaging 1,197 Bo per day per well and 20,961 Mcf per day per well.
"Recent results from the Boden unit further validate Continental's optimized density development and the high quality of the over-pressured Meramec that underlies our acreage position in STACK," said Gary Gould, Senior Vice President of Production & Resource Development.
SCOOP: SpringBoard on Pace to Add 10% to CLR Net Oil Production (3Q18-3Q19)
The Company's fourth quarter 2018 SCOOP production increased 6% over third quarter 2018 and 8% over fourth quarter 2017, averaging 67,244 Boe per day. The Company completed 17 gross (14 net) operated wells with first production in fourth quarter 2018. The Company's fourth quarter 2018 SCOOP oil production increased 47% over fourth quarter 2017, reflecting the decision made in early 2018 to shift to the Company's oil-weighted assets.
As previously announced in the Company's Project SpringBoard conference call, Project SpringBoard is expected to add 10%, or 16,500 barrels of oil per day, to the Company's total net oil production from third quarter 2018 to third quarter 2019. In fourth quarter 2018, Project SpringBoard production growth was on pace, producing an average 5,260 barrels of oil per day. The Company currently has 45 gross operated wells waiting on completion in Project SpringBoard with 18 gross operated wells in the Springer reservoir and 27 gross operated wells in the Woodford and Sycamore reservoirs. Approximately 12 rigs will be focused on Project SpringBoard in 2019, with approximately 7 rigs targeting the Springer and approximately 5 rigs targeting the Woodford and Sycamore.
Financial Update
"Continental's 2018 performance signals a structural transition to free cash flow generation through low cost operations and development," said John Hart, Chief Financial Officer. "Over the next five years, we are targeting free cash flow generation, continued debt reduction and an average 12.5% compound annual production growth rate to drive strong corporate returns and continued shareholder value."
As of December 31, 2018, the Company's balance sheet included approximately $282.7 million in cash and cash equivalents, $5.77 billion in total debt and $5.49 billion in net debt (non-GAAP). The Company anticipates further reducing net debt to $5 billion late in 2019.
For full-year 2018, the Company's average net sales prices excluding the effects of derivative positions were $59.19 per barrel of oil and $3.01 per Mcf of gas, or $41.25 per Boe. The Company remains unhedged on oil. Production expense per Boe was $3.59 for full-year 2018, a record annual low for the Company and well within annual guidance of $3.50 to $3.75.
Non-acquisition capital expenditures for full-year 2018 totaled approximately $2.8 billion, including $2.4 billion in exploration and development drilling and completion, $276.4 million in leasehold and minerals, and $198.8 million in workovers, recompletions and other.
In fourth quarter 2018, the Company's average net sales prices excluding the effects of derivative positions were $50.06 per barrel of oil and $3.26 per Mcf of gas, or $37.13 per Boe. Production expense per Boe was $3.50 for fourth quarter 2018.
Non-acquisition capital expenditures for fourth quarter 2018 totaled approximately $742.6 million, including $611.0 million in exploration and development drilling and completion, $59.0 million in leasehold and minerals, and $72.6 million in workovers, recompletions and other.
The Company's 2019 guidance remains as announced on February 13, 2019 and can be found at the conclusion of this press release.
CLR's Five Year Vision Targets
Over the next five years, the Company is targeting an average 12.5% compound annual production growth rate from existing inventory. The Company is also targeting an average annual free cash flow of $500 million per year at $60 per barrel WTI. Individual years may vary above or below these targets depending on the timing of future projects.
In addition to cash flow generation, the Company expects ROCE to remain strong over the next five years, competing against other energy companies as well as other industries. The Company is targeting average annual ROCE of approximately 14.5% per year over the five years at $60 per barrel WTI.
The Company expects capital allocation between its North and South assets to be reasonably consistent with the historical norm of approximately 50% to 60% in the North and approximately 40% to 50% in the South.
The Company's operating expenses on a per Boe basis are expected to remain relatively consistent or improve. Additionally, the Company expects oil and gas differentials to improve with continued infrastructure directed toward coastal markets, which will allow the Company to benefit from access to both premium domestic and global markets.
The Company's five year vision is underpinned by the depth and quality of current inventory. The Company estimates less than 30% of current inventory is to be developed under this five year vision. The five year inventory is projected to deliver a 60% blended average rate of return (ROR) at $60 per barrel WTI.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended December 31, | Year ended December 31, | ||||||
2018 | 2017 | 2018 | 2017 | ||||
Average daily production: | |||||||
Crude oil (Bbl per day) | 186,934 | 168,066 | 168,177 | 138,455 | |||
Natural gas (Mcf per day) | 822,402 | 713,518 | 780,083 | 625,093 | |||
Crude oil equivalents (Boe per day) | 324,001 | 286,985 | 298,190 | 242,637 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||||
Crude oil ($/Bbl) | $50.06 | $51.16 | $59.19 | $45.70 | |||
Natural gas ($/Mcf) | $3.26 | $3.30 | $3.01 | $2.93 | |||
Crude oil equivalents ($/Boe) | $37.13 | $38.27 | $41.25 | $33.65 | |||
Production expenses ($/Boe) | $3.50 | $3.17 | $3.59 | $3.66 | |||
Production taxes (% of net crude oil and gas sales) | 8.2% | 7.3% | 7.9% | 7.0% | |||
DD&A ($/Boe) | $16.41 | $17.93 | $17.09 | $18.89 | |||
Total general and administrative expenses ($/Boe) (2) | $1.65 | $2.30 | $1.69 | $2.16 | |||
Net income attributable to Continental Resources (in thousands) (3) | $197,738 | $841,914 | $988,317 | $789,447 | |||
Diluted net income per share attributable to Continental Resources | $0.53 | $2.25 | $2.64 | $2.11 | |||
Adjusted net income (non-GAAP) (in thousands) (1) | $201,686 | $153,660 | $1,066,237 | $190,803 | |||
Adjusted diluted net income per share (non-GAAP) (1) | $0.54 | $0.41 | $2.84 | $0.51 | |||
Net cash provided by operating activities (in thousands) | $955,267 | $731,125 | $3,456,008 | $2,079,106 | |||
EBITDAX (non-GAAP) (in thousands) (1) | $850,640 | $837,887 | $3,623,373 | $2,363,617 |
(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided at the end of this press release. | |||||||||||||||
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.18, $1.80, $1.25, and $1.64 for 4Q 2018, 4Q 2017, FY 2018 and FY 2017, respectively. Non-cash equity compensation expense per Boe was $0.47, $0.50, $0.44, and $0.52 for 4Q 2018, 4Q 2017, FY 2018 and FY 2017, respectively. | |||||||||||||||
(3) In December 2017, the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate, which resulted in a one-time increase in net income of approximately $713.7 million ($1.91 per diluted share) for the three and twelve months ended December 31, 2017. |
Fourth Quarter Earnings Conference Call
Continental plans to host a conference call to discuss fourth quarter and full-year 2018 results on Tuesday, February 19, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, February 19, 2019 |
Dial-in: | 844-309-6572 |
Intl. dial-in: | 484-747-6921 |
Conference ID: | 5856777 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 855-859-2056 or 404-537-3406 |
Intl. replay: | 800-585-8367 |
Conference ID: | 5856777 |
Continental plans to publish a fourth quarter and full-year 2018 summary presentation to its website at www.CLR.com prior to the start of its conference call on February 19, 2019.
Upcoming Conferences
Members of Continental's management team expect to participate in the following investment conference:
March 25-26, 2019 Scotia Howard Weil 47th Annual Energy Conference – New Orleans, LA
Presentation materials for the conference mentioned above will be available on the Company's web site at www.CLR.com prior to the start of the Company's presentation at such conference.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "target," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, and once filed, for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: | |
Rory Sabino | Kristin Thomas | |
Vice President, Investor Relations | Senior Vice President, Public Relations | |
405-234-9620 | 405-234-9480 | |
Lucy Guttenberger | ||
Senior Investor Relations Associate | ||
405-774-5878 | ||
Continental Resources, Inc. and Subsidiaries | |||||||
Consolidated Statements of Income | |||||||
Three months ended December 31, | Year ended December 31, | ||||||
2018 | 2017 | 2018 | 2017 | ||||
Revenues: | In thousands, except per share data | ||||||
Crude oil and natural gas sales | $ 1,154,104 | $ 1,017,750 | $ 4,678,722 | $ 2,982,966 | |||
Gain (loss) on natural gas derivatives, net | (19,394) | 8,165 | (23,930) | 91,647 | |||
Crude oil and natural gas service operations | 14,584 | 21,257 | 54,794 | 46,215 | |||
Total revenues | 1,149,294 | 1,047,172 | 4,709,586 | 3,120,828 | |||
Operating costs and expenses: | |||||||
Production expenses | 104,258 | 84,371 | 390,423 | 324,214 | |||
Production taxes | 90,393 | 73,816 | 353,140 | 208,278 | |||
Transportation expenses | 49,028 | - | 191,587 | - | |||
Exploration expenses | 3,295 | 2,802 | 7,642 | 12,393 | |||
Crude oil and natural gas service operations | 4,205 | 6,216 | 21,639 | 16,880 | |||
Depreciation, depletion, amortization and accretion | 488,416 | 476,732 | 1,859,327 | 1,674,901 | |||
Property impairments | 38,494 | 27,552 | 125,210 | 237,370 | |||
General and administrative expenses | 49,201 | 61,294 | 183,569 | 191,706 | |||
Litigation settlement | - | 59,600 | - | 59,600 | |||
Net gain on sale of assets and other | (8,410) | (54,679) | (16,671) | (53,915) | |||
Total operating costs and expenses | 818,880 | 737,704 | 3,115,866 | 2,671,427 | |||
Income from operations | 330,414 | 309,468 | 1,593,720 | 449,401 | |||
Other income (expense): | |||||||
Interest expense | (69,441) | (75,823) | (293,032) | (294,495) | |||
Loss on extinguishment of debt | - | (554) | (7,133) | (554) | |||
Other | 1,016 | 506 | 3,247 | 1,715 | |||
(68,425) | (75,871) | (296,918) | (293,334) | ||||
Income before income taxes | 261,989 | 233,597 | 1,296,802 | 156,067 | |||
(Provision) benefit for income taxes | (62,868) | 608,317 | (307,102) | 633,380 | |||
Net income | 199,121 | 841,914 | 989,700 | 789,447 | |||
Net income attributable to noncontrolling interests | 1,383 | - | 1,383 | - | |||
Net income attributable to Continental Resources | $ 197,738 | $ 841,914 | $ 988,317 | $ 789,447 | |||
Net income per share attributable to Continental Resources: | |||||||
Basic | $ 0.53 | $ 2.27 | $ 2.66 | $ 2.13 | |||
Diluted | $ 0.53 | $ 2.25 | $ 2.64 | $ 2.11 |
Continental Resources, Inc. and Subsidiaries | |||||
Consolidated Balance Sheets | |||||
December 31, 2018 | December 31, 2017 | ||||
Assets | In thousands | ||||
Cash and cash equivalents | $ | 282,749 | $ | 43,902 | |
Other current assets | 1,129,612 | 1,207,823 | |||
Net property and equipment (1) | 13,869,800 | 12,933,789 | |||
Other noncurrent assets | 15,786 | 14,137 | |||
Total assets | $ | 15,297,947 | $ | 14,199,651 | |
Liabilities and equity | |||||
Current liabilities | $ | 1,387,509 | $ | 1,330,242 | |
Long-term debt, net of current portion | 5,765,989 | 6,351,405 | |||
Other noncurrent liabilities | 1,722,588 | 1,386,801 | |||
Equity attributable to Continental Resources | 6,145,133 | 5,131,203 | |||
Equity attributable to noncontrolling interests | 276,728 | - | |||
Total liabilities and equity | $ | 15,297,947 | $ | 14,199,651 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $10.81 billion and $9.08 billion as of December 31, 2018 and December 31, 2017, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||||||
Consolidated Statements of Cash Flows | ||||||||||||
Three months ended December 31, | Year ended December 31, | |||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||
Net income | $ | 199,121 | $ | 841,914 | $ | 989,700 | $ | 789,447 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Non-cash expenses | 576,033 | (70,395) | 2,340,600 | 1,288,244 | ||||||||
Changes in assets and liabilities | 180,113 | (40,394) | 125,708 | 1,415 | ||||||||
Net cash provided by operating activities | 955,267 | 731,125 | 3,456,008 | 2,079,106 | ||||||||
Net cash used in investing activities | (756,689) | (434,591) | (2,860,172) | (1,808,845) | ||||||||
Net cash provided by (used in) financing activities | 71,319 | (263,395) | (356,934) | (243,034) | ||||||||
Effect of exchange rate changes on cash | (44) | (2) | (55) | 32 | ||||||||
Net change in cash and cash equivalents | 269,853 | 33,137 | 238,847 | 27,259 | ||||||||
Cash and cash equivalents at beginning of period | 12,896 | 10,765 | 43,902 | 16,643 | ||||||||
Cash and cash equivalents at end of period | $ | 282,749 | $ | 43,902 | $ | 282,749 | $ | 43,902 |
Non-GAAP adjusted net income and adjusted net income per share attributable to Continental
Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, losses on certain litigation settlements, gains and losses on asset sales, losses on extinguishment of debt, and the impact of U.S. tax reform legislation as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.
Three months ended December 31, | ||||||||||||||
2018 | 2017 | |||||||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||||||||
Net income attributable to Continental Resources (GAAP) | $ 197,738 | $ 0.53 | $841,914 | $ 2.25 | ||||||||||
Adjustments: | ||||||||||||||
Non-cash (gain) loss on derivatives | (25,022) | 7,450 | ||||||||||||
Property impairments | 38,494 | 27,552 | ||||||||||||
Litigation settlement | - | 59,600 | ||||||||||||
Gain on sale of assets | (8,410) | (54,420) | ||||||||||||
Loss on extinguishment of debt | - | 554 | ||||||||||||
Total tax effect of adjustments (1) | (1,114) | (15,335) | ||||||||||||
Tax benefit from US tax reform legislation | - | (713,655) | ||||||||||||
Total adjustments, net of tax | 3,948 | 0.01 | (688,254) | (1.84) | ||||||||||
Adjusted net income (non-GAAP) | $ 201,686 | $ 0.54 | $153,660 | $ 0.41 | ||||||||||
Weighted average diluted shares outstanding | 374,525 | 373,764 | ||||||||||||
Adjusted diluted net income per share (non-GAAP) | $ 0.54 | $0.41 | ||||||||||||
Year ended December 31, | ||||||||||||||
2018 | 2017 | |||||||||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||||||||
Net income attributable to Continental Resources (GAAP) | $ 988,317 | $ 2.64 | $789,447 | $ 2.11 | ||||||||||
Adjustments: | ||||||||||||||
Non-cash gain on derivatives | (13,009) | (58,031) | ||||||||||||
Property impairments | 125,210 | 237,370 | ||||||||||||
Litigation settlement | - | 59,600 | ||||||||||||
Gain on sale of assets | (16,671) | (55,124) | ||||||||||||
Loss on extinguishment of debt | 7,133 | 554 | ||||||||||||
Total tax effect of adjustments (1) | (24,743) | (69,358) | ||||||||||||
Tax benefit from US tax reform legislation | - | (713,655) | ||||||||||||
Total adjustments, net of tax | 77,920 | 0.20 | (598,644) | (1.60) | ||||||||||
Adjusted net income (non-GAAP) | $1,066,237 | $ 2.84 | $190,803 | $ 0.51 | ||||||||||
Weighted average diluted shares outstanding | 374,838 | 373,768 | ||||||||||||
Adjusted diluted net income per share (non-GAAP) | $ 2.84 | $ 0.51 |
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2018 and 38% in effect for 2017 to the pre-tax amount of adjustments associated with our operations in the United States other than the 2017 tax benefit adjustment related to US tax reform legislation. |
Non-GAAP Net Debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At December 31, 2018, the Company's total debt was $5.77 billion and its net debt amounted to $5.49 billion, representing total debt of $5.77 billion less cash and cash equivalents of $282.7 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Non-GAAP EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
Three months ended December 31, | Year ended December 31, | |||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||
Net income | $ | 199,121 | $ | 841,914 | $ | 989,700 | $ | 789,447 | ||||
Interest expense | 69,441 | 75,823 | 293,032 | 294,495 | ||||||||
Provision (benefit) for income taxes | 62,868 | (608,317) | 307,102 | (633,380) | ||||||||
Depreciation, depletion, amortization and accretion | 488,416 | 476,732 | 1,859,327 | 1,674,901 | ||||||||
Property impairments | 38,494 | 27,552 | 125,210 | 237,370 | ||||||||
Exploration expenses | 3,295 | 2,802 | 7,642 | 12,393 | ||||||||
Impact from derivative instruments: | ||||||||||||
Total (gain) loss on derivatives, net | 19,394 | (8,417) | 23,930 | (90,432) | ||||||||
Total cash (paid) received on derivatives, net | (44,416) | 15,867 | (36,939) | 32,401 | ||||||||
Non-cash (gain) loss on derivatives, net | (25,022) | 7,450 | (13,009) | (58,031) | ||||||||
Non-cash equity compensation | 14,027 | 13,377 | 47,236 | 45,868 | ||||||||
Loss on extinguishment of debt | - | 554 | 7,133 | 554 | ||||||||
EBITDAX (non-GAAP) | $ | 850,640 | $ | 837,887 | $ | 3,623,373 | $ | 2,363,617 |
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended December 31, | Year ended December 31, | |||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||
Net cash provided by operating activities | $ | 955,267 | $ | 731,125 | $ | 3,456,008 | $ | 2,079,106 | ||||
Current income tax provision (benefit) | 2 | (7,781) | (7,776) | (7,781) | ||||||||
Interest expense | 69,441 | 75,823 | 293,032 | 294,495 | ||||||||
Exploration expenses, excluding dry hole costs | 3,149 | 2,783 | 7,495 | 12,217 | ||||||||
Litigation settlement | - | (59,600) | - | (59,600) | ||||||||
Gain on sale of assets, net | 8,410 | 54,420 | 16,671 | 55,124 | ||||||||
Other, net | (5,516) | 723 | (16,349) | (8,529) | ||||||||
Changes in assets and liabilities | (180,113) | 40,394 | (125,708) | (1,415) | ||||||||
EBITDAX (non-GAAP) | $ | 850,640 | $ | 837,887 | $ | 3,623,373 | $ | 2,363,617 |
Non-GAAP Free Cash Flow
Our presentation of projected free cash flow is a non-GAAP measure. We define projected free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our new relationship formed with Franco-Nevada in 2018 to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Management believes that this measure is useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. From time to time the Company provides forward-looking free cash flow estimates or targets; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Non-GAAP Net Sales Prices
On January 1, 2018, we adopted Accounting Standards Update 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which impacted the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach on January 1, 2018 whereby changes have been applied only to the most current period presented and prior period results have not been adjusted to conform to current presentation.
Under the new rules, revenues and transportation expenses associated with production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from our operated properties differs from the net presentation of revenues from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results, to achieve comparability between operated and non-operated revenues, and to achieve comparability with prior period metrics for analysis purposes, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three and twelve months ended December 31, 2018. Information is also presented for the three and twelve months ended December 31, 2017 for comparative purposes.
Three months ended December 31, 2018 | Three months ended December 31, 2017 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $900,872 | $253,232 | $1,154,104 | $800,871 | $216,879 | $1,017,750 | ||||||
Less: Transportation expenses | (42,373) | (6,655) | (49,028) | — | — | — | ||||||
Net crude oil and natural gas sales (non-GAAP for 2018) | $858,499 | $246,577 | $1,105,076 | $800,871 | $216,879 | $1,017,750 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 17,149 | 75,661 | 29,759 | 15,653 | 65,644 | 26,594 | ||||||
Net sales price (non-GAAP for 2018) | $50.06 | $3.26 | $37.13 | $51.16 | $3.30 | $38.27 | ||||||
Year ended December 31, 2018 | Year ended December 31, 2017 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $3,792,594 | $886,128 | $4,678,722 | $2,313,862 | $669,104 | $2,982,966 | ||||||
Less: Transportation expenses | (162,312) | (29,275) | (191,587) | — | — | — | ||||||
Net crude oil and natural gas sales (non-GAAP for 2018) | $3,630,282 | $856,853 | $4,487,135 | $2,313,862 | $669,104 | $2,982,966 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 61,332 | 284,730 | 108,787 | 50,628 | 228,159 | 88,655 | ||||||
Net sales price (non-GAAP for 2018) | $59.19 | $3.01 | $41.25 | $45.70 | $2.93 | $33.65 |
Non-GAAP Cash General and Administrative Expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended December 31, | Year ended December 31, | |||||||
2018 | 2017 | 2018 | 2017 | |||||
Total G&A per Boe (GAAP) | $1.65 | $2.30 | $1.69 | $2.16 | ||||
Less: Non-cash equity compensation per Boe | (0.47) | (0.50) | (0.44) | (0.52) | ||||
Cash G&A per Boe (non-GAAP) | $1.18 | $1.80 | $1.25 | $1.64 |
Calculation of Return on Capital Employed (ROCE)
The following table shows the calculation of ROCE for 2018.
In thousands | 2018 | |
Net income attributable to Continental Resources | $ 988,317 | |
Impact from derivative instruments: | ||
Total (gain) loss on derivatives, net | 23,930 | |
Total cash received (paid), net | (36,939) | |
Non-cash (gain) loss on derivatives, net | (13,009) | |
Provision for income taxes | 307,102 | |
Non-cash equity compensation | 47,236 | |
Interest expense | 293,032 | |
Loss on extinguishment of debt | 7,133 | |
Adjusted EBIT | $ 1,629,811 | |
Equity attributable to Continental Resources - beginning of 2018 | $ 5,131,203 | |
Total debt - beginning of 2018 | 6,353,691 | |
Capital employed - beginning of 2018 | 11,484,894 | |
Equity attributable to Continental Resources - end of 2018 | 6,145,133 | |
Total debt - end of 2018 | 5,768,349 | |
Capital employed - end of 2018 | 11,913,482 | |
Average capital employed | $11,699,188 | |
ROCE | 13.9% |
Continental Resources, Inc. | ||
2019 Guidance | ||
As of February 18, 2019 | ||
2019 | ||
Full-year average oil production | 190,000 to 200,000 Bo per day | |
Full-year average natural gas production | 790,000 to 810,000 Mcf per day | |
Capital expenditures budget | $2.6 billion | |
Operating Expenses: | ||
Production expense per Boe | $3.75 to $4.25 | |
Production tax (% of net oil & gas revenue) | 8.0% to 8.3% | |
Cash G&A expense per Boe(1) | $1.25 to $1.45 | |
Non-cash equity compensation per Boe | $0.45 to $0.55 | |
DD&A per Boe | $15.00 to $17.00 | |
Average Price Differentials: | ||
NYMEX WTI crude oil (per barrel of oil) | ($4.50) to ($5.50) | |
Henry Hub natural gas (per Mcf) | $0.00 to ($0.50) |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.00 per Boe. |
View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-full-year-2018-and-4q18-results-300797501.html
SOURCE Continental Resources
OKLAHOMA CITY, Feb. 13, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced a 2019 capital expenditures budget of $2.6 billion, which is focused on both strong free cash flow generation and oil-weighted production growth. Annual crude oil production is projected to grow 13% to 19% and to range between 190,000 to 200,000 barrels of oil (Bo) per day. Annual crude oil volumetric growth is projected to be split approximately equally between the Company's North and South assets. Annual natural gas production is projected to grow 1% to 4% and to range between 790,000 to 810,000 thousand cubic feet (Mcf) per day.
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The 2019 capital budget is projected to generate approximately $3.0 billion of cash flow from operations and an estimated $500 to $600 million of free cash flow for full-year 2019 at $55 per barrel WTI and $3.00 per Mcf Henry Hub. This level of cash flow would enable the Company to reduce net debt (non-GAAP) to its $5 billion target. The Company anticipates achieving this debt reduction target late in 2019. The capital budget is projected to be cash neutral in the mid-$40's per barrel WTI price. A $5 change per barrel WTI is estimated to impact annual cash flow by $300 million to $325 million.
Free cash flow and net debt are non-GAAP measures. See "Non-GAAP Financial Measures" at the end of this press release for definitions and an explanation for how these measures relate to the most comparable U.S. GAAP financial measures.
There are currently no oil hedges in place, allowing the Company to fully participate in the upside of oil prices. Natural gas is hedged 110,000 MMBtus per day for first quarter 2019 at an average price of $4.48 and 577,000 MMBtus per day for April through December 2019 at an average price of $2.80.
Of the total $2.6 billion capital budget, the Company is allocating approximately $125 million to the previously announced mineral royalty agreement. With a carry structure in place, the Company will recoup $100 million during the year, effectively reducing the Company's share of total 2019 capital spend by $100 million. The Company expects to earn 50% of total revenue generated from this strategic royalty relationship in 2019.
The Company is allocating approximately $2.2 billion to drilling and completion (D&C) activities, of which approximately 50% is allocated to the Bakken and approximately 50% to Oklahoma. Capital allocation to the Bakken is lower than the prior year due to a lower rig count and the timing of drilling large pads later in the year, where completion spend is not expected to occur until 2020. The non-D&C capital is planned to be primarily focused on leasehold, mineral acquisitions, workovers and facilities.
In 2019, production expense is projected to be between $3.75 and $4.25 per Boe, reflecting a shift toward oil-weighted production growth. Total G&A is projected to be between $1.70 and $2.00 per Boe. In 2019, production tax is projected to be between 8.0% and 8.3% of net oil and gas revenue.
Oil differentials are projected to be in a range of ($4.50) to ($5.50) per Bo, and natural gas differentials are projected to be in a range of $0.00 to ($0.50) per Mcf in 2019. The Company has guided natural gas differentials wider than the prior year based on lower crude oil prices, which impact NGL realizations. The Company has also guided crude oil differentials wider than the prior year but expects improvement based on expanding pipeline infrastructure. The Company is realizing sequential monthly improvement in first quarter 2019.
"In 2019, Continental will deliver enhanced capital efficiency with greater oil-weighted production growth coupled with a lower capital spend. The high quality of our assets and operations will drive sustainable free cash flow generation, debt reduction and industry-leading returns," said Harold Hamm, Chairman and Chief Executive Officer.
2019 Operating Plan
The Company plans to operate an average of 25 drilling rigs during 2019, down from 31 rigs at year-end 2018 and 1 more rig than the 2018 average of 24 rigs. The Company expects to complete approximately 307 gross (207 net) operated wells with first production in 2019 and average 9 completion crews.
In the Bakken, the Company plans to operate an average of 6 drilling rigs during 2019, slightly lower than the 2018 average. The Company expects to complete approximately 166 gross (107 net) operated wells in the Bakken with first production in 2019 and average 4 completion crews. At year-end 2019, the Company expects to have a normal working backlog of approximately 115 gross operated Bakken wells in progress in various stages of completion, of which 45 gross wells are projected to be completed but waiting on first sales. This compares to 137 gross operated Bakken wells in progress at year-end 2018.
In Oklahoma, the Company plans to operate an average of 19 drilling rigs during 2019, up 1 rig from the 2018 average, with approximately 12 rigs focused on Project SpringBoard. The Company expects to complete approximately 141 gross (100 net) operated wells in Oklahoma with first production in 2019 and average 5 completion crews.
2018 and 4Q18 Production
Full-year 2018 production averaged 298,190 Boe per day, up 23% over full-year 2017. Total 2018 production included 168,177 barrels of oil per day, up 21% over full-year 2017. Fourth quarter 2018 production averaged 324,001 Boe per day, up 9% from third quarter 2018. Total production for fourth quarter included 186,934 barrels of oil per day, up 14% over third quarter 2018.
As a reminder, the entire fourth quarter and full-year 2018 results will be announced on Monday, February 18, 2019 following the usual time for the close of trading on the New York Stock Exchange. The Company will host a conference call on Tuesday, February 19, 2019 at 12:00 p.m. ET (11:00 a.m. CT). For more information, please refer to the previous press release announcing key upcoming events, dated January 23, 2019, or visit www.CLR.com.
YE 2018 Proved Reserves: Standardized Measure and PV-10 (non-GAAP) up 50% and 58%, respectively, over YE 2017
The Company announced proved reserves of 1.52 billion Boe at December 31, 2018, a 14% increase compared with year-end 2017 proved reserves. The 2018 average SEC oil price was $65.56 per barrel, and the 2018 average SEC natural gas price was $3.10 per MMBtu. Of the 14% increase, only 2% was associated with the increased year-over-year SEC commodity prices.
At December 31, 2018, the Company had a Standardized Measure of discounted future net cash flows of $15.7 billion. The Company's 2018 proved reserves had a PV-10 of $18.7 billion, up 58% year-over-year. PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial metric, because it does not include the effects of discounted income taxes on future net revenues of approximately $3.0 billion. See "Non-GAAP Financial Measures" at the end of this press release for further discussion of PV-10.
Year-end 2018 proved reserves were 50% crude oil, 85% operated by the Company, and approximately 44% were classified as proved developed producing (PDP).
The Bakken accounted for 798 MMBoe, or 52% of Continental's year-end 2018 proved reserves. SCOOP accounted for 459 MMBoe, or 30% of Continental's year-end 2018 proved reserves. STACK accounted for 230 MMBoe, or 15% of Continental's year-end 2018 proved reserves.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, and once filed, for the year ended December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Senior Investor Relations Associate | |
405-774-5878 | |
Non-GAAP Financial Measures
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures, excluding acquisitions, plus non-controlling interest capital contributions, less distributions to non-controlling interests. The inclusion of non-controlling interest capital contributions and distributions, which began in the fourth quarter of 2018, is related to our newly formed relationship with Franco-Nevada to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Net debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
PV-10
Our PV-10 value, a non-GAAP financial measure, is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, 2018, our PV-10 totaled approximately $18.7 billion. The standardized measure of our discounted future net cash flows was approximately $15.7 billion at December 31, 2018, representing a $3.0 billion difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties.
Continental Resources, Inc. 2019 Guidance As of February 13, 2019 | ||
2019 | ||
Full-year average oil production | 190,000 to 200,000 Bo per day | |
Full-year average natural gas production | 790,000 to 810,000 Mcf per day | |
Capital expenditures budget | $2.6 billion | |
Operating Expenses: | ||
Production expense per Boe | $3.75 to $4.25 | |
Production tax (% of net oil & gas revenue) | 8.0% to 8.3% | |
Cash G&A expense per Boe(1) | $1.25 to $1.45 | |
Non-cash equity compensation per Boe | $0.45 to $0.55 | |
DD&A per Boe | $15.00 to $17.00 | |
Average Price Differentials: | ||
NYMEX WTI crude oil (per barrel of oil) | ($4.50) to ($5.50) | |
Henry Hub natural gas (per Mcf) | $0.00 to ($0.50) | |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is a projected range of $1.70 to $2.00 per Boe. |
Continental Resources, Inc. 2019 Capital Expenditures | |||
The following table provides the breakout of budgeted capital expenditures: | |||
($ in Millions) | Bakken D&C | Oklahoma D&C | Leasehold, Facilities, Other(1) |
Capex | $1,063 | $1,102 | $435 |
1. Includes $125 million allocated to minerals royalty acquisitions, of which $100 million will be recouped from Franco-Nevada. |
Continental Resources, Inc. 2019 Operational Detail | ||||
The following table provides additional operational detail for wells expected to have first production in 2019: | ||||
Asset | Average Rigs | Gross Operated Wells | Net Operated Wells | Total Net Wells(1) |
Bakken | 6 | 166 | 107 | 148 |
Oklahoma | 19 | 141 | 100 | 109 |
Total | 25 | 307 | 207 | 257 |
1. Represents projected net operated and non-operated wells. |
_____________________________________
1 Total general and administrative (G&A) expense is comprised of cash G&A and non-cash equity compensation per Boe. Cash G&A is a non-GAAP measure. See "Non-GAAP Financial Measures" and the guidance table at the end of this press release for a definition and reconciliation of this measure to the most comparable U.S. GAAP financial measure. Cash G&A guidance is a projected range of $1.25 to $1.45 per Boe. Non-cash equity compensation per Boe guidance is a projected range of $0.45 to $0.55.
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-2018-and-4q18-production-year-end-2018-proved-reserves-and-2019-capital-budget-and-guidance-300795351.html
SOURCE Continental Resources
OKLAHOMA CITY, Jan. 23, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announces the following upcoming events.
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1. Project SpringBoard Conference Call on Tuesday, January 29, 2019 at 12:00 p.m. ET
The Company plans to host a conference call to discuss recent operational results from Project SpringBoard. The conference call is scheduled for Tuesday, January 29th at 12 p.m. ET (11 a.m. CT). Following prepared remarks, the conference call will be open for Q&A. Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, January 29, 2019 |
Dial-in: | 844-309-6572 |
Intl. dial-in: | 484-747-6921 |
Conference ID: | 9786067 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 855-859-2056 or 404-537-3406 |
Intl. replay: | 800-585-8367 |
Conference ID: | 9786067 |
Continental plans to publish a SpringBoard presentation to its website at www.CLR.com prior to the start of its conference call on January 29, 2019.
2. 2019 Projected Capital Budget/Guidance Release on Wednesday, February 13, 2019 after Market Close
The Company plans to announce its 2019 budget and full-year guidance on Wednesday, February 13, 2019 following the close of trading on the New York Stock Exchange.
3. 4Q18 & Full-Year 2018 Earnings Release on Monday, February 18, 2019 after Market Close; Earnings Conference Call Scheduled for Tuesday, February 19, 2019 at 12:00 p.m. ET
The Company plans to announce fourth quarter and full-year 2018 results on Monday, February 18, 2019 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss fourth quarter and full-year 2018 results on Tuesday, February 19, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, February 19, 2019 |
Dial-in: | 844-309-6572 |
Intl. dial-in: | 484-747-6921 |
Conference ID: | 5856777 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 855-859-2056 or 404-537-3406 |
Intl. replay: | 800-585-8367 |
Conference ID: | 5856777 |
Continental plans to publish a fourth quarter and full-year 2018 summary presentation to its website at www.CLR.com prior to the start of its conference call on February 19, 2019.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Senior Investor Relations Associate | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-key-upcoming-events-300783219.html
SOURCE Continental Resources
OKLAHOMA CITY, Oct. 29, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced third quarter operating and financial results. The Company reported net income of $314.2 million, or $0.84 per diluted share, for the quarter ended September 30, 2018. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In third quarter 2018, these typically excluded items in aggregate represented $22.8 million, or $0.06 per diluted share, of Continental's reported net income. Adjusted net income for third quarter 2018 was $337.0 million, or $0.90 per diluted share.
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Net cash provided by operating activities for third quarter 2018 was $860.7 million. EBITDAX for third quarter 2018 was $1.0 billion. Definitions and reconciliations of adjusted net income, adjusted net income per share, free cash flow, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables at the conclusion of this press release.
The Company's third quarter 2018 crude oil differential was $3.72 per barrel below the NYMEX daily average for the period, an improvement of $1.26 per barrel compared to third quarter 2017 due to strong Gulf Coast pricing, strong seasonal demand and lower Cushing inventories. The realized wellhead natural gas price for third quarter 2018 was a premium of $0.22 per Mcf compared to the average NYMEX Henry Hub benchmark price.
"With up to 70 of our forecasted 2018 Bakken wells and up to 18 SpringBoard wells scheduled to be completed by year end, Continental anticipates a strong wave of oil-weighted production growth as we approach year end," said Harold Hamm, Chairman and Chief Executive Officer. "Thanks to the quality of our oil assets, the ingenuity of our teams, and the positive tailwind provided by our unhedged oil portfolio, Continental's strategic move to optimize capital-efficient, oil-weighted growth is enhancing shareholder value."
$215 Million in Proceeds Received in October from Minerals Venture Closing
On October 23, 2018, the Company closed its strategic minerals agreement with Franco-Nevada. The Company received approximately $215 million in net proceeds at closing, which offset previously incurred Capex for acquired minerals. Moving forward, the minerals relationship will capitalize on the Company's land and exploration expertise and will focus predominantly on acquiring minerals under the Company's drill plan. To grow the minerals portfolio, Franco-Nevada has committed up to $300 million over the next three years, while the Company has committed up to $75 million (or 20% of the total investment) over the next three years, subject to achieving agreed upon development thresholds. With a carry structure in place, the Company will earn 25-50% of total revenue from the minerals venture, based on achieving certain predetermined targets.
Production Update
Third quarter 2018 production totaled 27.3 million barrels of oil equivalent (Boe), or 296,904 Boe per day, up 22% from third quarter 2017. Total production for third quarter included 164,605 barrels of oil (Bo) per day, as well as 793.8 million cubic feet (MMcf) of natural gas per day. The following table provides the Company's average daily production by region for the periods presented.
3Q | 2Q | 3Q | YTD | YTD | ||||||
Boe per day | 2018 | 2018 | 2017 | 2018 | 2017 | |||||
North Region: | ||||||||||
North Dakota Bakken | 161,008 | 151,805 | 129,582 | 155,796 | 114,435 | |||||
Montana Bakken | 6,635 | 6,314 | 7,269 | 6,600 | 7,569 | |||||
Red River Units | 8,989 | 8,404 | 9,536 | 8,909 | 9,832 | |||||
Other | 26 | 258 | 449 | 232 | 422 | |||||
South Region: | ||||||||||
SCOOP | 63,270 | 64,786 | 57,283 | 63,360 | 60,171 | |||||
STACK | 56,129 | 51,722 | 35,619 | 53,733 | 32,280 | |||||
Arkoma(1) | 8 | 9 | 1,722 | 6 | 1,755 | |||||
Other | 839 | 761 | 1,328 | 856 | 1,228 | |||||
Total | 296,904 | 284,059 | 242,788 | 289,492 | 227,692 |
(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017. |
Bakken: 167,643 Boepd Average Daily 3Q18 Production; up 23% over 3Q17
The Company's Bakken production hit an all-time quarterly record, averaging 167,643 Boe per day in third quarter 2018, up 23% versus third quarter 2017. During the quarter, the Company completed 42 gross (26 net) operated wells flowing at an average initial 24-hour rate of 2,013 Boe per day. Two of the wells ranked as top ten 30-day rate Bakken wells for the Company, including the Wiley 8-25H (2,289 Boe per day) and Mountain Gap 3-10H (2,094 Boe per day). All Company top ten 30-day rate Bakken wells have been completed in the past twelve months.
The Company currently has 8 rigs drilling in the Bakken, up 2 rigs from last quarter to facilitate continued oil growth in 2019. In fourth quarter 2018, production is expected to ramp significantly with up to 70 wells forecasted to be completed by year end 2018.
"The performance and returns from the Bakken have been exceptional," said Jack Stark, President. "Our entire 2017 Bakken program, which included 133 operated wells, paid out by the end of third quarter 2018. Now that's capital efficiency."
STACK: 3 Meramec Units Flow at Combined Initial Rate of 74,260 Boepd (24-Hr. IP)
The Company's STACK production increased 58% to 56,129 Boe per day in third quarter 2018, compared to third quarter 2017. During the quarter, the Company completed 15 gross (7 net) operated wells with first production. The Company currently has 5 operated drilling rigs in STACK.
The Company recently completed three outstanding Meramec units in the over-pressured oil and condensate windows of STACK. All three units were developed with the equivalent of six, two-mile wells. In the oil window, the Jalou unit flowed at a combined initial 24-hour rate of 25,404 Boe per day, averaging 2,470 Bo per day per well and 10,587 Mcf per day per well. At an average 24-hour rate of 4,234 Boe per day, the Jalou wells set an industry record for fully developed units in the STACK over-pressured oil window. Additionally in the oil window, the Homsey unit flowed at a combined initial 24-hour rate of 21,127 Boe per day, averaging 2,071 Bo per day per well and 8,701 Mcf per day per well. In the condensate window, the Simba unit flowed at a combined initial 24-hour rate of 27,729 Boe per day, averaging 621 Bo per day per well and 24,001 Mcf per day per well.
"The outstanding results from these units confirm both our unit development model and the exceptional quality of our Meramec reservoirs, which are some of the thickest and most over-pressured in STACK," said Tony Barrett, Vice President, Exploration. "These results demonstrate the potential of our operated STACK inventory with up to 65 units remaining to develop in the oil and condensate windows."
The following table provides the average initial 24-hour rates per well for recent STACK units:
Unit | 2-Mi Equiv. Wells | Bopd per Well | Mcfpd per Well | Boepd per Well |
Jalou | 6 | 2,470 | 10,587 | 4,234 |
Homsey | 6 | 2,071 | 8,701 | 3,521 |
Simba | 6 | 621 | 24,001 | 4,622 |
SCOOP: Project SpringBoard Proceeding on Schedule with 14 Rigs Drilling
The Company's SCOOP production averaged 63,270 Boe per day in third quarter 2018, up 10% versus third quarter 2017. The Company's SCOOP crude oil production in third quarter 2018 increased 33% over third quarter 2017. The Company completed 9 gross (7 net) operated wells with first production in third quarter 2018. The Company currently has 16 operated drilling rigs in SCOOP, ramping up to 18 by year end.
Project SpringBoard is proceeding on schedule with 14 rigs drilling, 8 of which are targeting the Springer reservoir and 6 of which are targeting the Woodford and Sycamore reservoirs. In the Springer, the Company has finished drilling 17 of the 18 wells planned for row 1 and has begun drilling row 2. Of the 17 Springer wells drilled, 9 are flowing-back and 8 are in various stages of completions. In the Woodford and Sycamore, the Company has finished drilling 9 wells to date.
"Project SpringBoard is a massive oil project where we are concurrently developing three reservoirs," said Gary Gould, Senior Vice President of Production & Resource Development. "As expected, we are already realizing operational efficiencies that will translate to significant additional value for our shareholders."
Financial Update
"Continental's strong third quarter and early fourth quarter results reflect our strategic decision to focus operations on oil-weighted production growth," said John Hart, Chief Financial Officer. "Continental is poised to deliver a strong exit rate, increase our oil production growth and continue to use significant free cash flow to further reduce debt toward our long-term target of $5 billion or below."
As of September 30, 2018, the Company's balance sheet included approximately $13 million in cash and cash equivalents and $5.96 billion in total debt. On September 30, 2018, net debt (non-GAAP) was $5.94 billion. Net debt is projected to be between $5.4 and $5.6 billion at year end 2018, driven by strong cash flow. The Company's third quarter annualized net-debt-to-EBITDAX ratio was 1.49x and has now reached levels seen prior to the three-year commodity down cycle.
In third quarter 2018, the Company's average net sales price excluding the effects of derivative positions was $65.78 per barrel of oil and $3.12 per Mcf of gas, or $44.85 per Boe. The Company remains unhedged on oil. Production expense per Boe was $3.77 for third quarter 2018.
Non-acquisition capital expenditures for third quarter 2018 totaled approximately $790.8 million, including $633.5 million in exploration and development drilling, $105.5 million in leasehold, and $51.8 million in workovers, recompletions and other. Non-acquisition capital expenditures for third quarter were slightly higher than projected due to timing of completions that will see first production in fourth quarter 2018 or in 2019.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended September 30, | Nine months ended September 30, | ||||||
2018 | 2017 | 2018 | 2017 | ||||
Average daily production: | |||||||
Crude oil (Bbl per day) | 164,605 | 140,611 | 161,856 | 128,476 | |||
Natural gas (Mcf per day) | 793,793 | 613,060 | 765,821 | 595,294 | |||
Crude oil equivalents (Boe per day) | 296,904 | 242,788 | 289,492 | 227,692 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) | |||||||
Crude oil ($/Bbl) | $65.78 | $43.27 | $62.73 | $43.26 | |||
Natural gas ($/Mcf) | $3.12 | $2.74 | $2.92 | $2.78 | |||
Crude oil equivalents ($/Boe) | $44.85 | $31.86 | $42.80 | $31.67 | |||
Production expenses ($/Boe) | $3.77 | $3.82 | $3.62 | $3.86 | |||
Production taxes (% of net crude oil and gas sales) | 8.0% | 7.3% | 7.8% | 6.8% | |||
DD&A ($/Boe) | $17.15 | $19.00 | $17.35 | $19.31 | |||
Total general and administrative expenses ($/Boe) (2) | $1.61 | $1.99 | $1.70 | $2.10 | |||
Net income (loss) (in thousands) | $314,169 | $10,621 | $790,580 | ($52,467) | |||
Diluted net income (loss) per share | $0.84 | $0.03 | $2.11 | ($0.14) | |||
Adjusted net income (non-GAAP) (in thousands) (1) | $337,017 | $32,162 | $865,033 | $37,142 | |||
Adjusted diluted net income per share (non-GAAP) (1) | $0.90 | $0.09 | $2.31 | $0.10 | |||
Net cash provided by operating activities (in thousands) | $860,748 | $431,409 | $2,500,741 | $1,347,981 | |||
EBITDAX (non-GAAP) (in thousands) (1) | $999,882 | $563,767 | $2,772,733 | $1,525,730 |
(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.18, $1.45, $1.28, and $1.58 for 3Q 2018, 3Q 2017, YTD 2018 and YTD 2017, respectively. Non-cash equity compensation expense per Boe was $0.43, $0.54, $0.42, and $0.52 for 3Q 2018, 3Q 2017, YTD 2018 and YTD 2017, respectively. |
Third Quarter Earnings Conference Call
Continental plans to host a conference call to discuss third quarter results on Tuesday, October 30, 2018, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, October 30, 2018 |
Dial in: | 844-309-6572 |
Intl. dial in: | 484-747-6921 |
Pass code: | 3745129 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 855-859-2056 or 404-537-3406 |
Intl. replay: | 800-585-8367 |
Pass code: | 3745129 |
Continental plans to publish a third quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on October 30, 2018.
Upcoming Conferences
Members of Continental's management team expect to participate in the following investment conference:
November 14-15, 2018 Bank of America Global Energy Conference – Miami, Florida
Presentation materials for the conference mentioned above will be available on the Company's web site at www.CLR.com prior to the start of the Company's presentation at such conference.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Senior Investor Relations Associate | |
405-774-5878 | |
Continental Resources, Inc. and Subsidiaries | |||||||
Unaudited Condensed Consolidated Statements of Income (Loss) | |||||||
Three months ended September 30, | Nine months ended September 30, | ||||||
2018 | 2017 | 2018 | 2017 | ||||
Revenues: | In thousands, except per share data | ||||||
Crude oil and natural gas sales | $ 1,273,238 | $ 704,818 | $ 3,524,618 | $ 1,965,216 | |||
Gain (loss) on natural gas derivatives, net | (2,025) | 8,602 | (4,536) | 83,482 | |||
Crude oil and natural gas service operations | 10,938 | 13,323 | 40,210 | 24,959 | |||
Total revenues | 1,282,151 | 726,743 | 3,560,292 | 2,073,657 | |||
Operating costs and expenses: | |||||||
Production expenses | 103,032 | 84,514 | 286,165 | 239,842 | |||
Production taxes | 98,572 | 51,264 | 262,747 | 134,462 | |||
Transportation expenses | 46,008 | - | 142,559 | - | |||
Exploration expenses | 2,324 | 1,389 | 4,347 | 9,591 | |||
Crude oil and natural gas service operations | 5,163 | 3,349 | 17,434 | 10,664 | |||
Depreciation, depletion, amortization and accretion | 469,333 | 420,243 | 1,370,912 | 1,198,169 | |||
Property impairments | 23,770 | 35,130 | 86,715 | 209,819 | |||
General and administrative expenses | 44,151 | 44,006 | 134,368 | 130,413 | |||
Net (gain) loss on sale of assets and other | (1,510) | (4,905) | (8,261) | 764 | |||
Total operating costs and expenses | 790,843 | 634,990 | 2,296,986 | 1,933,724 | |||
Income from operations | 491,308 | 91,753 | 1,263,306 | 139,933 | |||
Other income (expense): | |||||||
Interest expense | (73,409) | (74,756) | (223,590) | (218,672) | |||
Loss on extinguishment of debt | (7,133) | - | (7,133) | - | |||
Other | 869 | 394 | 2,231 | 1,209 | |||
(79,673) | (74,362) | (228,492) | (217,463) | ||||
Income (loss) before income taxes | 411,635 | 17,391 | 1,034,814 | (77,530) | |||
(Provision) benefit for income taxes | (97,466) | (6,770) | (244,234) | 25,063 | |||
Net income (loss) | $ 314,169 | $ 10,621 | $ 790,580 | $ (52,467) | |||
Basic net income (loss) per share | $ 0.84 | $ 0.03 | $ 2.13 | $ (0.14) | |||
Diluted net income (loss) per share | $ 0.84 | $ 0.03 | $ 2.11 | $ (0.14) |
Continental Resources, Inc. and Subsidiaries | |||||
Unaudited Condensed Consolidated Balance Sheets | |||||
September 30, 2018 | December 31, 2017 | ||||
Assets | In thousands | ||||
Cash and cash equivalents | $ | 12,896 | $ | 43,902 | |
Other current assets | 1,356,241 | 1,207,823 | |||
Net property and equipment (1) | 13,644,538 | 12,933,789 | |||
Other noncurrent assets | 17,385 | 14,137 | |||
Total assets | $ | 15,031,060 | $ | 14,199,651 | |
Liabilities and shareholders' equity | |||||
Current liabilities | $ | 1,490,449 | $ | 1,330,242 | |
Long-term debt, net of current portion | 5,955,326 | 6,351,405 | |||
Other noncurrent liabilities | 1,646,475 | 1,386,801 | |||
Total shareholders' equity | 5,938,810 | 5,131,203 | |||
Total liabilities and shareholders' equity | $ | 15,031,060 | $ | 14,199,651 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $10.33 billion and $9.08 billion as of September 30, 2018 and December 31, 2017, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||
Net income (loss) | $ | 314,169 | $ | 10,621 | $ | 790,580 | $ | (52,467) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
Non-cash expenses | 619,284 | 480,718 | 1,764,566 | 1,358,639 | ||||||||
Changes in assets and liabilities | (72,705) | (59,930) | (54,405) | 41,809 | ||||||||
Net cash provided by operating activities | 860,748 | 431,409 | 2,500,741 | 1,347,981 | ||||||||
Net cash used in investing activities | (759,880) | (494,934) | (2,103,483) | (1,374,254) | ||||||||
Net cash (used in) provided by financing activities | (217,976) | 57,080 | (428,253) | 20,361 | ||||||||
Effect of exchange rate changes on cash | 15 | 20 | (11) | 34 | ||||||||
Net change in cash and cash equivalents | (117,093) | (6,425) | (31,006) | (5,878) | ||||||||
Cash and cash equivalents at beginning of period | 129,989 | 17,190 | 43,902 | 16,643 | ||||||||
Cash and cash equivalents at end of period | $ | 12,896 | $ | 10,765 | $ | 12,896 | $ | 10,765 |
Non-GAAP Financial Measures
Adjusted earnings (net income/loss) and adjusted earnings (net income/loss) per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as an alternative to, or more meaningful than, earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended September 30, | ||||||||
2018 | 2017 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income (GAAP) | $314,169 | $ 0.84 | $ 10,621 | $ 0.03 | ||||
Adjustments: | ||||||||
Non-cash loss on derivatives | 548 | 2,939 | ||||||
Property impairments | 23,770 | 35,130 | ||||||
Gain on sale of assets | (1,510) | (3,562) | ||||||
Loss on extinguishment of debt | 7,133 | - | ||||||
Total tax effect of adjustments (1) | (7,093) | (12,966) | ||||||
Total adjustments, net of tax | 22,848 | 0.06 | 21,541 | 0.06 | ||||
Adjusted net income (non-GAAP) | $337,017 | $ 0.90 | $ 32,162 | $0.09 | ||||
Weighted average diluted shares outstanding | 374,623 | 373,015 | ||||||
Adjusted diluted net income per share (non-GAAP) | $ 0.90 | $0.09 | ||||||
Nine months ended September 30, | ||||||||
2018 | 2017 | |||||||
In thousands, except per share data | $ | Diluted EPS | $ | Diluted EPS | ||||
Net income (loss) (GAAP) | $790,580 | $ 2.11 | $(52,467) | $ (0.14) | ||||
Adjustments: | ||||||||
Non-cash (gain) loss on derivatives | 12,013 | (65,481) | ||||||
Property impairments | 86,715 | 209,819 | ||||||
Gain on sale of assets | (8,261) | (703) | ||||||
Loss on extinguishment of debt | 7,133 | - | ||||||
Total tax effect of adjustments (1) | (23,147) | (54,026) | ||||||
Total adjustments, net of tax | 74,453 | 0.20 | 89,609 | 0.24 | ||||
Adjusted net income (non-GAAP) | $865,033 | $ 2.31 | $ 37,142 | $ 0.10 | ||||
Weighted average diluted shares outstanding | 374,762 | 373,588 | ||||||
Adjusted diluted net income per share (non-GAAP) | $ 2.31 | $ 0.10 |
(1) Computed by applying a combined federal and state statutory tax rate of 24% in effect for 2018 and 38% in effect for 2017 to the pre-tax amount of adjustments associated with our operations in the United States. |
Net debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At September 30, 2018, the Company's net debt amounted to $5.94 billion, representing total debt of $5.96 billion less cash and cash equivalents of $13 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||
Net income (loss) | $ | 314,169 | $ | 10,621 | $ | 790,580 | $ | (52,467) | ||||
Interest expense | 73,409 | 74,756 | 223,590 | 218,672 | ||||||||
Provision (benefit) for income taxes | 97,466 | 6,770 | 244,234 | (25,063) | ||||||||
Depreciation, depletion, amortization and accretion | 469,333 | 420,243 | 1,370,912 | 1,198,169 | ||||||||
Property impairments | 23,770 | 35,130 | 86,715 | 209,819 | ||||||||
Exploration expenses | 2,324 | 1,389 | 4,347 | 9,591 | ||||||||
Impact from derivative instruments: | ||||||||||||
Total (gain) loss on derivatives, net | 2,025 | (9,945) | 4,536 | (82,015) | ||||||||
Total cash (paid) received on derivatives, net | (1,477) | 12,884 | 7,477 | 16,534 | ||||||||
Non-cash (gain) loss on derivatives, net | 548 | 2,939 | 12,013 | (65,481) | ||||||||
Non-cash equity compensation | 11,730 | 11,919 | 33,209 | 32,490 | ||||||||
Loss on extinguishment of debt | 7,133 | - | 7,133 | - | ||||||||
EBITDAX (non-GAAP) | $ | 999,882 | $ | 563,767 | $ | 2,772,733 | $ | 1,525,730 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended September 30, | Nine months ended September 30, | |||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||
Net cash provided by operating activities | $ | 860,748 | $ | 431,409 | $ | 2,500,741 | $ | 1,347,981 | ||||
Current income tax provision (benefit) | (7,778) | (1) | (7,778) | - | ||||||||
Interest expense | 73,409 | 74,756 | 223,590 | 218,672 | ||||||||
Exploration expenses, excluding dry hole costs | 2,324 | 1,389 | 4,346 | 9,434 | ||||||||
Gain on sale of assets, net | 1,510 | 3,562 | 8,261 | 703 | ||||||||
Other, net | (3,036) | (7,278) | (10,832) | (9,251) | ||||||||
Changes in assets and liabilities | 72,705 | 59,930 | 54,405 | (41,809) | ||||||||
EBITDAX (non-GAAP) | $ | 999,882 | $ | 563,767 | $ | 2,772,733 | $ | 1,525,730 |
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures, excluding acquisitions, plus non-controlling interest capital contributions, less distributions to non-controlling interests. The inclusion of non-controlling interest capital contributions and distributions, expected to begin in the fourth quarter of 2018, is related to our newly formed relationship with Franco-Nevada to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Net sales prices
On January 1, 2018, we adopted Accounting Standards Update 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which impacted the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach whereby changes have been applied only to the most current period presented and prior period results have not been adjusted to conform to current presentation.
Under the new rules, revenues and transportation expenses associated with production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from our operated properties differs from the net presentation of revenues from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results, and to achieve comparability with prior period metrics for analysis purposes, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three and nine months ended September 30, 2018. Information is also presented for the three and nine months ended September 30, 2017 for comparative purposes.
Three months ended September 30, 2018 | Three months ended September 30, 2017 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $1,038,558 | $234,680 | $1,273,238 | $550,451 | $154,367 | $704,818 | ||||||
Less: Transportation expenses | (39,336) | (6,672) | (46,008) | — | — | — | ||||||
Net crude oil and natural gas sales (non-GAAP for 2018) | $999,222 | $228,008 | $1,227,230 | $550,451 | $154,367 | $704,818 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 15,190 | 73,029 | 27,361 | 12,722 | 56,401 | 22,123 | ||||||
Net sales price (non-GAAP for 2018) | $65.78 | $3.12 | $44.85 | $43.27 | $2.74 | $31.86 | ||||||
Nine months ended September 30, 2018 | Nine months ended September 30, 2017 | |||||||||||
In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | ||||||
Crude oil and natural gas sales (GAAP) | $2,891,722 | $632,896 | $3,524,618 | $1,512,990 | $452,226 | $1,965,216 | ||||||
Less: Transportation expenses | (119,939) | (22,620) | (142,559) | — | — | — | ||||||
Net crude oil and natural gas sales (non-GAAP for 2018) | $2,771,783 | $610,276 | $3,382,059 | $1,512,990 | $452,226 | $1,965,216 | ||||||
Sales volumes (MBbl/MMcf/MBoe) | 44,183 | 209,069 | 79,028 | 34,975 | 162,515 | 62,061 | ||||||
Net sales price (non-GAAP for 2018) | $62.73 | $2.92 | $42.80 | $43.26 | $2.78 | $31.67 |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | |
2018 Guidance | |
As of October 29, 2018 | |
2018 | |
Full-year average production | 290,000 to 300,000 Boe per day |
Exit-rate average production | 315,000 to 325,000 Boe per day |
Capital expenditures budget (non-acquisition) | $2.7 billion |
Operating Expenses: | |
Production expense per Boe | $3.50 to $3.75 (updated(1)) |
Production tax (% of net oil & gas revenue) | 7.6% to 8.0% |
Cash G&A expense per Boe(2) | $1.20 to $1.65 |
Non-cash equity compensation per Boe | $0.40 to $0.50 |
DD&A per Boe | $17.00 to $18.00 |
Average Price Differentials: | |
NYMEX WTI crude oil (per barrel of oil) | ($3.50) to ($4.50) |
Henry Hub natural gas (per Mcf) | $0.00 to +$0.50 |
(1) Updated from a prior guidance range of $3.00 to $3.50. | |
(2) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.60 to $2.15 per Boe. |
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SOURCE Continental Resources
OKLAHOMA CITY, Sept. 27, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce third quarter 2018 results on Monday, October 29, 2018 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss third quarter 2018 results on Tuesday, October 30, 2018 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: | 12 p.m. ET, Tuesday, October 30, 2018 |
Dial-in: | 844-309-6572 |
Intl. dial-in: | 484-747-6921 |
Conference ID: | 3745129 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: | 855-859-2056 or 404-537-3406 |
Intl. replay: | 800-585-8367 |
Conference ID: | 3745129 |
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Continental plans to publish a third quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its conference call on October 30, 2018.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: | Media Contact: |
Rory Sabino | Kristin Thomas |
Vice President, Investor Relations | Senior Vice President, Public Relations |
405-234-9620 | 405-234-9480 |
Lucy Guttenberger | |
Senior Investor Relations Associate | |
405-774-5878 | |
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-third-quarter-2018-results-on-monday-october-29-2018-300720636.html
SOURCE Continental Resources
OKLAHOMA CITY, Aug. 7, 2018 /PRNewswire/ --/PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced second quarter operating and financial results. The Company reported net income of $242.5 million, or $0.65 per diluted share, for the quarter ended June 30, 2018. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In second quarter 2018, these typically excluded items in aggregate represented $30.4 million, or $0.08 per diluted share, of Continental's reported net income. Adjusted net income for second quarter 2018 was $272.9 million, or $0.73 per diluted share.
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Net cash provided by operating activities for second quarter 2018 was $753.8 million. EBITDAX for second quarter 2018 was $896.7 million. Definitions and reconciliations of adjusted net income, adjusted net income per share, free cash flow, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables at the conclusion of this press release.
As of June 30, 2018, the Company's balance sheet included approximately $130.0 million in cash and cash equivalents and $6.17 billion in total debt. During June, the Company achieved its short-term goal to drop below $6 billion in net debt. On June 30, 2018, net debt was slightly higher at $6.04 billion due to working capital changes and incremental acquired minerals. On July 12, 2018, the Company announced a partial call of its 5% Senior Notes Due 2022. This represents 20% ($400 million) of the $2 billion in aggregate principal amount of these notes currently outstanding. The Company continues to pursue its $5 billion long-term net debt goal. The Company's second quarter annualized net-debt-to-EBITDAX ratio was 1.68x and continues to approach the historically low levels seen prior to the three-year commodity down cycle.
The Company's second quarter 2018 crude oil differential was $4.55 per barrel below the NYMEX daily average for the period, an improvement of $1.76 per barrel compared to second quarter 2017. The realized wellhead natural gas price for second quarter 2018 was $0.15 per Mcf below the average NYMEX Henry Hub benchmark price. The Company expects to realize improved crude oil differentials in third quarter 2018 based on widening Brent/WTI spread and lower Cushing inventories.
Updated 2018 Guidance
The Company is increasing its 2018 annual production guidance to 290,000 to 300,000 Boe per day and is increasing its projected exit rate by 10,000 Boe per day to 315,000 to 325,000 Boe per day. This increase is driven primarily by Bakken outperformance, realized operational efficiencies and the reallocation of rigs to higher, non-carried working interest wells in SCOOP and STACK.
The Company also updated its 2018 Capex guidance from $2.3 billion to $2.7 billion. Approximately $275 million of this increase is associated with an investment in minerals within our existing leasehold, which is expected to be partially funded by mineral divestiture proceeds of approximately $220 million in fourth quarter 2018. New capital of $125 million and reallocated capital of $75 million will be used for additional drilling and completions (D&C) activity, including the addition of three rigs by year end, focused on high rate of return, oil-weighted assets. One-third of the D&C Capex increase is associated with higher value, 60-stage Bakken completions and two-thirds is associated with activity in Oklahoma.
Included within the updated 2018 Capex guidance is approximately $600 million for wells that will not have first production until 2019, providing a catalyst for continued oil-weighted production growth. The Company expects to exit 2018 with a wells in progress (WIP) inventory in the Bakken of approximately 130 gross operated wells, including approximately 50 already stimulated, with first production expected in 2019. In Oklahoma, the Company expects to exit 2018 with a WIP inventory of approximately 55 gross operated wells, including approximately 5 already stimulated, with first production expected in 2019. These wells will further prompt oil-focused growth in 2019.
"Continental is in an advantaged position in the current market, with high rate of return oil plays benefitting from existing infrastructure," said Harold Hamm, Chairman and Chief Executive Officer. "As we look into the second half of 2018 and beyond, Continental and its shareholders have an exciting opportunity to accelerate capital-efficient, oil-focused production growth while remaining disciplined in achieving our targets for free cash flow and debt reduction."
In the Bakken, the Company is projected to average 5 completion crews and 6 rigs in the second half of the year, ramping up to 7 rigs by year end. The Company expects to complete approximately 125 additional Bakken wells with first production by year end, with more than half of these in fourth quarter 2018. In Oklahoma, the Company is projected to average 4 completion crews and 18 rigs in the second half of the year, ramping up to 19 rigs at year end. Over 95% of our drilling activity in 2018 will be focused on oil and liquids-rich prospects.
The Company also improved guidance for select 2018 operating expenses. Total G&A expense, which is comprised of cash and non-cash G&A expense, is expected to be $1.60 to $2.15 per Boe in 2018. Of this total, cash G&A expense is expected to be $1.20 to $1.65 per Boe, a reduction from the previous $1.25 to $1.75 per Boe. Non-cash equity compensation is expected to be $0.40 to $0.50 per Boe, a reduction from the previous $0.45 to $0.55 per Boe. Continental also reduced 2018 guidance for DD&A to $17.00 to $18.00 per Boe for the year, down from the previous range of $17.00 to $19.00 due to strong well productivity and capital efficiency.
2018 Updated Guidance Metrics |
Previous Guidance |
Updated Guidance |
Annual production (Boe per day) |
285,000 to 300,000 |
290,000 to 300,000 |
Exit rate production (Boe per day) |
305,000 to 315,000 |
315,000 to 325,000 |
Capex (non-acquisition) |
$2.3 billion |
$2.7 billion |
Cash G&A expense per Boe |
$1.25 to $1.75 |
$1.20 to $1.65 |
Non-cash equity compensation per Boe |
$0.45 to $0.55 |
$0.40 to $0.50 |
DD&A per Boe |
$17.00 to $19.00 |
$17.00 to $18.00 |
The Company's full 2018 guidance is stated in a table at the conclusion of this release.
$220 Million Minerals Divestiture & Strategic Mineral Relationship Formed
The Company announced yesterday the formation of a strategic minerals relationship with Franco-Nevada. The Company expects to receive approximately $220 million in net proceeds at closing in fourth quarter 2018. In addition, the parties have also committed, subject to satisfaction of agreed upon development thresholds, to spend up to a combined $125 million per year over the next three years to acquire additional minerals through the newly-formed subsidiary. With a carry component on capital acquisition costs, the Company is to fund 20% of future mineral acquisitions. The Company will be entitled to between 25% and 50% of total revenues generated by the minerals subsidiary based upon performance relative to certain predetermined targets. This new relationship is expected to enhance the value of minerals by targeting areas of the Company's future development in Oklahoma.
Production Update
Second quarter 2018 production totaled 25.8 million barrels of oil equivalent (Boe), or 284,059 Boe per day, up 26% from second quarter 2017. Total production for second quarter included 157,116 barrels of oil (Bo) per day and 761.7 million cubic feet (MMcf) of natural gas per day. The following table provides the Company's average daily production by region for the periods presented.
2Q |
1Q |
2Q |
YTD |
YTD | ||||||
Boe per day |
2018 |
2018 |
2017 |
2018 |
2017 | |||||
North Region: |
||||||||||
North Dakota Bakken |
151,805 |
154,503 |
112,397 |
153,147 |
106,736 | |||||
Montana Bakken |
6,314 |
6,853 |
7,464 |
6,582 |
7,720 | |||||
Red River Units |
8,404 |
9,338 |
9,878 |
8,868 |
9,983 | |||||
Other |
258 |
418 |
483 |
337 |
409 | |||||
South Region: |
||||||||||
SCOOP |
64,786 |
62,012 |
61,107 |
63,406 |
61,640 | |||||
STACK |
51,722 |
53,361 |
31,934 |
52,515 |
30,582 | |||||
Arkoma(1) |
9 |
2 |
1,788 |
6 |
1,771 | |||||
Other |
761 |
923 |
1,162 |
864 |
1,177 | |||||
Total |
284,059 |
287,410 |
226,213 |
285,725 |
220,018 |
(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017. |
Bakken: Record Results and Type Curve Uplifted to 1.2 MMBoe per Well
The Company uplifted its type curve EUR for the Bakken 9% to 1,200 MBoe per well in the second quarter. This increase reflects the Company's move from 40-stage to 60-stage completions, based on improved performance observed from 70 wells completed with the Company's 60-stage optimized completion techniques. A 60-stage completion increases the cost of a typical Bakken well by approximately $0.5 million for a total completed well cost of $8.4 million. At this cost, the 1,200 MBoe type curve delivers a 175% rate of return (ROR) at $70 WTI and approximately $0.4 million of incremental cash flow per well in the first year, as compared to the Company's previous 1,100 MBoe type curve.
"Our Bakken team continues to unlock value for our shareholders through innovative thinking and advanced technologies," said Gary Gould, Senior Vice President of Production & Resource Development. "Over the past year, our team increased our Bakken type curve twice, cumulatively raising the EUR 22%, doubling the rate of return, and adding $3.5 million of incremental first-year cash flow per well for an additional cost of only $1.4 million per well. This step change in performance is uplifting Bakken economics throughout the field. With 4,000 wells of operated inventory still ahead of us, the Bakken will be a growth vehicle for Continental for many years to come."
The Company's Bakken production averaged 158,119 Boe per day in second quarter 2018, up 32% versus second quarter 2017. During the quarter, the Company completed 35 gross (19 net) operated wells flowing at an average initial 24-hour rate of 2,282 Boe per day. Four of the wells ranked as top ten 30-day rate Bakken wells for the Company, including the first 30-day Bakken well to average over 3,000 Boe per day (Mountain Gap 7-10H in Dunn County, 3,104 Boe per day).
SCOOP: Project SpringBoard Phase I and Phase II Underway
The Company's SCOOP production averaged 64,786 Boe per day in second quarter 2018, up 6% versus second quarter 2017. The Company completed 16 gross (13 net) operated wells with first production in second quarter 2018.
The Company previously announced Project SpringBoard, which is a massive, multi-year, stacked pay, oil development project that covers approximately 70-square miles and includes 45,000 gross (31,000 net) contiguous acres. SpringBoard holds up to 400 MMBoe of gross unrisked resource potential, with wells expecting to average 70%-85% oil across both phases. The Company estimates up to 100 Springer and 250 Woodford and Sycamore potential locations and will operate SpringBoard with an average working interest of approximately 75%. In addition, SpringBoard is expected to benefit from the Company's row development operational efficiencies and production will benefit from access to premium markets through existing pipeline infrastructure.
Drilling is underway in both Phase I and Phase II of Project SpringBoard, with 7 rigs targeting the Springer reservoir (Phase I) and 4 rigs, ramping up to 6 rigs by year end, targeting the Woodford and Sycamore reservoirs (Phase II). The Company expects first production from the Springer wells in Project SpringBoard to begin late third quarter 2018, with up to 18 Springer wells producing by year end 2018. First production from the Woodford and Sycamore wells is expected to begin in first quarter 2019.
"Project SpringBoard is an outstanding, high impact oil project for Continental and its shareholders," said Jack Stark, President. "This project alone has the potential to increase Continental's oil production by as much as 10% over the next 12 months."
STACK: Oil Window Drilling Accelerated with Strong Well Results
The Company's STACK production increased 62% to 51,722 Boe per day in second quarter 2018, compared to second quarter 2017. Continental completed 26 gross (13 net) operated wells with first production in second quarter 2018. The top Company-operated STACK oil wells in second quarter include the Swaim 3-14H: 3,476 Boepd (2,596 Bopd), Madeline 2-4-9XH: 3,540 Boepd (2,548 Bopd), Lugene 1-33H: 3,600 Boepd (2,004 Bopd), Nelda 1-3-10XH: 4,032 Boepd (1,886 Bopd) and Brown Family 1-13-24XH: 3,065 Boepd (1,443 Bopd).
Financial Update
"Continental's positive revisions to production guidance reflect the oil-focused opportunity we see in accelerating our activity in a capital-efficient manner. The momentum built from these decisions will directly correlate to revenue generation and oil-weighted growth as we enter the back half of 2018 and 2019," said John Hart, Chief Financial Officer. "Continental will conduct the capital spend from both our D&C activity and our new minerals opportunity in a manner supportive of cash flow enhancement and debt reduction."
In second quarter 2018, the Company's average net sales price excluding the effects of derivative positions was $63.35 per barrel of oil and $2.65 per Mcf of gas, or $42.16 per Boe.
Production expense per Boe was $3.49 for second quarter 2018, which represented an $0.11 quarter over quarter improvement versus first quarter 2018 and a $0.50 year over year improvement versus second quarter 2017. Other select operating costs and expenses for second quarter 2018 included production taxes of 7.7% of net crude oil and natural gas sales; DD&A of $17.29 per Boe; and total G&A of $1.82 per Boe.
Non-acquisition capital expenditures for second quarter 2018 totaled approximately $714.2 million, including $627.9 million in exploration and development drilling, $44.9 million in leasehold, and $41.4 million in workovers, recompletions and other.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended June 30, |
Six months ended June 30, | ||||||
2018 |
2017 |
2018 |
2017 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
157,116 |
125,381 |
160,458 |
122,308 | |||
Natural gas (Mcf per day) |
761,653 |
604,991 |
751,603 |
586,263 | |||
Crude oil equivalents (Boe per day) |
284,059 |
226,213 |
285,725 |
220,018 | |||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) |
|||||||
Crude oil ($/Bbl) |
$63.35 |
$41.91 |
$61.14 |
$43.26 | |||
Natural gas ($/Mcf) |
$2.65 |
$2.63 |
$2.81 |
$2.81 | |||
Crude oil equivalents ($/Boe) |
$42.16 |
$30.31 |
$41.71 |
$31.56 | |||
Production expenses ($/Boe) |
$3.49 |
$3.99 |
$3.54 |
$3.89 | |||
Production taxes (% of net crude oil and gas sales) |
7.7% |
6.7% |
7.6% |
6.6% | |||
DD&A ($/Boe) |
$17.29 |
$19.14 |
$17.45 |
$19.48 | |||
Total general and administrative expenses ($/Boe) (2) |
$1.82 |
$1.89 |
$1.75 |
$2.16 | |||
Net income (loss) (in thousands) |
$242,464 |
($63,557) |
$476,410 |
($63,088) | |||
Diluted net income (loss) per share |
$0.65 |
($0.17) |
$1.27 |
($0.17) | |||
Adjusted net income (loss) (non-GAAP) (in thousands) (1) |
$272,877 |
($1,801) |
$528,016 |
$4,979 | |||
Adjusted diluted net income (loss) per share (non-GAAP) (1) |
$0.73 |
$0.00 |
$1.41 |
$0.01 | |||
Net cash provided by operating activities (in thousands) |
753,802 |
$446,371 |
1,639,993 |
$916,572 | |||
EBITDAX (non-GAAP) (in thousands) (1) |
896,654 |
$479,490 |
1,772,850 |
$961,963 |
(1) Net sales prices, adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.41, $1.45, $1.33, and $1.65 for 2Q 2018, 2Q 2017, YTD 2018 and YTD 2017, respectively. Non-cash equity compensation expense per Boe was $0.41, $0.44, $0.42, and $0.51 for 2Q 2018, 2Q 2017, YTD 2018 and YTD 2017, respectively. |
Second Quarter Earnings Conference Call
Continental plans to host a conference call to discuss second quarter results on Wednesday, August 8, 2018, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Wednesday, August 8, 2018 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
4798234 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
4798234 |
Continental plans to publish a second quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on August 8, 2018.
Upcoming Conferences
Members of Continental's management team plan to participate in the following investment conferences:
August 15-16, 2018 Heikkinen Energy Conference
September 4-6, 2018 Barclays Global CEO-Energy Power Conference
Presentation materials for all conferences mentioned above will be available on the Company's web site at www.CLR.com prior to the start of the Company's presentation at the applicable conference. For each presentation, the Company will utilize its web site to post updated materials or indicate which previously posted presentation materials will be used for the conference in question.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
Rory Sabino |
Kristin Thomas |
Vice President, Investor Relations |
Senior Vice President, Public Relations |
405-234-9620 |
405-234-9480 |
Lucy Guttenberger |
|
Senior Investor Relations Associate |
|
405-774-5878 |
|
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Statements of Income (Loss) | |||||||
Three months ended June 30, |
Six months ended June 30, | ||||||
2018 |
2017 |
2018 |
2017 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 1,137,528 |
$ 626,548 |
$ 2,251,380 |
$ 1,260,398 | |||
Gain (loss) on natural gas derivatives, net |
(12,685) |
28,022 |
(2,511) |
74,880 | |||
Crude oil and natural gas service operations |
12,270 |
6,916 |
29,272 |
11,636 | |||
Total revenues |
1,137,113 |
661,486 |
2,278,141 |
1,346,914 | |||
Operating costs and expenses: |
|||||||
Production expenses |
90,171 |
82,474 |
183,133 |
155,328 | |||
Production taxes |
83,595 |
41,965 |
164,175 |
83,198 | |||
Transportation expenses |
47,254 |
- |
96,551 |
- | |||
Exploration expenses |
303 |
3,204 |
2,023 |
8,202 | |||
Crude oil and natural gas service operations |
7,688 |
4,478 |
12,271 |
7,315 | |||
Depreciation, depletion, amortization and accretion |
447,200 |
395,770 |
901,578 |
777,926 | |||
Property impairments |
29,162 |
123,316 |
62,946 |
174,689 | |||
General and administrative expenses |
47,174 |
39,186 |
90,217 |
86,407 | |||
Net (gain) loss on sale of assets and other |
(6,710) |
134 |
(6,751) |
5,669 | |||
Total operating costs and expenses |
745,837 |
690,527 |
1,506,143 |
1,298,734 | |||
Income (loss) from operations |
391,276 |
(29,041) |
771,998 |
48,180 | |||
Other income (expense): |
|||||||
Interest expense |
(74,288) |
(72,744) |
(150,182) |
(143,916) | |||
Other |
708 |
373 |
1,362 |
815 | |||
(73,580) |
(72,371) |
(148,820) |
(143,101) | ||||
Income (loss) before income taxes |
317,696 |
(101,412) |
623,178 |
(94,921) | |||
(Provision) benefit for income taxes |
(75,232) |
37,855 |
(146,768) |
31,833 | |||
Net income (loss) |
$ 242,464 |
$ (63,557) |
$ 476,410 |
$ (63,088) | |||
Basic net income (loss) per share |
$ 0.65 |
$ (0.17) |
$ 1.28 |
$ (0.17) | |||
Diluted net income (loss) per share |
$ 0.65 |
$ (0.17) |
$ 1.27 |
$ (0.17) |
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Balance Sheets | |||||
June 30, 2018 |
December 31, 2017 | ||||
Assets |
In thousands | ||||
Cash and cash equivalents |
$ |
129,989 |
$ |
43,902 | |
Other current assets |
1,311,300 |
1,207,823 | |||
Net property and equipment (1) |
13,339,571 |
12,933,789 | |||
Other noncurrent assets |
17,620 |
14,137 | |||
Total assets |
$ |
14,798,480 |
$ |
14,199,651 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
1,484,439 |
$ |
1,330,242 | |
Long-term debt, net of current portion |
6,164,221 |
6,351,405 | |||
Other noncurrent liabilities |
1,536,332 |
1,386,801 | |||
Total shareholders' equity |
5,613,488 |
5,131,203 | |||
Total liabilities and shareholders' equity |
$ |
14,798,480 |
$ |
14,199,651 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $9.88 billion and $9.08 billion as of June 30, 2018 and December 31, 2017, respectively. |
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||||||
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2018 |
2017 |
2018 |
2017 | ||||||||
Net income (loss) |
$ |
242,464 |
$ |
(63,557) |
$ |
476,410 |
$ |
(63,088) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
576,109 |
465,966 |
1,145,283 |
877,921 | ||||||||
Changes in assets and liabilities |
(64,771) |
43,962 |
18,300 |
101,739 | ||||||||
Net cash provided by operating activities |
753,802 |
446,371 |
1,639,993 |
916,572 | ||||||||
Net cash used in investing activities |
(715,392) |
(490,049) |
(1,343,603) |
(879,320) | ||||||||
Net cash (used in) provided by financing activities |
(6,553) |
43,666 |
(210,277) |
(36,719) | ||||||||
Effect of exchange rate changes on cash |
(13) |
14 |
(26) |
14 | ||||||||
Net change in cash and cash equivalents |
31,844 |
2 |
86,087 |
547 | ||||||||
Cash and cash equivalents at beginning of period |
98,145 |
17,188 |
43,902 |
16,643 | ||||||||
Cash and cash equivalents at end of period |
$ |
129,989 |
$ |
17,190 |
$ |
129,989 |
$ |
17,190 |
Non-GAAP Financial Measures
Adjusted earnings (net income/loss) and adjusted earnings (net income/loss) per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt as applicable. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as an alternative to, or more meaningful than, earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended June 30, | ||||||||
2018 |
2017 | |||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||
Net income (loss) (GAAP) |
$ 242,464 |
$ 0.65 |
$ (63,557) |
$ (0.17) | ||||
Adjustments: |
||||||||
Non-cash (gain) loss on derivatives |
17,443 |
(23,265) |
||||||
Property impairments |
29,162 |
123,316 |
||||||
Gain on sale of assets |
(6,711) |
(780) |
||||||
Total tax effect of adjustments (1) |
(9,481) |
(37,515) |
||||||
Total adjustments, net of tax |
30,413 |
0.08 |
61,756 |
0.17 | ||||
Adjusted net income (loss) (non-GAAP) |
$ 272,877 |
$ 0.73 |
$ (1,801) |
$0.00 | ||||
Weighted average diluted shares outstanding |
374,505 |
371,111 |
||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ 0.73 |
$0.00 |
||||||
Six months ended June 30, | ||||||||
2018 |
2017 | |||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||
Net income (loss) (GAAP) |
$ 476,410 |
$ 1.27 |
$ (63,088) |
$ (0.17) | ||||
Adjustments: |
||||||||
Non-cash (gain) loss on derivatives |
11,465 |
(68,420) |
||||||
Property impairments |
62,946 |
174,689 |
||||||
(Gain) loss on sale of assets |
(6,751) |
2,859 |
||||||
Total tax effect of adjustments (1) |
(16,054) |
(41,061) |
||||||
Total adjustments, net of tax |
51,606 |
0.14 |
68,067 |
0.18 | ||||
Adjusted net income (non-GAAP) |
$ 528,016 |
$ 1.41 |
$ 4,979 |
$ 0.01 | ||||
Weighted average diluted shares outstanding |
374,583 |
373,518 |
||||||
Adjusted diluted net income per share (non-GAAP) |
$ 1.41 |
$ 0.01 |
(1) Computed by applying a combined federal and state statutory tax rate of 24% in effect for 2018 and 38% in effect for 2017 to the pre-tax amount of adjustments associated with our operations in the United States. |
Net debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At June 30, 2018, the Company's net debt amounted to $6.04 billion, representing total debt of $6.17 billion less cash and cash equivalents of $130.0 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt as applicable. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income/loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income/loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income/loss to EBITDAX for the periods presented.
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2018 |
2017 |
2018 |
2017 | ||||||||
Net income (loss) |
$ |
242,464 |
$ |
(63,557) |
$ |
476,410 |
$ |
(63,088) | ||||
Interest expense |
74,288 |
72,744 |
150,182 |
143,916 | ||||||||
Provision (benefit) for income taxes |
75,232 |
(37,855) |
146,768 |
(31,833) | ||||||||
Depreciation, depletion, amortization and accretion |
447,200 |
395,770 |
901,578 |
777,926 | ||||||||
Property impairments |
29,162 |
123,316 |
62,946 |
174,689 | ||||||||
Exploration expenses |
303 |
3,204 |
2,023 |
8,202 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total (gain) loss on derivatives, net |
12,685 |
(27,109) |
2,511 |
(72,070) | ||||||||
Total cash received on derivatives, net |
4,758 |
3,844 |
8,954 |
3,650 | ||||||||
Non-cash (gain) loss on derivatives, net |
17,443 |
(23,265) |
11,465 |
(68,420) | ||||||||
Non-cash equity compensation |
10,562 |
9,133 |
21,478 |
20,571 | ||||||||
EBITDAX (non-GAAP) |
$ |
896,654 |
$ |
479,490 |
$ |
1,772,850 |
$ |
961,963 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented. | ||||||||||||
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2018 |
2017 |
2018 |
2017 | ||||||||
Net cash provided by operating activities |
$ |
753,802 |
$ |
446,371 |
$ |
1,639,993 |
$ |
916,572 | ||||
Current income tax provision |
- |
- |
- |
1 | ||||||||
Interest expense |
74,288 |
72,744 |
150,182 |
143,916 | ||||||||
Exploration expenses, excluding dry hole costs |
303 |
3,204 |
2,022 |
8,045 | ||||||||
Gain (loss) on sale of assets, net |
6,711 |
780 |
6,751 |
(2,859) | ||||||||
Other, net |
(3,221) |
353 |
(7,798) |
(1,973) | ||||||||
Changes in assets and liabilities |
64,771 |
(43,962) |
(18,300) |
(101,739) | ||||||||
EBITDAX (non-GAAP) |
$ |
896,654 |
$ |
479,490 |
$ |
1,772,850 |
$ |
961,963 |
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures, excluding acquisitions, plus non-controlling interest capital contributions, less distributions to non-controlling interests. The inclusion of non-controlling interest capital contributions and distributions, expected to begin in the fourth quarter of 2018, is related to our newly formed relationship with Franco-Nevada to fund a portion of certain mineral acquisitions which are included in our capital expenditures and operating results. Free cash flow is not a measure of net income or cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Net sales prices
On January 1, 2018, we adopted Accounting Standards Update 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which impacted the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach whereby changes have been applied only to the most current period presented and prior period results have not been adjusted to conform to current presentation.
Under the new rules, revenues and transportation expenses associated with production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from our operated properties differs from the net presentation of revenues from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results, and to achieve comparability with prior period metrics for analysis purposes, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three and six months ended June 30, 2018. Information is also presented for the three and six months ended June 30, 2017 for comparative purposes.
Three months ended June 30, 2018 |
Three months ended June 30, 2017 | |||||||||||
In thousands |
Crude oil |
Natural gas |
Total |
Crude oil |
Natural gas |
Total | ||||||
Crude oil and natural gas sales (GAAP) |
$946,884 |
$190,644 |
$1,137,528 |
$481,898 |
$144,650 |
$626,548 | ||||||
Less: Transportation expenses |
(40,217) |
(7,037) |
(47,254) |
— |
— |
— | ||||||
Net crude oil and natural gas sales (non-GAAP for 2018) |
$906,667 |
$183,607 |
$1,090,274 |
$481,898 |
$144,650 |
$626,548 | ||||||
Sales volumes (MBbl/MMcf/MBoe) |
14,311 |
69,310 |
25,863 |
11,499 |
55,054 |
20,674 | ||||||
Net sales price (non-GAAP for 2018) |
$63.35 |
$2.65 |
$42.16 |
$41.91 |
$2.63 |
$30.31 | ||||||
Six months ended June 30, 2018 |
Six months ended June 30, 2017 | |||||||||||
In thousands |
Crude oil |
Natural gas |
Total |
Crude oil |
Natural gas |
Total | ||||||
Crude oil and natural gas sales (GAAP) |
$1,853,165 |
$398,215 |
$2,251,380 |
$962,539 |
$297,859 |
$1,260,398 | ||||||
Less: Transportation expenses |
(80,603) |
(15,948) |
(96,551) |
— |
— |
— | ||||||
Net crude oil and natural gas sales (non-GAAP for 2018) |
$1,772,562 |
$382,267 |
$2,154,829 |
$962,539 |
$297,859 |
$1,260,398 | ||||||
Sales volumes (MBbl/MMcf/MBoe) |
28,993 |
136,040 |
51,667 |
22,253 |
106,114 |
39,938 | ||||||
Net sales price (non-GAAP for 2018) |
$61.14 |
$2.81 |
$41.71 |
$43.26 |
$2.81 |
$31.56 |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | |||
2018 Guidance | |||
As of August 7, 2018 | |||
Previous 2018 |
Updated 2018 | ||
Full-year average production |
285,000 to 300,000 Boe per day |
290,000 to 300,000 Boe per day | |
Exit-rate average production |
305,000 to 315,000 Boe per day |
315,000 to 325,000 Boe per day | |
Capital expenditures (non-acquisition) |
$2.3 billion |
$2.7 billion | |
Operating Expenses: |
|||
Production expense per Boe |
$3.00 to $3.50 |
$3.00 to $3.50 | |
Production tax (% of net oil & gas revenue) |
7.6% to 8.0% |
7.6% to 8.0% | |
Cash G&A expense per Boe(1) |
$1.25 to $1.75 |
$1.20 to $1.65 | |
Non-cash equity compensation per Boe |
$0.45 to $0.55 |
$0.40 to $0.50 | |
DD&A per Boe |
$17.00 to $19.00 |
$17.00 to $18.00 | |
Average Price Differentials: |
|||
NYMEX WTI crude oil (per barrel of oil) |
($3.50) to ($4.50) |
($3.50) to ($4.50) | |
Henry Hub natural gas (per Mcf) |
$0.00 to +$0.50 |
$0.00 to +$0.50 |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.60 to $2.15 per Boe. |
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SOURCE Continental Resources
OKLAHOMA CITY, Aug. 6, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (The "Company") today announced that Franco-Nevada (NYSE & TSX: FNV) has agreed to pay approximately $220 million for a stake in a newly-formed minerals subsidiary. In accordance with the deal terms, the Company will receive the proceeds at closing, offsetting the majority of previously incurred capital expenditures. The amount to be received by the Company at closing is subject to adjustment under the terms of the transaction documents.
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In addition, the parties have also committed, subject to satisfaction of agreed upon development thresholds, to spend up to a combined $125 million per year over the next three years to acquire additional minerals through the newly-formed subsidiary. With a carry component on capital acquisition costs, the Company is to fund 20% of future mineral acquisitions. The Company will be entitled to between 25% and 50% of total revenues generated by the minerals subsidiary based upon performance relative to certain predetermined targets.
The Company subsidiary and Franco-Nevada have executed definitive documents evidencing the aforementioned divestiture and the formation of the strategic relationship, subject to customary closing conditions, to acquire minerals in the SCOOP and STACK plays of Oklahoma, primarily in areas operated by the Company. These areas offer prolific well results, excellent economics, proximity to infrastructure and future upside via stacked hydrocarbon-bearing horizons.
"We could not be more pleased to team up with a leading royalty corporation in Franco-Nevada, who has a vast understanding of the value of mineral ownership as evidenced by their long track-record of acquiring assets globally," said Harold Hamm, Chairman and Chief Executive Officer. "We are pleased to announce yet another growth vehicle to Continental within our core business, complementing our existing assets and capturing incremental value for Continental shareholders while also applying proceeds for further debt reduction."
"Collaborating with Continental to purchase minerals is a new business development opportunity for Franco-Nevada," stated David Harquail, Chief Executive Officer of Franco-Nevada. "We are pleased to be able to work with this best-in-class operator to further strengthen Franco-Nevada's overall portfolio."
RBC Capital Markets and Vinson & Elkins LLP acted as exclusive financial and legal advisors, respectively, to the Company.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
About Franco-Nevada
Franco-Nevada Corporation (NYSE & TSX: FNV) is the leading gold-focused royalty and stream company with a current market capitalization of approximately $14 billion. Based in Toronto, Canada, Franco-Nevada targets to have 80% of its business in precious metals and up to 20% of its business in non-precious resources including oil & gas. Its business model provides investors with commodity price and exploration optionality while limiting exposure to many of the risks of operating companies. Franco-Nevada is the gold investment that works. For more information, please visit www.franco-nevada.com.
Investor Contact: |
Media Contact: |
Rory Sabino |
Kristin Thomas |
Vice President, Investor Relations |
Senior Vice President, Public Relations |
405-234-9620 |
405-234-9480 |
Lucy Guttenberger |
|
Senior Investor Relations Associate |
|
405-774-5878 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-220mm-minerals-divestiture-and-formation-of-strategic-relationship-with-franco-nevada-300692633.html
SOURCE Continental Resources
OKLAHOMA CITY, July 12, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today that it will redeem $400 million in aggregate principal amount, representing approximately 20% of the $2.0 billion in aggregate principal amount currently outstanding, of its 5% Senior Notes due 2022 (the "Notes") on August 16, 2018, the redemption date for the Notes.
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The redemption price for the Notes called for redemption will be equal to 101.667% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date in accordance with the terms of the Notes and the indenture under which the Notes were issued. The Notes to be redeemed will be selected in accordance with the procedures of The Depository Trust Company. Interest on the portion of the Notes selected for redemption will cease to accrue on and after the redemption date.
Additional information concerning the terms and conditions of the redemption is contained in the notice distributed to holders of the Notes. Beneficial holders with any questions about the redemption should contact their respective brokerage firm or financial institution.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, the ability to complete the redemption and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statement. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contacts: |
Media Contact: |
Rory Sabino |
Kristin Thomas |
Vice President, Investor Relations |
Senior Vice President, Public Relations |
405-234-9620 |
405-234-9480 |
Lucy Guttenberger |
|
Senior Investor Relations Associate |
|
405-774-5878 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-partial-redemption-of-5-senior-notes-due-2022-300679772.html
SOURCE Continental Resources
OKLAHOMA CITY, July 10, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce second quarter 2018 results on Tuesday, August 7, 2018 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss second quarter 2018 results on Wednesday, August 8, 2018 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Wednesday, August 8, 2018 |
Dial-in: |
844-309-6572 |
Intl. dial-in: |
484-747-6921 |
Conference ID: |
4798234 |
A replay of the call will be available for 14 days on the Company's website or by dialing: | |
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
4798234 |
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Continental plans to publish a second quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its conference call on August 8, 2018.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
|
Rory Sabino |
Kristin Thomas |
|
Vice President, Investor Relations |
Senior Vice President, Public Relations |
|
405-234-9620 |
405-234-9480 |
|
Lucy Guttenberger |
||
Senior Investor Relations Associate |
||
405-774-5878 |
||
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-second-quarter-2018-results-on-tuesday-august-7-2018-300678922.html
SOURCE Continental Resources
OKLAHOMA CITY, May 2, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced first quarter operating and financial results. The Company reported net income of $233.9 million, or $0.63 per diluted share, for the quarter ended March 31, 2018.
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The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In first quarter 2018, these typically excluded items in aggregate represented $21.2 million, or $0.05 per diluted share, of Continental's reported net income. Adjusted net income for first quarter 2018 was $255.1 million, or $0.68 per diluted share.
Net cash provided by operating activities for first quarter 2018 was $886.2 million. EBITDAX for first quarter 2018 was $876.2 million. Definitions and reconciliations of adjusted net income, adjusted net income per share, free cash flow, EBITDAX, net debt, net sales prices and cash general and administrative expenses per barrel of oil equivalent (Boe) presented herein to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables at the conclusion of this press release.
During first quarter 2018, the Company generated $207 million in free cash flow, allowing the Company to pay down its existing revolver balance to zero and build its cash on hand. At quarter-end, Continental's total debt was $6.17 billion, nearing the Company's short-term goal of $6 billion, while also underscoring the strides made towards achieving the long-term target of $5 billion. The Company's first quarter annualized net-debt-to-EBITDAX ratio was 1.73x, which now approaches the historical levels seen prior to the three year commodity down cycle.
Based on realizations without the effect of derivatives, the Company's first quarter 2018 crude oil differential was $3.91 per barrel below the NYMEX daily average for the period, an improvement of $3.18 per barrel compared to first quarter 2017. The realized wellhead natural gas price for first quarter 2018 was in line with the average NYMEX Henry Hub benchmark price.
"Our first quarter results show our 2018 breakout year is off to a strong start," said Harold Hamm, Chairman and Chief Executive Officer. "We are breaking away from our peers and capitalizing on decades of exploration success and operational achievements. Coupled with oil-weighted production growth and industry-leading efficiencies, we remain focused on maximizing returns and generating free cash flow now approaching $1 billion in 2018, at current commodity prices."
Production
First quarter 2018 production totaled 25.9 million barrels of oil equivalent (Boe), or 287,410 Boe per day, up 34% from first quarter 2017. Oil production grew 37% from first quarter 2017 to first quarter 2018. The Company expects second quarter 2018 production will be in a range of 285,000 to 290,000 Boe per day.
Total production for first quarter 2018 included 163,837 barrels of oil (Bo) per day (57% of production) and 741.4 million cubic feet (MMcf) of natural gas per day (43% of production). The Company expects to remain in the range of 57% - 60% oil as a percent of overall production in 2018, which is in line with prior guidance.
The following table provides the Company's average daily production by region for the periods presented.
1Q |
4Q |
1Q | ||||
Boe per day |
2018 |
2017 |
2017 | |||
North Region: |
||||||
North Dakota Bakken |
154,503 |
158,640 |
101,012 | |||
Montana Bakken |
6,853 |
6,958 |
7,980 | |||
Red River Units |
9,338 |
9,497 |
10,089 | |||
Other |
418 |
468 |
333 | |||
South Region: |
||||||
SCOOP |
62,012 |
62,242 |
62,178 | |||
STACK |
53,361 |
47,914 |
29,216 | |||
Arkoma(1) |
2 |
11 |
1,754 | |||
Other |
923 |
1,255 |
1,193 | |||
Total |
287,410 |
286,985 |
213,755 |
(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017. |
Bakken: Record Well Performance and Improved Differentials
The Company's Bakken production averaged 161,356 Boe per day in first quarter 2018, up 48% versus first quarter 2017. Approximately 80% of the production was oil. The Company completed 31 gross (21 net) operated Bakken wells during the first quarter with an average 24-Hour IP of 2,079 Boe per day.
Three of the Company's top five all-time 30-day rate wells in the Bakken were completed in the first quarter, averaging 2,305 Boe per day. The top eight 30-day rate Bakken wells in the Company's history have now been completed in the past two quarters. These record rates are a result of the Company's optimized completion designs.
To date, the Company has completed 164 optimized Bakken wells in Dunn, McKenzie, Mountrail and Williams counties. On average, these wells are performing in line with the Company's current 1.1 MMBoe type curve, which delivers a rate of return of 140%, based on a $65 WTI oil price.
Bakken crude oil differentials averaged $4.31 per barrel in first quarter 2018, a 47% improvement over the first quarter 2017 average of $8.10 per barrel. This sustainable, structural shift has been driven by increased pipeline takeaway capacity and the renegotiated transportation contract with Belle Fourche-Tallgrass. Approximately 30% of the Company's Bakken crude now flows on Belle Fourche-Tallgrass pipeline systems at a reduced rate of $3.75 per barrel, down 40% from the previous rate. The renegotiated contract was effective January 1, 2018 and runs through October 2024.
"We are clearly seeing a structural uplift in well performance across the Bakken field," said Jack Stark, President. "Combined with improved differentials and low production costs, our optimized completions are generating some of the best returns we have seen from our Bakken assets. With over 4,000 locations in inventory, the future value to be realized by Continental and its shareholders from our Bakken assets is tremendous."
Continental operates six drilling rigs in the Bakken and plans to maintain that level through year end. The Company also operates eight stimulation crews in the play and plans to average seven to eight crews through the end of the year.
SCOOP
The Company's SCOOP production averaged 62,012 Boe per day (26% oil) in first quarter 2018. The Company had 18 gross (14 net) operated wells completed in first quarter 2018. Continental currently has eight operated drilling rigs working in SCOOP with five targeting the Springer formation, one targeting the Woodford and two targeting the Sycamore.
SCOOP: Project "SpringBoard" Announced with Phase 1 Springer Row Development Underway
The Company has initiated a multi-zone, oil development project within SCOOP named Project SpringBoard. The project covers 70-square miles and includes approximately 45,000 gross (31,000 net) contiguous acres. The Company anticipates approximately 100 Springer wells and up to 250 Woodford and/or Sycamore wells will be drilled in the project with gross unrisked reserve potential of over 400 MMBoe. The Company will operate these wells with an average working interest of approximately 75%. The Company currently plans to develop Project SpringBoard in two phases, with "Phase 1" focused on the Springer reservoir and "Phase 2" focused on Woodford and Sycamore reservoirs. These reservoirs will be developed in rows up to nine miles wide to maximize the efficiencies and returns from the project.
"Project SpringBoard is a massive oil project controlled and operated by Continental," said Tony Barrett, Vice President, Exploration. "SpringBoard marks the beginning of full scale development of our SCOOP oil assets, following years of exploration, leasing and delineation drilling. With oil differentials below $2.00, these barrels represent some of the most profitable barrels within the Company."
Before beginning row development of the Springer, the Company recently completed the four-well Triple H Springer unit within Project SpringBoard. The four Springer producers flowed at a maximum combined 24-hour IP rate of 6,065 Boe per day, with 88% of the production being high quality, sweet 46 gravity crude. The Triple H wells were drilled to test the productivity of thinner areas of the reservoir, using extended laterals that were 10,200 feet long. These extended laterals were drilled in approximately the same number of days (35 days) and at drilling costs comparable to one-mile laterals drilled approximately one year earlier.
SCOOP Woodford Oil: Updated Design Lowers Drilling Costs $1 Million per Well
Updated well designs and improved drilling performance have reduced completed well costs in the Woodford oil window by approximately $1 million to $11.7 million per well. At these reduced costs, a Woodford oil well now delivers a 70% rate of return, assuming the Company's current 1.5 MMBoe type curve and $65 WTI.
In addition, the Company recently completed two optimized Woodford completions. This includes the Pyle 1-36-25XH well announced last quarter, which flowed at a 24-Hour IP rate of 1,812 Boe per day (81% oil) and the Lillian 1-23-14XH well announced this quarter, which flowed at a 24-Hour IP rate of 1,593 Boe per day (74% oil). Both are outperforming the Company's 1.5 MMBoe type curve.
STACK: Shifting Rigs to Accelerate Development of Oil and Liquids-Rich Assets
The Company's STACK production increased 83% to 53,361 Boe per day in first quarter 2018, compared to first quarter 2017. Continental had 12 gross (7 net) operated wells completed in first quarter 2018.
The Company is shifting three of five rigs drilling in the STACK gas window, as acreage in the STACK JDA is now essentially held by production. Two rigs will move to unit development in the STACK over-pressured oil window and one will move to the over-pressured condensate window in SCOOP. With this reallocation, approximately 90% of the Company's 16 rigs in Oklahoma will be focused on oil and liquids-rich assets.
Project Wildcat: 400 MMcfd of Firm Transportation from SCOOP and STACK
The Company recently announced a firm transportation agreement on Enable Midstream Partners' Project Wildcat, which will provide 400 MMcf per day of additional takeaway capacity from SCOOP and STACK. As the anchor shipper, the Company will also have direct access to premium markets, including the growing North Texas region, where supplies of natural gas from the Barnett Shale continue to decline. Project Wildcat is expected to be fully in service in July 2018.
"With the announcement of Project Wildcat, Continental is in an extremely advantageous position in Oklahoma," said Harold Hamm, Chairman and Chief Executive Officer. "Wildcat provides additional flow assurance for Continental's growing production from SCOOP and STACK into a new premium market."
Financial Update
"2018 is off to a great start with the generation of $207 million in free cash flow in the first quarter," said John Hart, Chief Financial Officer. "With continued excess cash generation, we expect to be below $6 billion of net debt in the second quarter 2018, targeting our long-term goal of $5 billion of net debt being achieved sometime in 2019. This is yet another example of how Continental continues to deliver on its goals. We couldn't be more proud of what our Company is able to accomplish quarter-after-quarter."
On April 30, 2018, Fitch assigned an investment grade rating to the Company, which follows the February 12, 2018 upgrade by S&P to investment grade and reflects positive free cash flow and an improving leverage profile.
In first quarter 2018, the Company's average net sales price excluding the effects of derivative positions was $58.98 per barrel of oil and $2.98 per Mcf of gas, or $41.26 per Boe.
Production expense per Boe was $3.60 for first quarter 2018. Other select operating costs and expenses for first quarter 2018 included production taxes of 7.6% of net crude oil and natural gas sales; DD&A of $17.61 per Boe; and total G&A of $1.67 per Boe.
Non-acquisition capital expenditures for first quarter 2018 totaled approximately $596.3 million, including $496.3 million in exploration and development drilling, $67.0 million in leasehold and seismic, and $33.0 million in workovers, recompletions and other.
As of March 31, 2018, the Company's balance sheet included approximately $98.1 million in cash and cash equivalents and $6.17 billion in total debt.
The following table provides the Company's production results, average net sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
1Q |
4Q |
1Q | |||
2018 |
2017 |
2017 | |||
Average daily production: |
|||||
Crude oil (Bbl per day) |
163,837 |
168,066 |
119,201 | ||
Natural gas (Mcf per day) |
741,442 |
713,518 |
567,328 | ||
Crude oil equivalents (Boe per day) |
287,410 |
286,985 |
213,755 | ||
Average net sales prices (non-GAAP), excluding effect from derivatives: (1) |
|||||
Crude oil ($/Bbl) |
$58.98 |
$51.16 |
$44.69 | ||
Natural gas ($/Mcf) |
$2.98 |
$3.30 |
$3.00 | ||
Crude oil equivalents ($/Boe) |
$41.26 |
$38.27 |
$32.90 | ||
Production expenses ($/Boe) |
$3.60 |
$3.17 |
$3.78 | ||
Production taxes (% of net crude oil and gas sales) |
7.6% |
7.3% |
6.5% | ||
DD&A ($/Boe) |
$17.61 |
$17.93 |
$19.84 | ||
Total general and administrative expenses ($/Boe) (2) |
$1.67 |
$2.30 |
$2.45 | ||
Net income (in thousands) (3) |
$233,946 |
$841,914 |
$469 | ||
Diluted net income per share (3) |
$0.63 |
$2.25 |
$0.00 | ||
Adjusted net income (non-GAAP) (in thousands) (1) |
$255,140 |
$153,660 |
$6,782 | ||
Adjusted diluted net income per share (non-GAAP) (1) |
$0.68 |
$0.41 |
$0.02 | ||
Net cash provided by operating activities (in thousands) |
$886,191 |
$731,125 |
$470,201 | ||
EBITDAX (non-GAAP) (in thousands) (1) |
$876,196 |
$837,887 |
$482,472 |
(1) Net sales prices, adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. Further information about these non-GAAP financial measures as well as reconciliations to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
(2) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.25, $1.80, and $1.86 for 1Q 2018, 4Q 2017, and 1Q 2017, respectively. Non-cash equity compensation expense per Boe was $0.42, $0.50, and $0.59 for 1Q 2018, 4Q 2017, and 1Q 2017, respectively. |
(3) In December 2017, the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate, which resulted in a one-time increase in net income of approximately $713.7 million ($1.91 per diluted share) for the three months ended December 31, 2017. |
First Quarter Earnings Conference Call
Continental plans to host a conference call to discuss first quarter results on Thursday, May 3, 2018, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, May 3, 2018 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
4956858 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
4956858 |
Continental plans to publish a first quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on May 3, 2018.
Upcoming Conferences
Members of Continental's management team plan to participate in the following investment conferences:
May 7-8, 2018 |
Morgan Stanley E&P and Oil Services Conference, Houston |
June 5, 2018 |
Raymond James Best Ideas Conference, Boston |
June 18-20, 2018 |
JP Morgan Annual Oil & Gas Conference, New York |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
Rory Sabino |
Kristin Thomas |
Vice President, Investor Relations |
Senior Vice President, Public Relations |
405-234-9620 |
405-234-9480 |
Continental Resources, Inc. and Subsidiaries | |||
Unaudited Condensed Consolidated Statements of Income | |||
Three months ended March 31, | |||
2018 |
2017 | ||
Revenues: |
In thousands, except per share data | ||
Crude oil and natural gas sales |
$ 1,113,852 |
$ 633,850 | |
Gain on natural gas derivatives, net |
10,174 |
46,858 | |
Crude oil and natural gas service operations |
17,002 |
4,719 | |
Total revenues |
1,141,028 |
685,427 | |
Operating costs and expenses: |
|||
Production expenses |
92,962 |
72,854 | |
Production taxes |
80,580 |
41,234 | |
Transportation expenses |
49,297 |
- | |
Exploration expenses |
1,720 |
4,998 | |
Crude oil and natural gas service operations |
4,583 |
2,837 | |
Depreciation, depletion, amortization and accretion |
454,378 |
382,156 | |
Property impairments |
33,784 |
51,372 | |
General and administrative expenses |
43,043 |
47,220 | |
Net (gain) loss on sale of assets and other |
(41) |
5,535 | |
Total operating costs and expenses |
760,306 |
608,206 | |
Income from operations |
380,722 |
77,221 | |
Other income (expense): |
|||
Interest expense |
(75,894) |
(71,172) | |
Other |
654 |
442 | |
(75,240) |
(70,730) | ||
Income before income taxes |
305,482 |
6,491 | |
Provision for income taxes |
(71,536) |
(6,022) | |
Net income |
$ 233,946 |
$ 469 | |
Basic net income per share |
$ 0.63 |
$ - | |
Diluted net income per share |
$ 0.63 |
$ - |
Continental Resources, Inc. and Subsidiaries | |||||
Unaudited Condensed Consolidated Balance Sheets | |||||
March 31, 2018 |
December 31, 2017 | ||||
Assets |
In thousands | ||||
Cash and cash equivalents |
$ |
98,145 |
$ |
43,902 | |
Other current assets |
1,192,910 |
1,207,823 | |||
Net property and equipment (1) |
13,073,054 |
12,933,789 | |||
Other noncurrent assets |
13,408 |
14,137 | |||
Total assets |
$ |
14,377,517 |
$ |
14,199,651 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
1,391,277 |
$ |
1,330,242 | |
Long-term debt, net of current portion |
6,163,775 |
6,351,405 | |||
Other noncurrent liabilities |
1,461,244 |
1,386,801 | |||
Total shareholders' equity |
5,361,221 |
5,131,203 | |||
Total liabilities and shareholders' equity |
$ |
14,377,517 |
$ |
14,199,651 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $9.53 billion and $9.08 billion as of March 31, 2018 and December 31, 2017, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||
Three months ended March 31, | ||||||
In thousands |
2018 |
2017 | ||||
Net income |
$ |
233,946 |
$ |
469 | ||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||
Non-cash expenses |
569,174 |
411,955 | ||||
Changes in assets and liabilities |
83,071 |
57,777 | ||||
Net cash provided by operating activities |
886,191 |
470,201 | ||||
Net cash used in investing activities |
(628,211) |
(389,271) | ||||
Net cash used in financing activities |
(203,724) |
(80,385) | ||||
Effect of exchange rate changes on cash |
(13) |
- | ||||
Net change in cash and cash equivalents |
54,243 |
545 | ||||
Cash and cash equivalents at beginning of period |
43,902 |
16,643 | ||||
Cash and cash equivalents at end of period |
$ |
98,145 |
$ |
17,188 |
Non-GAAP Financial Measures
Adjusted earnings (net income) and adjusted earnings (net income) per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as an alternative to, or more meaningful than, earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
1Q 2018 |
4Q 2017 |
1Q 2017 | ||||||||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||||||||||
Net income (GAAP) |
$233,946 |
$ 0.63 |
$841,914 |
$ 2.25 |
$ 469 |
$ - | ||||||||||||
Adjustments: |
||||||||||||||||||
Non-cash (gain) loss on derivatives |
(5,978) |
7,450 |
(45,155) |
|||||||||||||||
Property impairments |
33,784 |
27,552 |
51,372 |
|||||||||||||||
Litigation settlement |
- |
59,600 |
- |
|||||||||||||||
(Gain) loss on sale of assets |
(41) |
(54,420) |
3,638 |
|||||||||||||||
Loss on extinguishment of debt |
- |
554 |
- |
|||||||||||||||
Total tax effect of adjustments (1) |
(6,571) |
(15,335) |
(3,542) |
|||||||||||||||
Tax benefit from US tax reform legislation |
- |
(713,655) |
- |
|||||||||||||||
Total adjustments, net of tax |
21,194 |
0.05 |
(688,254) |
(1.84) |
6,313 |
0.02 | ||||||||||||
Adjusted net income (non-GAAP) |
$255,140 |
$ 0.68 |
$153,660 |
$ 0.41 |
$ 6,782 |
$ 0.02 | ||||||||||||
Weighted average diluted shares outstanding |
374,181 |
373,764 |
373,353 |
|||||||||||||||
Adjusted diluted net income per share (non-GAAP) |
$ 0.68 |
$ 0.41 |
$ 0.02 |
(1) Computed by applying a combined federal and state statutory tax rate of 24% in effect for 2018 and 38% in effect for 2017 to the pre-tax amount of adjustments associated with our operations in the United States other than the tax benefit adjustment related to US tax reform legislation. |
Net debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. At March 31, 2018, the Company's net debt amounted to $6.07 billion, representing total debt of $6.17 billion less cash and cash equivalents of $98 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
1Q |
4Q |
1Q | |||||||
In thousands |
2018 |
2017 |
2017 | ||||||
Net income |
$ |
233,946 |
$ |
841,914 |
$ |
469 | |||
Interest expense |
75,894 |
75,823 |
71,172 | ||||||
Provision (benefit) for income taxes |
71,536 |
(608,317) |
6,022 | ||||||
Depreciation, depletion, amortization and accretion |
454,378 |
476,732 |
382,156 | ||||||
Property impairments |
33,784 |
27,552 |
51,372 | ||||||
Exploration expenses |
1,720 |
2,802 |
4,998 | ||||||
Impact from derivative instruments: |
|||||||||
Total gain on derivatives, net |
(10,174) |
(8,417) |
(44,961) | ||||||
Total cash received (paid) on derivatives, net |
4,196 |
15,867 |
(194) | ||||||
Non-cash (gain) loss on derivatives, net |
(5,978) |
7,450 |
(45,155) | ||||||
Non-cash equity compensation |
10,916 |
13,377 |
11,438 | ||||||
Loss on extinguishment of debt |
- |
554 |
- | ||||||
EBITDAX (non-GAAP) |
$ |
876,196 |
$ |
837,887 |
$ |
482,472 | |||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
1Q |
4Q |
1Q | |||||||
In thousands |
2018 |
2017 |
2017 | ||||||
Net cash provided by operating activities |
$ |
886,191 |
$ |
731,125 |
$ |
470,201 | |||
Current income tax provision (benefit) |
- |
(7,781) |
1 | ||||||
Interest expense |
75,894 |
75,823 |
71,172 | ||||||
Exploration expenses, excluding dry hole costs |
1,719 |
2,783 |
4,841 | ||||||
Litigation settlement |
- |
(59,600) |
- | ||||||
Gain (loss) on sale of assets, net |
41 |
54,420 |
(3,638) | ||||||
Other, net |
(4,578) |
723 |
(2,328) | ||||||
Changes in assets and liabilities |
(83,071) |
40,394 |
(57,777) | ||||||
EBITDAX (non-GAAP) |
$ |
876,196 |
$ |
837,887 |
$ |
482,472 |
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures excluding acquisitions and divestitures. Free cash flow is not a measure of net income or cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
The following table reconciles historical net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the first quarter of 2018.
1Q | |||
In thousands |
2018 | ||
Net cash provided by operating activities (GAAP) |
$ |
886,191 | |
Exclude: Changes in working capital items |
(83,071) | ||
Less: Capital expenditures (1) |
(596,304) | ||
Free cash flow (non-GAAP) |
$ |
206,816 | |
(1) Capital expenditures are calculated as follows: |
|||
In thousands |
|||
Cash paid for capital expenditures |
$ |
628,268 | |
Less: Total acquisitions |
(30,575) | ||
Plus: Change in accrued capital expenditures |
(1,389) | ||
Plus: Exploratory seismic costs |
- | ||
Capital expenditures |
$ |
596,304 |
Net sales prices
On January 1, 2018, we adopted Accounting Standards Update 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), which impacted the presentation of our crude oil and natural gas revenues. We adopted the new rules using a modified retrospective transition approach whereby changes have been applied only to the most current period presented and prior period results have not been adjusted to conform to current presentation.
Under the new rules, revenues and transportation expenses associated with the majority of production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning January 1, 2018 the gross presentation of revenues from the majority of our operated properties differs from the net presentation of revenues from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results, and to achieve comparability with prior period metrics for analysis purposes, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three months ended March 31, 2018. Information is also presented for the three months ended March 31, 2017 for comparative purposes.
Three months ended March 31, 2018 |
Three months ended March 31, 2017 | |||||||||||
In thousands |
Crude oil |
Natural gas |
Total |
Crude oil |
Natural gas |
Total | ||||||
Crude oil and natural gas sales (GAAP) |
$906,281 |
$207,571 |
$1,113,852 |
$480,641 |
$153,209 |
$633,850 | ||||||
Less: Transportation expenses |
(40,386) |
(8,911) |
(49,297) |
— |
— |
— | ||||||
Net crude oil and natural gas sales (non-GAAP for 2018) |
$865,895 |
$198,660 |
$1,064,555 |
$480,641 |
$153,209 |
$633,850 | ||||||
Sales volumes (MBbl, MMcf, MBoe) |
14,682 |
66,730 |
25,804 |
10,754 |
51,059 |
19,264 | ||||||
Net sales price (non-GAAP for 2018) |
$58.98 |
$2.98 |
$41.26 |
$44.69 |
$3.00 |
$32.90 |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | ||
2018 Guidance | ||
As of May 2, 2018 | ||
2018 | ||
Full-year average production |
285,000 to 300,000 Boe per day | |
Exit-rate average production |
305,000 to 315,000 Boe per day | |
Capital expenditures (non-acquisition) |
$2.3 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.00 to $3.50 | |
Production tax (% of net oil & gas revenue) |
7.6% to 8.0% | |
Cash G&A expense per Boe(1) |
$1.25 to $1.75 | |
Non-cash equity compensation per Boe |
$0.45 to $0.55 | |
DD&A per Boe |
$17.00 to $19.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($3.50) to ($4.50) | |
Henry Hub natural gas (per Mcf) |
$0.00 to +$0.50 |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.30 per Boe. |
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SOURCE Continental Resources
OKLAHOMA CITY, April 26, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) today announced the execution of a firm transportation agreement on Enable Midstream Partners' (NYSE: ENBL) Project Wildcat. Project Wildcat will provide Continental Resources 400 million cubic feet per day (MMcf/d) of additional takeaway capacity from its properties in the SCOOP and STACK plays in Oklahoma. Project Wildcat will provide Continental direct access to premium markets, including the expanding Dallas Fort Worth area where supplies of natural gas from the Barnett shale continue to decline.
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"We are pleased to continue to expand our relationship with Enable as the anchor shipper on Project Wildcat. Project Wildcat not only provides flow assurance for our growing production in SCOOP and STACK but access to premium markets to maximize the returns on every molecule we sell," said Harold Hamm, Continental's Chairman and Chief Executive Officer.
"Enable has provided midstream solutions for Continental's substantial production growth in Oklahoma since before the SCOOP and STACK were household names," said Rod Sailor, Enable's President and CEO. "We are pleased to build on our relationship and support Continental's future growth with this creative and cost-effective market-access project."
Project Wildcat commences service in June 2018 and is expected to be fully in service in July 2018.
Investor Contact: |
Media Contact: |
Rory Sabino |
Kristin Thomas |
Vice President, Investor Relations |
Senior Vice President, Public Relations |
P/F: 405.234.9620 |
405-234-9480 |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
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SOURCE Continental Resources
OKLAHOMA CITY, April 3, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce first quarter 2018 results on Wednesday, May 2, 2018 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss first quarter 2018 results on Thursday, May 3, 2018 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
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Time and date: 12 p.m. ET, Thursday, May 3, 2018
Dial-in: 844-309-6572
Intl. dial-in: 484-747-6921
Conference ID: 4956858
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: 855-859-2056 or 404-537-3406
Intl. replay: 800-585-8367
Conference ID: 4956858
Continental plans to publish a first quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its conference call on May 3, 2018.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
Rory Sabino |
Kristin Thomas |
Vice President, Investor Relations |
Senior Vice President, Public Relations |
405-234-9620 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-first-quarter-2018-results-on-wednesday-may-2-2018-300623866.html
SOURCE Continental Resources
OKLAHOMA CITY, March 29, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) today announced the forthcoming departure of James L. "Jim" Gallogly from its Board of Directors.
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His departure is in connection with his appointment as president designate of the University of Oklahoma and will be effective at the end of the Annual Meeting of Shareholders of Continental Resources, scheduled for May 17, 2018.
In his letter of resignation, Mr. Gallogly indicated he was resigning from the Board in order to ensure he would be able to devote the necessary time and attention to fulfilling his new duties to the University of Oklahoma.
"We commend Jim on his service to Continental on our Board of Directors and wish him well in his future endeavors," said Harold Hamm.
Investor Contact: |
Media Contact: | |
Rory Sabino |
Kristin Thomas | |
Vice President, Investor Relations |
Senior Vice President, Public Relations | |
P/F: 405.234.9620 |
405-234-9480 | |
Alyson L. Gilbert |
||
Manager, Investor Relations |
||
405-774-5814 |
||
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SOURCE Continental Resources
TULSA, Okla., March 6, 2018 /PRNewswire/ -- Velocity Midstream Partners, LLC ("Velocity") announced that it has completed the construction of a 45-mile, 12" crude oil pipeline loop of its existing condensate pipeline through the fairway of the South Central Oklahoma Oil Province ("SCOOP"). The crude oil loop project is supported by expanded commitments from Continental Resources Inc. (NYSE: CLR), an Oklahoma City-based exploration and production company, and CVR Refining, LP (NYSE: CVRR) ("CVR"). Velocity also announced that it has started construction of a 22-mile, 12" crude oil pipeline extension linking the core of the Merge play to its SCOOP pipeline assets. The Merge pipeline will be placed into operation in April 2018. Along with these new pipelines, Velocity also announced the completion of a Joint Tariff agreement with Plains All American Pipeline, L.P. (NYSE: PAA) ("Plains") providing storage and segregated, batched crude transportation to PAA's Cushing terminal.
In addition to the new pipeline projects and transportation arrangements, Velocity has acquired 100% ownership of all of the truck unloading terminals along its pipelines and has expanded and added terminals to provide attractive locations for SCOOP and Merge producers. Upon completion of its Merge terminal just west of Tuttle, OK, Velocity will have six unloading terminals operating 24/7 across the two plays with segregated unloading and storage for crude oil and condensate. Velocity is in discussions with producers to construct an additional 15-mile pipeline extension and a new terminal in central Canadian County.
Velocity's system is now comprised of 125 miles of pipeline capable of flowing 250,000 barrels per day, along with 395,000 barrels of storage and 26 truck unloading bays capable of unloading greater than 100,000 barrels per day. The new crude oil pipeline enables producers in the SCOOP and Merge to segregate their heavier crude barrels produced from the Springer, Sycamore, Meramec and Woodford oil formations from the lighter barrels being produced from the Woodford condensate formation. These segregated pipelines allow Velocity to transport different quality "neat barrels" from the wellhead to premium markets, thereby preserving the best possible pricing for its producer clients.
Velocity's crude and condensate pipelines lie through the core of the SCOOP and Merge plays, allowing Velocity to provide cost effective gathering solutions to producers regardless of crude gravity. Velocity's pipeline corridor is within 10 miles of more than 20 active producers controlling over 1,000,000 proved gross acres of stacked pay from the Woodford, Springer, Sycamore and Meramec formations. Velocity has engineered a condensate stabilization facility with plans for construction this spring to insure producers are able to continually meet the RVP specifications of downstream pipelines and Cushing purchasers. Producers interested in more information about Velocity's gathering and transportation services should contact Velocity CEO Rick Wilkerson at 918-574-2323.
"Velocity appreciates the continued support of Continental Resources and is honored to be working with CVR and Plains to deliver strong, reliable markets to our producer clients in the SCOOP and Merge. CVR is a highly successful downstream entity with vast expertise in refining and logistics," said Rick Wilkerson, Velocity's Chief Executive Officer. "Further, Plains is the premier crude oil transportation and terminal operator of barrels destined for Cushing, and we are proud to be partnered with them to provide a complete well-to-market transportation solution. The attractiveness of Woodford, Springer, Meramec and Sycamore crude to Midcontinent refiners like CVR, coupled with the reduction in crude gathering and transportation costs, provides the producers in the SCOOP and Merge with the Midcontinent's preeminent market options."
"As a part of CVR's continued focus on expanding its logistics business, we are pleased with our partnership with Velocity and its ability to complete the fully envisioned crude oil pipeline project," said Dave Lamp, Chief Executive Officer of CVR. "Velocity has a proven track record of developing, constructing, and operating high quality midstream assets and gathering systems."
About Velocity Midstream Partners, LLC: Velocity (www.velocitymidstream.com) is an independent midstream service provider that engineers, constructs and operates crude oil and natural gas gathering and transportation solutions. Velocity was formed in 2008 by Rick Wilkerson and Mike Parker. Chief Operating Officer Van Nguyen joined Velocity in 2010. Velocity owns and operates crude oil and condensate pipelines and terminals throughout the SCOOP and Merge basins. Since its inception, Velocity has been financially supported with capital commitments exceeding $300 million through its long-standing partnership with Energy Spectrum Partners (www. EnergySpectrum.com).
About Plains All American Pipeline, LP: Plains All American Pipeline, L.P. is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, natural gas liquids ("NGL") and natural gas. PAA owns an extensive network of pipeline transportation, terminal, storage and gathering assets in key crude oil and NGL producing basins, in transportation corridors and at major market hubs in the United States and Canada. On average, PAA handles over 5 million barrels per day of crude oil and NGL in its Transportation segment. PAA is headquartered in Houston, Texas. More information is available at www.plainsallamerican.com.
About Continental Resources, Inc.: Continental Resources (NYSE: CLR) is a top-15 independent oil producer in the Continental U.S. and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The company also has significant positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations.
SOURCE Velocity Midstream Partners, LLC
OKLAHOMA CITY, Feb. 27, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced it has named Rory R. Sabino as Vice President of Investor Relations, effective March 12, 2018.
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Mr. Sabino has more than two decades of institutional equity experience, most recently serving Bank of America Merrill Lynch (BAML) as a financial advisor and Senior Energy Sector Specialist. Mr. Sabino has more than 13 years of energy sector experience. At BAML, he worked with numerous traders, research analysts and salespeople, in addition to BAML's banking and capital markets teams, developing ideas and cultivating client releationships. He led the firm's messaging across the energy sector. Over the last eight years, he worked closely with Energy Banking teams globally, offering guidance and ideas to the trading desk and clients, and worked with institutional clients across buy-side organizations. He also advised corporate clients on the performance of their equities, as well as intelligence on investor sentiment. Prior to BAML, he worked in various energy and equity roles at ICAP, Citigroup, Hambrecht and Quist, and Salomon Smith Barney. Mr. Sabino maintains his registration with FINRA as a broker.
Mr. Sabino earned a Bachelor of Arts in Political Science from Johns Hopkins University.
"We're very pleased to have Rory join the Continental team," said Harold Hamm, Chairman and Chief Executive Officer. "He brings a depth of knowledge and expertise in communicating with investment professionals about the U.S. energy industry, as well as a passion for exploration and production.
"He's a great match who will serve our shareholders very well," Mr. Hamm said. "It's great to have him on board."
Warren Henry, who established Continental's IR department soon after the Company went public in 2007, is retiring. "Warren has done an outstanding job, and we sincerely appreciate his leadership over these transformative years. We wish Stephanie and Warren and their pup, Winston, all the best in their retirement," said Jack Stark, President. He noted that Mr. Henry will remain with the Company through the end of March to help with the leadership transition.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-rory-r-sabino-as-new-vice-president-for-investor-relations-300605382.html
SOURCE Continental Resources
OKLAHOMA CITY, Feb. 21, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced fourth quarter and full-year 2017 operating and financial results. Continental reported net income of $841.9 million, or $2.25 per diluted share, for the quarter ended December 31, 2017. Of total net income, $128.2 million was from operations and $713.7 million was from federal tax reform. The Company reported full-year net income of $789.4 million, or $2.11 per diluted share, with $75.7 million from operations and $713.7 million from federal tax reform.
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The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In fourth quarter 2017, these typically excluded items in aggregate represented $688.2 million, or $1.84 per diluted share, of Continental's reported net income. Adjusted net income for the fourth quarter was $153.7 million, or $0.41 per diluted share. For full-year 2017, these typically excluded items in aggregate represented $598.6 million, or $1.60 per diluted share. Adjusted net income for full-year 2017 was $190.8 million, or $0.51 per diluted share.
Net cash provided by operating activities for fourth quarter 2017 was $731.1 million, and for full-year 2017 it was $2.1 billion. EBITDAX for fourth quarter 2017 was $837.9 million, contributing to full-year 2017 EBITDAX of $2.4 billion. Definitions and reconciliations of adjusted net income (loss), adjusted net income (loss) per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures can be found in the supporting tables at the conclusion of this press release.
"Continental's fourth quarter performance was a fitting completion to a standout year," said Harold Hamm, Chairman and Chief Executive Officer. "As we made clear in our 2018 guidance announcement, we expect even stronger performance in 2018 with both significant production growth and robust free cash flow."
Full-Year 2017 Production Increases 12% Over 2016
Fourth quarter 2017 net production totaled 26.4 million Boe, or 286,985 Boe per day, up 18% from third quarter 2017, with oil production up 20% to 168,066 barrels of oil (Bo) per day. Compared to fourth quarter 2016, Continental increased production 37%, with oil production up 44%.
Total net production for fourth quarter 2017 included 168,066 Bo per day (59% of production) and 713.5 million cubic feet (MMcf) of natural gas per day (41% of production). Full-year 2017 production averaged 242,637 Boe per day.
First quarter 2018 production is estimated to be between 285,000 and 290,000 Boe per day.
The following table provides the Company's average daily production by region for the periods presented.
4Q |
3Q |
4Q |
FY |
FY |
|||||||
Boe per day |
2017 |
2017 |
2016 |
2017 |
2016 |
||||||
North Region: |
|||||||||||
North Dakota Bakken |
158,640 |
129,582 |
96,035 |
125,577 |
109,686 |
||||||
Montana Bakken |
6,958 |
7,269 |
8,489 |
7,415 |
9,514 |
||||||
Red River Units |
9,497 |
9,536 |
10,140 |
9,748 |
10,745 |
||||||
Other |
468 |
449 |
4,109 |
434 |
1,665 |
||||||
South Region: |
|||||||||||
SCOOP |
62,242 |
57,283 |
63,490 |
60,693 |
65,062 |
||||||
STACK |
47,914 |
35,619 |
24,426 |
36,220 |
16,983 |
||||||
Arkoma(1) |
11 |
1,722 |
1,929 |
1,315 |
1,915 |
||||||
Other |
1,255 |
1,328 |
1,243 |
1,235 |
1,342 |
||||||
Total |
286,985 |
242,788 |
209,861 |
242,637 |
216,912 |
||||||
(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017. |
Bakken Continues to Deliver Record Results
Continental's Bakken net production reached an all-time high in the fourth quarter averaging 165,598 Boe per day, up 58% over the fourth quarter 2016. The Company completed 97 gross (37 net) operated and non-operated Bakken wells with first production during fourth quarter 2017. Thirty-nine of the fourth quarter wells were operated by the Company with an average 24-hour IP of 2,180 Boe per day. The Company completed a total 350 gross (134 net) operated and non-operated Bakken wells with first production for full-year 2017. The Company plans to keep an average of six operated drilling rigs in the play during 2018.
Five of the fourth quarter operated wells produced the highest 30-day rates ever recorded from the Company's operated Bakken wells, averaging 2,230 Boe per day. This included the Monroe 6-2H that produced at an average 30-day rate of 2,869 Boe, which was the best 30-day rate ever achieved by the Company from a Bakken well. All of the wells were completed using the Company's optimized completion designs with various combinations of larger proppant loads, tighter stage spacing and diverter technology, along with accelerated flow backs and high-capacity lift.
From late 2016 through fourth quarter 2017, the Company has brought on 134 optimized Bakken wells in Dunn, McKenzie, Mountrail and Williams counties. Average production per well is slightly outperforming the Company's updated 1,100 MBoe Bakken type curve announced in August 2017. The type curve delivers a 125% rate of return at $60 per barrel WTI (WTI) and $3.00 per Mcf Henry Hub (HH). This more than doubles the rate of return expected from the Company's previous type curve.
"Continental's returns from the Bakken compete head to head with the best oil plays in the U.S. today, driven by our optimized completions, lower production expense and the $4.50 per Bo improvement in oil differentials since 2015," said Jack Stark, President. "On top of that, Bakken production is 80% crude oil."
The Company exited 2017 with a drilled-well inventory of 165 gross operated wells in the Bakken, including 52 gross operated wells with stimulation complete or in progress, but which did not have first sales in 2017.
STACK: Density Tests Defining Unit Development
Continental's STACK net production averaged 47,914 Boe per day in fourth quarter 2017, a 96% increase over fourth quarter 2016. A total of 63 gross (23 net) operated and non-operated STACK wells with first production were completed during the quarter, and 158 gross (52 net) operated and non-operated wells were completed with first production for the full year. The Company plans to keep an average of eight operated drilling rigs in the play during 2018, with four to six targeting the Woodford and Meramec formations as part of the joint development agreement with SK E&S.
The Company is introducing its preliminary economic model for unit development in the STACK Meramec over-pressured oil window. The unit economic model is based on the results of six full-unit density tests the Company has completed with three-to-five wells per zone. Initial results indicate that four wells per zone on average will deliver the maximum PV-10 from a single Meramec reservoir in a unit. The Company's unit economic model includes a total of eight wells with four wells in two Meramec reservoirs given the Company expects to target two Meramec reservoirs on average underlying its acreage in the over-pressured oil window. Combined these eight wells are projected to recover an estimated 9.6 million Boe (MMBoe) and deliver a PV-10 of approximately $87 million with a rate of return of 96%, assuming a completed well cost of $9.5 million for a 9,800-foot lateral well at $60 WTI and $3 HH. In addition, up to four more wells can be expected to be completed in the underlying Woodford formation.
The unit economic model includes results from the Verona and Gillilan density tests that were completed during the fourth quarter. These two units adjoin each other and were strategically selected to compare eight and 10 well density development. The Verona unit included four wells in the Upper and four wells in the Lower Meramec. The eight wells had a combined unit 24-hour IP of 18,205 Boe per day, averaging 2,281 Boe per day per well, and 68% of the production was crude oil. Results for the Verona were in-line with Company expectations. The Gillilan unit included five wells in the Upper and five wells in the Lower Meramec. The 10 wells had a combined unit 24-hour IP of 11,024 Boe per day, averaging 1,102 Boe per day per well, and 64% of the production was crude oil. Early performance from the Gillilan wells indicates the unit was over-drilled with ten wells and further supports the Company's eight-well model.
During the fourth quarter the Company also completed its first density test in the STACK Meramec over-pressured condensate window. The Angus Trust density test involved only half of the unit with three wells drilled in the Upper Meramec and three wells drilled in the Lower Meramec. This is the tightest well spacing Continental has tested to date, which is the equivalent of six wells per zone or 12 wells in the unit. The half-unit 24-hour IP for the Angus Trust test was 15,955 Boe per day and 39% of the production was crude oil. Average IP per well was 2,659 Boe per day. Early performance indicates the maximum PV-10 from a unit can be achieved with fewer than 12 Meramec wells per unit in the over-pressured condensate window. To further evaluate the proper well density, the Company has begun drilling a second density test at the Simba unit located one mile west of the Angus Trust unit. The Simba will be a six-well, full-unit test with three wells in Upper and three wells in the Lower Meramec.
SCOOP
In fourth quarter 2017, SCOOP net production averaged 62,242 Boe per day (23% oil), or 22% of the Company's total production in fourth quarter. A total of 12 gross (1 net) operated and non-operated SCOOP wells were completed with first production during the quarter, and 71 gross (16 net) operated and non-operated wells were completed with first production for the full year. In 2018, the Company plans to average seven operated rigs in the play.
SCOOP Springer: Beginning Full-Field Development; Type Curve EUR Uplifted 28% for Unit Well
Continental has concluded its initial Springer density testing program and is beginning full-field development with five rigs dedicated to the Springer in 2018. The Company has completed three density pilots that tested four, five and six well configurations in the Springer reservoir. Results indicate that on average, four wells should deliver the maximum PV-10 from the Springer reservoir on a unit basis. A Springer unit well is projected to recover 1,200 MBoe at a completed well cost of $9.5 million for a 7,500-foot lateral. This is a 28% uplift in EUR from the Company's legacy 940 MBoe type curve for a 4,500-foot standalone well. The Company's unit economic model projects that a four-well Springer unit will produce a combined 4.8 MMBoe over the life of the wells and generate a PV-10 of approximately $68 million and a rate of return of 175% assuming $60 WTI and $3 HH. This adds approximately $44 million to the PV-10 of a Springer unit compared to a standalone well at $60 WTI and $3 HH.
"Longer laterals and optimized completions in the Springer have doubled our type curve rate of return with $4.0 million incremental first-year gross cash flow per well," said Gary Gould, SVP of Production and Resource Development. "Approximately 20% of Continental's operated drilling and completion capital budget will be focused on the Springer oil play in 2018."
During the fourth quarter, the Company completed its third density pilot with the completion of the six-well Celesta density unit. The six wells flowed at a combined peak 24-hour rate of 6,014 Boe (81% oil). The five new wells produced at an average 24-hour peak production rate of 939 Boe per day. The average lateral length was 9,400 feet for the six wells. Early performance of the Celesta unit wells indicates the maximum PV-10 from a unit can be achieved with fewer than six wells and supports the Company's four-well economic model for a Springer unit.
"We are eager to begin development of this prolific oil reservoir," said Mr. Stark. "Timing is right to take advantage of improved crude prices and our optimized completion technology."
SCOOP Woodford Oil Type Curve Increased Again
The Company announced it has increased the EUR for two-mile lateral wells drilled in the SCOOP Woodford oil window by approximately 13% to 1,520 MBoe per well, with 60% of production being crude oil. The increase in EUR was based on the results of 32 optimized completions conducted over the past several years in the SCOOP Woodford oil window and assumes an average 9,800-foot lateral well. At a targeted completed well cost of $12.7 million per well, this yields a 55% rate of return at $60 WTI and $3.00 HH.
The Company recently completed the Pyle 1-36-25XH in the SCOOP Woodford oil window. The Pyle flowed at a 24-hour IP of 1,812 Boe with 81% of the production being crude oil from a 9,800-foot lateral.
2017 Proved Reserves: Standardized Measure and PV-10 (non-GAAP) Up 90% and 78%, respectively, over Year-End 2016
The Company announced proved reserves of 1.33 billion Boe at December 31, 2017, a 4% increase compared with year-end 2016 proved reserves. The 2017 average SEC oil price was $51.34 per barrel, and the 2017 average SEC natural gas price was $2.98 per MMBtu.
At December 31, 2017, Continental had a Standardized Measure of discounted future net cash flows of $10.47 billion. Continental's 2017 proved reserves had a PV-10 of $11.83 billion, up 78% year-over-year. PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial metric, because it does not include the effects of discounted income taxes on future net revenues of approximately $1.36 billion. Continental and others in the crude oil and natural gas industry use PV-10 to compare the relative size and value of proved reserves without regard to specific income tax characteristics.
Year-end 2017 proved reserves were 48% crude oil, 89% operated by the Company, and approximately 45% were classified as proved developed producing (PDP).
The Bakken accounted for 635.5 MMBoe, or 48% of Continental's year-end 2017 proved reserves. The SCOOP Woodford and SCOOP Springer plays accounted for 491.8 MMBoe, or 37% of Continental's year-end 2017 proved reserves. The STACK accounted for 167.4 MMBoe, or 13% of Continental's year-end 2017 proved reserves.
The Company had a total of 1,783 gross (976 net) proved undeveloped (PUD) locations at year-end 2017, with the Bakken accounting for 1,252 gross (656 net) PUD locations. SCOOP accounted for an additional 336 gross (230 net) PUD locations, while STACK accounted for 195 gross (90 net) PUD locations at year-end 2017.
Financial Update: 4Q 2017 Annualized Net-Debt-to-EBITDAX Ratio below 1.9x
"We were very pleased to finish 2017 in line or better than our guidance," said John Hart, Chief Financial Officer. "Fourth quarter 2017 was excellent from an operations standpoint. Production expense per Boe was down 17% from third quarter 2017, and all other cash operating costs were within budget. This speaks directly to the performance of our operating teams and the premier quality of our assets.
"By year end, long-term debt was $6.35 billion, and our fourth quarter annualized net-debt-to-EBITDAX ratio was 1.88x. We fully expect this to continue to trend down through 2018 as we pay down debt with excess cash flow, sell non-core assets, grow production and reap the benefit of higher commodity prices."
Net debt and EBITDAX are non-GAAP measures. Definitions and reconciliations of these measures to the most directly comparable U.S. GAAP financial measure are provided subsequently under the header "Non-GAAP Financial Measures."
In fourth quarter 2017, Continental's average realized sales price excluding the effects of derivative positions was $51.16 per barrel of oil and $3.30 per Mcf of gas, or $38.27 per Boe. Based on realizations without the effect of derivatives, the Company's fourth quarter 2017 oil differential was $4.23 per barrel below the NYMEX daily average for the period. The realized wellhead natural gas price for the quarter was on average $0.37 per Mcf above the average NYMEX Henry Hub benchmark price.
The corporate oil differential has improved by $2.86 per Bo from first quarter 2017, and the corporate gas differential has improved by $0.66 per Mcf. These trends reflect improved takeaway capacity in both the Bakken and Oklahoma as well as improving natural gas liquids pricing. The Company is expecting crude oil differentials to continue to improve in 2018 due to a recent renegotiation of an existing transportation contract at more favorable rates and terms, which should impact the Company's cash flow growth considerably.
Production expense per Boe was $3.17 for fourth quarter 2017, down a remarkable 17% compared with $3.82 per Boe for third quarter 2017. This improvement was primarily driven by reduced water handling and disposal costs from increased recycling activities in Oklahoma, reduced workover activity and the increase in production quarter over quarter. Other select operating costs and expenses for fourth quarter 2017 included production taxes of 7.3% of oil and natural gas sales; DD&A of $17.93 per Boe; and total G&A of $2.30 per Boe.
As of December 31, 2017, Continental's balance sheet included $43.9 million in cash and cash equivalents and $188 million of borrowings against the Company's revolving credit facility. At year-end 2017 Continental's long-term debt was $6.35 billion, down $261 million from September 30, 2017. As of January 31, 2018 Continental's long-term debt was down another $95 million to $6.26 billion.
Continental's 2018 guidance remains as announced on February 15, 2018 and can be found at the conclusion of this press release.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended December 31, |
Year ended December 31, | ||||||
2017 |
2016 |
2017 |
2016 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
168,066 |
116,486 |
138,455 |
128,005 | |||
Natural gas (Mcf per day) |
713,518 |
560,251 |
625,093 |
533,442 | |||
Crude oil equivalents (Boe per day) |
286,985 |
209,861 |
242,637 |
216,912 | |||
Average sales prices, excluding effect from derivatives: |
|||||||
Crude oil ($/Bbl) |
$51.16 |
$42.23 |
$45.70 |
$35.51 | |||
Natural gas ($/Mcf) |
$3.30 |
$2.70 |
$2.93 |
$1.87 | |||
Crude oil equivalents ($/Boe) |
$38.27 |
$30.64 |
$33.65 |
$25.55 | |||
Production expenses ($/Boe) |
$3.17 |
$3.60 |
$3.66 |
$3.65 | |||
Production taxes (% of oil and gas revenues) |
7.3% |
6.4% |
7.0% |
7.0% | |||
DD&A ($/Boe) |
$17.93 |
$20.11 |
$18.89 |
$21.54 | |||
Total general and administrative expenses ($/Boe) (1) |
$2.30 |
$2.93 |
$2.16 |
$2.14 | |||
Net income (loss) (in thousands) (2) |
$841,914 |
$27,670 |
$789,447 |
($399,679) | |||
Diluted net income (loss) per share (2) |
$2.25 |
$0.07 |
$2.11 |
($1.08) | |||
Adjusted net income (loss) (non-GAAP) (in thousands) (3) |
$153,660 |
($27,416) |
$190,803 |
($326,648) | |||
Adjusted diluted net income (loss) per share (non-GAAP) (3) |
$0.41 |
($0.07) |
$0.51 |
($0.88) | |||
Net cash provided by operating activities |
$731,125 |
$262,031 |
$2,079,106 |
$1,125,919 | |||
EBITDAX (non-GAAP) (in thousands) (3) |
$837,887 |
$652,382 |
$2,363,617 |
$1,881,889 | |||
(1) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.80, $2.21, $1.64, and $1.53 for 4Q 2017, 4Q 2016, FY 2017 and FY 2016, respectively. Non-cash equity compensation expense per Boe was $0.50, $0.72, $0.52, and $0.61 for 4Q 2017, 4Q 2016, FY 2017 and FY 2016, respectively. |
|||||||||||||||
(2) In December 2017, the Tax Cuts and Jobs Act was signed into law, which among other things reduces the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate, which resulted in a one-time increase in net income of approximately $713.7 million ($1.91 per diluted share) for the three and twelve months ended December 31, 2017. |
|||||||||||||||
(3) Adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or net cash provided by operating activities as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Fourth Quarter and Full-Year Earnings Conference Call
Continental plans to host a conference call to discuss fourth quarter and full-year results on Thursday, February 22, 2018, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, February 22, 2018 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
9287808 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
9287808 |
Continental plans to publish a fourth quarter and full-year 2017 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 22, 2018.
Upcoming Conferences
Members of Continental's management team plan to participate in the following investment conferences:
Feb 28–Mar 2, 2018 |
18th Annual Simmons/Piper Jaffray Energy Conference, Las Vegas |
March 13, 2018 |
Evercore ISI Energy/Power Summit 2018, Houston |
March 26-27, 2018 |
Scotia Howard Weil 46th Annual Energy Conference, New Orleans |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2016, and once filed, for the year ended December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||||||
Consolidated Statements of Income (Loss) | |||||||
Three months ended December 31, |
Year ended December 31, | ||||||
2017 |
2016 |
2017 |
2016 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 1,017,750 |
$ 591,764 |
$ 2,982,966 |
$ 2,026,958 | |||
Gain (loss) on crude oil and natural gas derivatives, net |
8,165 |
(47,382) |
91,647 |
(71,859) | |||
Crude oil and natural gas service operations |
21,257 |
5,307 |
46,215 |
25,174 | |||
Total revenues |
1,047,172 |
549,689 |
3,120,828 |
1,980,273 | |||
Operating costs and expenses: |
|||||||
Production expenses |
84,371 |
69,544 |
324,214 |
289,289 | |||
Production taxes |
73,816 |
38,172 |
208,278 |
142,388 | |||
Exploration expenses |
2,802 |
8,246 |
12,393 |
16,972 | |||
Crude oil and natural gas service operations |
6,216 |
2,162 |
16,880 |
11,386 | |||
Depreciation, depletion, amortization and accretion |
476,732 |
388,321 |
1,674,901 |
1,708,744 | |||
Property impairments |
27,552 |
34,564 |
237,370 |
237,292 | |||
General and administrative expenses |
61,294 |
56,537 |
191,706 |
169,580 | |||
Litigation settlement |
59,600 |
- |
59,600 |
- | |||
Net gain on sale of assets and other |
(54,679) |
(203,156) |
(53,915) |
(307,844) | |||
Total operating costs and expenses |
737,704 |
394,390 |
2,671,427 |
2,267,807 | |||
Income (loss) from operations |
309,468 |
155,299 |
449,401 |
(287,534) | |||
Other income (expense): |
|||||||
Interest expense |
(75,823) |
(75,613) |
(294,495) |
(320,562) | |||
Loss on extinguishment of debt |
(554) |
(26,055) |
(554) |
(26,055) | |||
Other |
506 |
517 |
1,715 |
1,697 | |||
(75,871) |
(101,151) |
(293,334) |
(344,920) | ||||
Income (loss) before income taxes |
233,597 |
54,148 |
156,067 |
(632,454) | |||
(Provision) benefit for income taxes |
608,317 |
(26,478) |
633,380 |
232,775 | |||
Net income (loss) |
$ 841,914 |
$ 27,670 |
$ 789,447 |
$ (399,679) | |||
Basic net income (loss) per share |
$ 2.27 |
$ 0.07 |
$ 2.13 |
$ (1.08) | |||
Diluted net income (loss) per share |
$ 2.25 |
$ 0.07 |
$ 2.11 |
$ (1.08) |
Continental Resources, Inc. and Subsidiaries | |||||
Consolidated Balance Sheets | |||||
December 31, 2017 |
December 31, 2016 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
1,251,725 |
$ |
913,233 | |
Net property and equipment (1) |
12,933,789 |
12,881,227 | |||
Other noncurrent assets |
14,137 |
17,316 | |||
Total assets |
$ |
14,199,651 |
$ |
13,811,776 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
1,330,242 |
$ |
932,393 | |
Long-term debt, net of current portion |
6,351,405 |
6,577,697 | |||
Other noncurrent liabilities |
1,386,801 |
1,999,690 | |||
Total shareholders' equity |
5,131,203 |
4,301,996 | |||
Total liabilities and shareholders' equity |
$ |
14,199,651 |
$ |
13,811,776 | |
(1) Balance is net of accumulated depreciation, depletion and amortization of $9.08 billion and $7.65 billion as of December 31, 2017 and December 31, 2016, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||||||
Consolidated Statements of Cash Flows | ||||||||||||
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net income (loss) |
$ |
841,914 |
$ |
27,670 |
$ |
789,447 |
$ |
(399,679) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
(70,395) |
369,093 |
1,288,244 |
1,687,814 | ||||||||
Changes in assets and liabilities |
(40,394) |
(134,732) |
1,415 |
(162,216) | ||||||||
Net cash provided by operating activities |
731,125 |
262,031 |
2,079,106 |
1,125,919 | ||||||||
Net cash (used in) provided by investing activities |
(434,591) |
17,256 |
(1,808,845) |
(532,965) | ||||||||
Net cash used in financing activities |
(263,395) |
(282,132) |
(243,034) |
(587,773) | ||||||||
Effect of exchange rate changes on cash |
(2) |
(8) |
32 |
(1) | ||||||||
Net change in cash and cash equivalents |
33,137 |
(2,853) |
27,259 |
5,180 | ||||||||
Cash and cash equivalents at beginning of period |
10,765 |
19,496 |
16,643 |
11,463 | ||||||||
Cash and cash equivalents at end of period |
$ |
43,902 |
$ |
16,643 |
$ |
43,902 |
$ |
16,643 |
Non-GAAP Financial Measures
PV-10
The Company's PV-10 value, a non-GAAP financial measure, is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, 2017, the Company's PV-10 totaled approximately $11.83 billion. The Standardized Measure of discounted future net cash flows was approximately $10.47 billion at December 31, 2017, representing a $1.36 billion difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at the Standardized Measure. The Company believes the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of the Company's proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company's crude oil and natural gas properties.
Net debt
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. At December 31, 2017, the Company's net debt amounted to $6.31 billion, representing total debt of $6.35 billion less cash and cash equivalents of $0.04 billion.
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net income (loss) |
$ |
841,914 |
$ |
27,670 |
$ |
789,447 |
$ |
(399,679) | ||||
Interest expense |
75,823 |
75,613 |
294,495 |
320,562 | ||||||||
Provision (benefit) for income taxes |
(608,317) |
26,478 |
(633,380) |
(232,775) | ||||||||
Depreciation, depletion, amortization and accretion |
476,732 |
388,321 |
1,674,901 |
1,708,744 | ||||||||
Property impairments |
27,552 |
34,564 |
237,370 |
237,292 | ||||||||
Exploration expenses |
2,802 |
8,246 |
12,393 |
16,972 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total (gain) loss on derivatives, net |
(8,417) |
45,331 |
(90,432) |
67,099 | ||||||||
Total cash received on derivatives, net |
15,867 |
6,281 |
32,401 |
89,522 | ||||||||
Non-cash (gain) loss on derivatives, net |
7,450 |
51,612 |
(58,031) |
156,621 | ||||||||
Non-cash equity compensation |
13,377 |
13,823 |
45,868 |
48,097 | ||||||||
Loss on extinguishment of debt |
554 |
26,055 |
554 |
26,055 | ||||||||
EBITDAX (non-GAAP) |
$ |
837,887 |
$ |
652,382 |
$ |
2,363,617 |
$ |
1,881,889 |
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net cash provided by operating activities |
$ |
731,125 |
$ |
262,031 |
$ |
2,079,106 |
$ |
1,125,919 | ||||
Current income tax benefit |
(7,781) |
(22,941) |
(7,781) |
(22,939) | ||||||||
Interest expense |
75,823 |
75,613 |
294,495 |
320,562 | ||||||||
Exploration expenses, excluding dry hole costs |
2,783 |
3,613 |
12,217 |
12,106 | ||||||||
Litigation settlement |
(59,600) |
- |
(59,600) |
- | ||||||||
Gain on sale of assets, net |
54,420 |
201,315 |
55,124 |
304,489 | ||||||||
Tax deficiency from stock-based compensation |
- |
(368) |
- |
(9,828) | ||||||||
Other, net |
723 |
(1,613) |
(8,529) |
(10,636) | ||||||||
Changes in assets and liabilities |
40,394 |
134,732 |
(1,415) |
162,216 | ||||||||
EBITDAX (non-GAAP) |
$ |
837,887 |
$ |
652,382 |
$ |
2,363,617 |
$ |
1,881,889 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, losses on certain litigation settlements, gains and losses on asset sales, losses on extinguishment of debt and the impact of U.S. tax reform legislation. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended December 31, | ||||||||
2017 |
2016 | |||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||
Net income (GAAP) |
$841,914 |
$ 2.25 |
$ 27,670 |
$ 0.07 | ||||
Adjustments: |
||||||||
Non-cash loss on derivatives |
7,450 |
51,612 |
||||||
Property impairments |
27,552 |
34,564 |
||||||
Litigation settlement |
59,600 |
- |
||||||
Gain on sale of assets |
(54,420) |
(201,315) |
||||||
Loss on extinguishment of debt |
554 |
26,055 |
||||||
Total tax effect of adjustments (1) |
(15,335) |
33,998 |
||||||
Tax benefit from US tax reform legislation |
(713,655) |
- |
||||||
Total adjustments, net of tax |
(688,254) |
(1.84) |
(55,086) |
(0.14) | ||||
Adjusted net income (loss) (non-GAAP) |
$153,660 |
$ 0.41 |
$ (27,416) |
$ (0.07) | ||||
Weighted average diluted shares outstanding |
373,764 |
370,539 |
||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ 0.41 |
$ (0.07) |
||||||
Year ended December 31, | ||||||||
2017 |
2016 | |||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||
Net income (loss) (GAAP) |
$789,447 |
$ 2.11 |
$(399,679) |
$ (1.08) | ||||
Adjustments: |
||||||||
Non-cash (gain) loss on derivatives |
(58,031) |
156,621 |
||||||
Property impairments |
237,370 |
237,292 |
||||||
Litigation settlement |
59,600 |
- |
||||||
Gain on sale of assets |
(55,124) |
(304,489) |
||||||
Loss on extinguishment of debt |
554 |
26,055 |
||||||
Total tax effect of adjustments (1) |
(69,358) |
(42,448) |
||||||
Tax benefit from US tax reform legislation |
(713,655) |
- |
||||||
Total adjustments, net of tax |
(598,644) |
(1.60) |
73,031 |
0.20 | ||||
Adjusted net income (loss) (non-GAAP) |
$190,803 |
$ 0.51 |
$(326,648) |
$ (0.88) | ||||
Weighted average diluted shares outstanding |
373,768 |
370,380 |
||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ 0.51 |
$ (0.88) |
||||||
(1) Computed by applying a combined federal and state statutory tax rate of 38% in effect for 2017 and 2016 to the pre-tax amount of adjustments associated with our operations in the United States other than the tax benefit adjustment related to US tax reform legislation. |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures excluding acquisitions and divestitures. Free cash flow is not a measure of net income (loss) or cash flows as determined by U.S. GAAP. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Continental Resources, Inc. |
|||
2018 Guidance |
|||
As of February 21, 2018 |
|||
2018 |
|||
Full-year average production |
285,000 to 300,000 Boe per day |
||
Exit-rate average production |
305,000 to 315,000 Boe per day |
||
Capital expenditures (non-acquisition) |
$2.3 billion |
||
Operating Expenses: |
|||
Production expense per Boe |
$3.00 to $3.50 |
||
Production tax (% of oil & gas revenue) |
7.6% to 8.0% |
||
Cash G&A expense per Boe(1) |
$1.25 to $1.75 |
||
Non-cash equity compensation per Boe |
$0.45 to $0.55 |
||
DD&A per Boe |
$17.00 to $19.00 |
||
Average Price Differentials: |
|||
NYMEX WTI crude oil (per barrel of oil) |
($3.50) to ($4.50) |
||
Henry Hub natural gas (per Mcf) |
$0.00 to +$0.50 |
||
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.30 per Boe. |
View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-fourth-quarter-and-full-year-2017-results-300602293.html
SOURCE Continental Resources
OKLAHOMA CITY, Feb. 15, 2018 /PRNewswire/ --
2017 Preliminary Results:
2018 Projected Capital Budget and Guidance:
Continued Improvement in 2018 Differentials and Operating Expenses Expected:
Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced a 2018 capital expenditures budget of $2.3 billion, which is focused on both strong free cash flow generation and strong annual production growth to approximately 285,000 to 300,000 Boe per day, with a 2018 exit rate of 305,000 to 315,000 Boe per day. Crude oil is projected to range between 57% and 60% of production throughout 2018, varying through the year due to the timing of large pad projects coming online.
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The 2018 capital budget is projected to generate $3.0 to $3.2 billion of cash flow from operations and $800 to $900 million of free cash flow for full-year 2018 at $60 WTI and $3.00 Henry Hub. There are currently no oil hedges in place, allowing the Company to fully participate in the upside of oil prices. Natural gas is hedged in excess of 80% of production for the remainder of the year at an average price of $2.88. Continental also noted that the capital budget is expected to be cash neutral at a WTI price in the low-to-mid-$40's. A $5 change in WTI is estimated to impact annual cash flow by $250 to $300 million, and a $0.10 change in Henry Hub is estimated to impact annual cash flow by $5 to $10 million. Free cash flow and cash G&A used herein are non-GAAP measures. See "Non-GAAP Measures" and the guidance table at the end of this press release for definitions and reconciliations of these measures to the most comparable U.S. GAAP financial measures.
Of the total $2.3 billion budget, the Company is allocating approximately $2.0 billion to drilling and completion (D&C) activities, with approximately 78% of the D&C budget focusing on the oil-weighted Bakken and SCOOP Springer assets. Approximately $500 million of the 2018 D&C capital reflects activities that will generate first production in 2019. The non-D&C capital is planned to be primarily focused on leasehold, workovers and facilities.
The Company experienced improved differentials and lower production expenses on a per Boe basis in fourth quarter 2017. These trends are projected to continue in 2018. Oil differentials are expected to be in a range of ($3.50) to ($4.50) per Bo, and natural gas differentials are expected to be $0.00 to a positive $0.50 per Mcf. Production expense is expected to be between $3.00 and $3.50 per Boe, and total G&A is expected to be between $1.70 and $2.30 per Boe.
"This year Continental expects to set itself apart by generating up to $900 million of free cash flow while delivering top-tier production growth," said Harold Hamm, Chairman and Chief Executive Officer. "We plan to use the majority of this excess cash to continue paying down debt, further strengthening our balance sheet and increasing shareholder value. We are focused on returns and expect, at a WTI price of $60, that our ROCE will be 10% to 15%, which is expected to be among the industry's best."
Year-End 2017 Update
Fourth quarter 2017 production averaged 286,985 Boe per day, with 59% of the production being oil. Oil production grew 20% compared to third quarter 2017. Full-year 2017 production averaged 242,637 Boe per day, up 12% over full-year 2016. Year-end long-term debt was approximately $6.35 billion, down $261 million from September 30, 2017, reflecting the application of cash flow and divestiture proceeds. As of January 31, 2018, Continental's long-term debt was down another $95 million to $6.26 billion.
As a reminder, the entire fourth quarter and full-year 2017 results will be announced on Wednesday, February 21, 2018 following the close of trading on the New York Stock Exchange with a conference call on Thursday, February 22, 2018 at 12:00 p.m. ET (11:00 a.m. CT). Details can be found at www.CLR.com.
2018 Operating Plan
In the Bakken, the Company plans to average six operated drilling rigs throughout 2018 and drill approximately 142 gross operated wells. The Company has six stimulation crews working currently and plans to average 6.5 crews in 2018, while completing 187 gross (113 net) operated wells.
During the year the Company plans to work down its inventory of drilled but not producing wells, and at year-end 2018, the Company expects to have 120 gross operated Bakken wells in progress in various stages of completion, of which 44 gross wells will have been completed but waiting on first sales. This compares to 165 gross operated wells in progress at year-end 2017. With six drilling rigs and an average pad size of six to seven wells, the projected 2018 year-end level of 120 gross operated wells in progress is considered a normal working backlog.
In Oklahoma, Continental plans to operate an average of 15 drilling rigs during 2018, of which eight rigs will be in STACK targeting the Meramec and Woodford formations, and seven rigs will be in the SCOOP play primarily targeting the Springer and Woodford formations. Five of the SCOOP rigs will be focused on the Springer as the Company begins full-field development of this oil reservoir. The Company expects to complete 118 gross (69 net) operated wells in Oklahoma with first production in 2018, including 72 gross (33 net) operated wells in STACK and other, 31 (26 net) operated wells in SCOOP Springer and 15 gross (10 net) operated wells in SCOOP Woodford/Sycamore. The Company plans to average four to five completion crews in Oklahoma during 2018.
Early Outlook for 2019
For 2019, the Company currently expects production to grow 15% to 20% year over year with a capital budget of $2.5 to $2.8 billion, while generating significant free cash flow comparable to 2018 projections.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2018, the Company will celebrate 51 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2016, and once filed, for the year ending December 31, 2017, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Non-GAAP Measures
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures excluding acquisitions and divestitures. Free cash flow is not a measure of net income (loss) or cash flows as determined by U.S. GAAP. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. This press release includes forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
2018 Guidance Table | ||
Continental Resources, Inc. | ||
2018 Guidance | ||
As of February 15, 2018 | ||
2018 | ||
Full-year average production |
285,000 to 300,000 Boe per day | |
Exit-rate average production |
305,000 to 315,000 Boe per day | |
Capital expenditures (non-acquisition) |
$2.3 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.00 to $3.50 | |
Production tax (% of oil & gas revenue) |
7.6% to 8.0% | |
Cash G&A expense per Boe(1) |
$1.25 to $1.75 | |
Non-cash equity compensation per Boe |
$0.45 to $0.55 | |
DD&A per Boe |
$17.00 to $19.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($3.50) to ($4.50) | |
Henry Hub natural gas (per Mcf) |
$0.00 to +$0.50 | |
(1) |
Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.30 per Boe. |
Continental Resources, Inc. | ||||||
2018 Non-Acquisition Capital Expenditures | ||||||
The following table provides the breakout of non-acquisition capital expenditures: |
||||||
($ in millions) |
Bakken |
SCOOP |
STACK |
SCOOP |
Exploration |
Leasehold, |
CAPEX |
$1,187 |
$355 |
$312 |
$110 |
$24 |
$312 |
Continental Resources, Inc. | ||||
2018 Operational Detail | ||||
The following table provides additional operational detail for the 2018 budget: | ||||
2018 wells with first production | ||||
Basin |
Average |
Gross |
Net |
Total Net |
Bakken |
6 |
187 |
113 |
143 |
SCOOP Springer |
5 |
31 |
26 |
32 |
SCOOP Woodford / Sycamore |
2 |
15 |
10 |
12 |
STACK & Other |
8 |
72 |
33 |
38 |
Totals |
21 |
305 |
182 |
225 |
1) Represents projected net operated and non-operated wells |
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-preliminary-2017-results-and-2018-capital-budget-300599798.html
SOURCE Continental Resources
OKLAHOMA CITY, Dec. 4, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today the pricing of its private placement of $1 billion of new 4 3/8% senior unsecured notes due 2028. The notes were sold at par. The offering is expected to close on December 8, 2017, subject to customary closing conditions. Continental intends to use the net proceeds from this offering to repay in full and terminate its $500 million term loan and to repay a portion of the borrowings outstanding under its revolving credit facility.
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The securities offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The senior unsecured notes are expected to be eligible for trading by qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S.
This press release is being issued pursuant to Rule 135c under the Securities Act, and is neither an offer to sell nor a solicitation of an offer to buy the notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, expectations regarding the completion of the notes offering and the use of proceeds therefrom are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to the risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contact: |
Media Contact: | |
J. Warren Henry |
Kristin Thomas | |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations | |
405-234-9127 |
405-234-9480 | |
Alyson L. Gilbert |
||
Manager, Investor Relations |
||
405-774-5814 |
||
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-pricing-of-1-billion-offering-of-new-senior-notes-due-2028-300566189.html
SOURCE Continental Resources
OKLAHOMA CITY, Dec. 4, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") announced today that, subject to market conditions, it intends to offer a series of senior notes due 2028 in a private placement to eligible purchasers. Continental intends to use the net proceeds from this offering to repay in full and terminate its $500 million term loan and to repay a portion of the borrowings outstanding under its current revolving credit facility.
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The securities to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The senior unsecured notes are expected to be eligible for trading by qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S.
This press release is being issued pursuant to Rule 135c under the Securities Act, and is neither an offer to sell nor a solicitation of an offer to buy the notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, expectations regarding the completion of the notes offering and the use of proceeds therefrom are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to the risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-announces-private-offering-of-new-senior-notes-due-2028-300565818.html
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 15, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced its second international sale of Bakken crude oil. The Company plans to sell 430,000 barrels of oil (Bo) for January delivery to international markets. The sale transaction will take place in Cushing, Oklahoma.
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This follows Continental's October announcement of the sale of 1,005,000 barrels of Bakken crude oil to Atlantic Trading and Marketing, which intends to export the oil to China.
"International markets are demonstrating accelerated interest in American light sweet oil, and Continental is currently negotiating additional potential sales," said Harold Hamm, Continental's Chairman and Chief Executive Officer. "This is the new reality of the United States as a world energy leader."
In December 2015 the U.S. lifted its ban on oil exports, allowing foreign sales to be transacted without a license. Oil exports have grown steadily in the past two years, primarily to foreign refineries configured specifically to process light sweet crude oil.
"We expect steady U.S. production and increasing international sales will drive down U.S. inventories and help correct the recent disparity between Brent and WTI prices," Mr. Hamm said. "Increasing export volumes will also help reduce America's foreign trade deficit."
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-second-international-sale-of-bakken-oil-300557160.html
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 7, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced third quarter operating and financial results. Continental reported net income of $10.62 million, or $0.03 per diluted share, for the quarter ended September 30, 2017.
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The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In third quarter 2017, these typically excluded items in aggregate represented $21.54 million, or $0.06 per diluted share, which reduced Continental's reported net income. Adjusted net income for the third quarter was $32.16 million, or $0.09 per diluted share.
Net cash provided by operating activities for third quarter 2017 was $431.4 million. EBITDAX for third quarter 2017 was $563.8 million. Definitions and reconciliations of adjusted net income (loss), adjusted net income (loss) per share, EBITDAX and cash G&A expense to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables and 2017 guidance summary at the conclusion of this press release.
"Continental's performance year-to-date demonstrates industry leadership in capital disciplined production growth," said Harold Hamm, Chairman and Chief Executive Officer. "Continental's operations continue to become more capital efficient each quarter, allowing us to sustain our low-cost advantage. Additionally, due to continued strong well performance in all of our plays, we are raising our exit rate production guidance to 280,000 to 290,000 Boe per day, a 33% to 38% increase over fourth quarter 2016. This positions us for strong, cash-flow-positive growth in 2018."
Crude Oil Represents 58% of Third Quarter Total Production
Third quarter 2017 net production totaled 22.3 million Boe, or 242,788 Boe per day, up 7% over second quarter 2017. Crude oil production was 140,611 Bo per day, or 58% of production, for third quarter 2017, a 12% increase over second quarter. Natural gas production averaged 613.1 million cubic feet (MMcf) per day, or 42% of production.
Third quarter production was negatively impacted in September by unusually rainy weather in the Bakken as well as midstream curtailments in Oklahoma associated with Hurricane Harvey. The net impact on third quarter production was a reduction of approximately 3,500 Boe per day. Apart from these two events, estimated production for the third quarter would have been in excess of 246,000 Boe per day. October production is estimated to be in excess of 275,000 Boe per day, with 59% being oil.
Fourth quarter average daily oil production is expected to be 14% to 18% higher than third quarter. Total fourth quarter 2017 production is expected to be in a range of 275,000 to 285,000 Boe per day, and the 2017 exit rate production is now expected to be in a range of 280,000 to 290,000 Boe per day. Full-year 2017 production is expected to be in a range of 238,000 to 242,000 Boe per day.
The Company's full 2017 guidance is stated in a table at the conclusion of the release.
The following table provides the Company's average daily production by region for the periods presented.
3Q |
2Q |
3Q |
YTD |
YTD | ||||||
Boe per day |
2017 |
2017 |
2016 |
2017 |
2016 | |||||
North Region: |
||||||||||
North Dakota Bakken |
129,582 |
112,397 |
99,251 |
114,435 |
114,269 | |||||
Montana Bakken |
7,269 |
7,464 |
8,678 |
7,569 |
9,858 | |||||
Red River Units |
9,536 |
9,878 |
10,475 |
9,832 |
10,949 | |||||
Other |
449 |
483 |
1,189 |
422 |
845 | |||||
South Region: |
||||||||||
SCOOP |
57,283 |
61,107 |
67,462 |
60,171 |
65,589 | |||||
STACK |
35,619 |
31,934 |
17,680 |
32,280 |
14,484 | |||||
Arkoma(1) |
1,722 |
1,788 |
1,833 |
1,755 |
1,911 | |||||
Other |
1,328 |
1,162 |
1,272 |
1,228 |
1,375 | |||||
Total |
242,788 |
226,213 |
207,840 |
227,692 |
219,280 |
(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017. |
Bakken: Increasing Value Through Technology
Continental's Bakken net production averaged 136,851 Boe per day in third quarter 2017, a 14% increase over second quarter 2017 production. The Company completed 122 gross (58 net) operated and non-operated Bakken wells during the quarter. The Company currently has four operated drilling rigs and four stimulation crews active in the Bakken. At September 30, 2017, the Company had 172 gross operated drilled but uncompleted or completed but not producing wells (DUCs). The Company expects to end 2017 with approximately 150 DUCs in inventory.
In the third quarter, the Company had 57 gross operated wells with first production, with an average 24-hour IP rate of 1,752 Boe per day (80% oil). Fifteen of the wells posted 24-hour IP rates of more than 2,000 Boe per day. All of the wells were completed using the Company's optimized completion technology that includes various combinations of larger proppant loads, tighter stage spacing and diverters, along with accelerated flow backs and high-capacity lift. Through third quarter 2017, the Company has brought on over 100 Bakken optimized wells, and their average production is in line with and slightly outperforming the Company's updated Bakken type curve announced last quarter. The new 1,100 MBoe Bakken type curve includes a 12% uplift in estimated ultimate recovery (EUR) and doubles the expected rate of return to 82% at $50 WTI, compared with the Company's previous type curve. The increased type curve yields approximately $2 million of gross incremental cash flow per well during the first year, cutting payouts in half to approximately 15 months per well.
"Our optimized completions are unlocking more value from our Bakken assets than ever before," said Jack Stark, President. "This is a key catalyst that will drive our ability to deliver cash-flow-positive, oil-weighted growth for years to come."
The Company also continued to improve key Bakken operating metrics during the third quarter. Average spud-to-total-depth drilling time for the third quarter was 10.5 days, a quarter-over-quarter improvement of 8% and an improvement of 27% compared with 2016's average drilling time. As a result, average drilling cost per well was down nearly 6% from the second quarter and approximately 25% below the 2016 average.
STACK: Over-Pressured Oil Window Density Test Delivers Strong Results
Continental's STACK net production averaged 35,619 Boe per day in third quarter 2017, a 12% increase over second quarter 2017. The Company completed 32 gross (15.2 net) operated and non-operated STACK wells during the quarter. The Company currently has nine operated drilling rigs in the play, with six of the rigs targeting the Woodford and Meramec formations as part of the joint development agreement with SK E&S.
The Company recently began flowing back a new Meramec density test in the over-pressured oil window of STACK at the Compton unit. The Compton was a 10-well density unit, with five new wells in the upper Meramec and four new wells and one parent well in the lower Meramec. Average lateral length was approximately 10,200 feet per well. The 10 wells flowed at a combined peak 24-hour rate of 22,032 Boe (75% oil) or 2,203 Boe per day per well. Early performance shows the wells on average are performing in line with the Company's oil window type curve of 1.7 MMBoe. Average completed well cost for the nine new Compton wells was approximately $9.2 million, down approximately 28% from the cost of the parent well.
The Company also reported results from seven operated standalone wells in the STACK Meramec over-pressured oil and condensate windows. The average 24-hour IPs for the seven wells was 3,736 Boe per day (40% oil) from an average 8,387-foot lateral.
Three notable wells were the R Moore 1-24H, the Edward Lee 1-13-12XH and the Lorene 1-8-5XH. The R Moore had an impressive 24-hour IP of 3,565 Boe per day (71% oil) from a 4,890-foot lateral. The Edward Lee had a 24-hour IP of 1,857 Boe per day (3% oil) from a 9,725-foot lateral. The Edward Lee is the Company's first Meramec well in Dewey County, and it's the farthest west Meramec completion to date for Continental. These two wells had flowing casing pressures of 3,800 and 4,500 pounds per square inch (psi), respectively.
The Lorene 1-8-5XH well was recently completed, setting a new 24-hour initial rate record for horizontal wells in Oklahoma. The Lorene produced at a maximum 24-hour flow rate of 1,863 barrels of oil and 29.1 MMcf per day, or 6,715 MBoe, at 5,575 psi flowing casing pressure from a 10,200-foot lateral. This exceeds the record rate previously announced by the Company from the Tres C FIU 1-35-2XH. The Tres C produced at an average rate of 5,345 Boe per day in its first 30 days and is currently producing approximately 3,600 Boe per day with a flowing casing pressure of 3,375 psi. The Lorene is located two miles east of the Tres C well in Blaine County.
SCOOP Woodford: Oklahoma Record Unit Production from Sympson Density Test
In third quarter 2017, SCOOP net production averaged 57,283 Boe per day (26% oil). Continental had 30 gross (7.1 net) operated and non-operated wells completed during third quarter 2017. Continental currently has five operated drilling rigs working in SCOOP, targeting the Springer, Sycamore and Woodford formations.
Continental recently completed its third 10-well pattern density project in the SCOOP Woodford condensate window, setting an Oklahoma record for an initial rate reported from a drilling spacing unit. The Sympson unit flowed at a combined peak 24-hour rate of 4,652 Bo and 222.3 MMcf per day (41,701 Boe per day).
The Sympson unit is a two-mile long, dual-zone, 10-well pattern unit that includes a total of 14 wells. Two one-mile parent wells and 12 children wells of various lengths were required to fill in the 10-well 1,280-acre unit pattern. This resulted in the equivalent of 5 wells in the Upper Woodford and 5 wells in the Lower Woodford. The 12 new wells produced at an average 24-hour peak production rate of 3,145 Boe per day (11% oil), and on average the wells are performing in line with the 2.3 MMBoe type curve. Lateral lengths ranged from 3,050 to 10,270 feet.
SCOOP Springer: Recent Wells Continue to Outperform Legacy Type Curve by 70%
Recently completed SCOOP Springer wells continue to outperform the Company's legacy 940 MBoe type curve, benefiting from optimized completions and longer laterals. Average production from the previously announced Cash, Trammell, Strassle, and Robinson wells is approximately 70% above the Springer type curve at 150 days.
During the third quarter, activity in SCOOP Springer was focused on an ongoing 6-well density test at the Celesta unit. This is the Company's first two-mile lateral density test in the Springer, and results are expected by early 2018.
Financial Update
"Continental's focus on capital efficiency and cash flow continues to yield results," said John Hart, Chief Financial Officer. "Our cash flows are strong and improving with rising production and improved commodity prices, each positively benefiting our leverage ratios. We see this trend continuing. We also continue to make progress towards our near-term debt reduction target of $6.0 billion and our longer-term goal of $5.0 billion. We recently closed on three separate transactions totaling $136 million, and we are actively marketing several larger packages."
In third quarter 2017, Continental's average realized sales price excluding the effects of derivative positions was $43.27 per barrel of oil and $2.74 per Mcf of gas, or $31.86 per Boe. Based on realizations without the effect of derivatives, the Company's third quarter 2017 oil differential was $4.98 per barrel below the NYMEX daily average for the period, $1.33 better than the second quarter differential. The realized wellhead natural gas price differential was $0.26 per Mcf below the average NYMEX Henry Hub benchmark price, $0.30 better than the second quarter average due primarily to stronger liquids pricing. The month of September had a premium of $0.02 per Mcf above the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.82 for third quarter 2017. Other select operating costs and expenses for third quarter 2017 included production taxes of 7.3% of oil and natural gas sales, DD&A of $19.00 per Boe, and total G&A of $1.99 per Boe.
Non-acquisition capital expenditures for third quarter 2017 totaled approximately $520.6 million. They included $444.7 million in exploration and development drilling, $47.7 million in leasehold and seismic, and $28.2 million in workovers, recompletions and other.
As of September 30, 2017, Continental's balance sheet included approximately $10.8 million in cash and cash equivalents and $6.6 billion in long-term debt. During the third quarter the Company closed on the previously announced sale of 26,000 net acres in the Arkoma Basin, oil-loading facilities and other divestitures for $76.1 million. Another previously announced divestiture closed in October for approximately $59.9 million.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended September 30, |
Nine months ended September 30, | ||||||
2017 |
2016 |
2017 |
2016 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
140,611 |
116,277 |
128,476 |
131,873 | |||
Natural gas (Mcf per day) |
613,060 |
549,374 |
595,294 |
524,441 | |||
Crude oil equivalents (Boe per day) |
242,788 |
207,840 |
227,692 |
219,280 | |||
Average sales prices, excluding effect from derivatives: |
|||||||
Crude oil ($/Bbl) |
$43.27 |
$37.66 |
$43.26 |
$33.51 | |||
Natural gas ($/Mcf) |
$2.74 |
$2.02 |
$2.78 |
$1.57 | |||
Crude oil equivalents ($/Boe) |
$31.86 |
$26.42 |
$31.67 |
$23.91 | |||
Production expenses ($/Boe) |
$3.82 |
$3.50 |
$3.86 |
$3.66 | |||
Production taxes (% of oil and gas revenues) |
7.3% |
6.8% |
6.8% |
7.3% | |||
DD&A ($/Boe) |
$19.00 |
$21.66 |
$19.31 |
$22.00 | |||
Total general and administrative expenses ($/Boe) (1) |
$1.99 |
$2.32 |
$2.10 |
$1.88 | |||
Net income (loss) (in thousands) |
$10,621 |
($109,621) |
($52,467) |
($427,348) | |||
Diluted net income (loss) per share |
$0.03 |
($0.30) |
($0.14) |
($1.15) | |||
Adjusted net income (loss) (non-GAAP) (in thousands) (2) |
$32,162 |
($82,853) |
$37,142 |
($299,232) | |||
Adjusted diluted net income (loss) per share (non-GAAP) (2) |
$0.09 |
($0.22) |
$0.10 |
($0.81) | |||
Net cash provided by operating activities |
$431,409 |
$366,167 |
$1,347,981 |
$863,888 | |||
EBITDAX (non-GAAP) (in thousands) (2) |
$563,767 |
$386,789 |
$1,525,730 |
$1,229,507 |
(1) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.45, $1.63, $1.58, and $1.31 for 3Q 2017, 3Q 2016, YTD 2017 and YTD 2016, respectively. Non-cash equity compensation expense per Boe was $0.54, $0.69, $0.52, and $0.57 for 3Q 2017, 3Q 2016, YTD 2017 and YTD 2016, respectively. |
(2) Adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or net cash provided by operating activities as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Third Quarter Earnings Conference Call
Continental plans to host a conference call to discuss third quarter results on Wednesday, November 8, 2017, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Wednesday, November 8, 2017 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
89145961 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
89145961 |
Continental plans to publish a third quarter 2017 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on November 8, 2017.
Upcoming Conferences
Members of Continental's management team plan to participate in the following investment conferences:
November 15-16, 2017 |
Bank of America Merrill Lynch Global Energy Conference, Miami |
November 28, 2017 |
Capital One Bakken Deep Dive, New York |
November 28, 2017 |
Jefferies 2017 Energy Conference, Houston |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||||||
Unaudited Condensed Consolidated Statements of Income (Loss) | |||||||
Three months ended September 30, |
Nine months ended September 30, | ||||||
2017 |
2016 |
2017 |
2016 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 704,818 |
$ 505,892 |
$ 1,965,216 |
$ 1,435,194 | |||
Gain (loss) on crude oil and natural gas derivatives, net |
8,602 |
15,668 |
83,482 |
(24,477) | |||
Crude oil and natural gas service operations |
13,323 |
4,639 |
24,959 |
19,867 | |||
Total revenues |
726,743 |
526,199 |
2,073,657 |
1,430,584 | |||
Operating costs and expenses: |
|||||||
Production expenses |
84,514 |
67,022 |
239,842 |
219,745 | |||
Production taxes |
51,264 |
34,583 |
134,462 |
104,216 | |||
Exploration expenses |
1,389 |
3,987 |
9,591 |
8,726 | |||
Crude oil and natural gas service operations |
3,349 |
2,605 |
10,664 |
9,224 | |||
Depreciation, depletion, amortization and accretion |
420,243 |
414,671 |
1,198,169 |
1,320,423 | |||
Property impairments |
35,130 |
57,689 |
209,819 |
202,728 | |||
General and administrative expenses |
44,006 |
44,389 |
130,413 |
113,043 | |||
Net (gain) loss on sale of assets and other |
(4,905) |
(5,564) |
764 |
(104,690) | |||
Total operating costs and expenses |
634,990 |
619,382 |
1,933,724 |
1,873,415 | |||
Income (loss) from operations |
91,753 |
(93,183) |
139,933 |
(442,831) | |||
Other income (expense): |
|||||||
Interest expense |
(74,756) |
(82,074) |
(218,672) |
(244,949) | |||
Other |
394 |
360 |
1,209 |
1,178 | |||
(74,362) |
(81,714) |
(217,463) |
(243,771) | ||||
Income (loss) before income taxes |
17,391 |
(174,897) |
(77,530) |
(686,602) | |||
(Provision) benefit for income taxes |
(6,770) |
65,276 |
25,063 |
259,254 | |||
Net income (loss) |
$ 10,621 |
$ (109,621) |
$ (52,467) |
$ (427,348) | |||
Basic net income (loss) per share |
$ 0.03 |
$ (0.30) |
$ (0.14) |
$ (1.15) | |||
Diluted net income (loss) per share |
$ 0.03 |
$ (0.30) |
$ (0.14) |
$ (1.15) |
Continental Resources, Inc. and Subsidiaries | |||||
Unaudited Condensed Consolidated Balance Sheets | |||||
September 30, 2017 |
December 31, 2016 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
1,060,975 |
$ |
913,233 | |
Net property and equipment (1) |
12,919,202 |
12,881,227 | |||
Other noncurrent assets |
14,910 |
17,316 | |||
Total assets |
$ |
13,995,087 |
$ |
13,811,776 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
1,129,459 |
$ |
932,393 | |
Long-term debt, net of current portion |
6,612,281 |
6,577,697 | |||
Other noncurrent liabilities |
1,976,568 |
1,999,690 | |||
Total shareholders' equity |
4,276,779 |
4,301,996 | |||
Total liabilities and shareholders' equity |
$ |
13,995,087 |
$ |
13,811,776 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $8.64 billion and $7.65 billion as of September 30, 2017 and December 31, 2016, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||||||
Three months ended September 30, |
Nine months ended September 30, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net income (loss) |
$ |
10,621 |
$ |
(109,621) |
$ |
(52,467) |
$ |
(427,348) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
480,718 |
415,690 |
1,358,639 |
1,318,720 | ||||||||
Changes in assets and liabilities |
(59,930) |
60,098 |
41,809 |
(27,484) | ||||||||
Net cash provided by operating activities |
431,409 |
366,167 |
1,347,981 |
863,888 | ||||||||
Net cash used in investing activities |
(494,934) |
(32,427) |
(1,374,254) |
(550,221) | ||||||||
Net cash provided by (used in) financing activities |
57,080 |
(330,802) |
20,361 |
(305,641) | ||||||||
Effect of exchange rate changes on cash |
20 |
(2) |
34 |
7 | ||||||||
Net change in cash and cash equivalents |
(6,425) |
2,936 |
(5,878) |
8,033 | ||||||||
Cash and cash equivalents at beginning of period |
17,190 |
16,560 |
16,643 |
11,463 | ||||||||
Cash and cash equivalents at end of period |
$ |
10,765 |
$ |
19,496 |
$ |
10,765 |
$ |
19,496 |
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income (loss) or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.
Three months ended September 30, |
Nine months ended September 30, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net income (loss) |
$ |
10,621 |
$ |
(109,621) |
$ |
(52,467) |
$ |
(427,348) | ||||
Interest expense |
74,756 |
82,074 |
218,672 |
244,949 | ||||||||
Provision (benefit) for income taxes |
6,770 |
(65,276) |
(25,063) |
(259,254) | ||||||||
Depreciation, depletion, amortization and accretion |
420,243 |
414,671 |
1,198,169 |
1,320,423 | ||||||||
Property impairments |
35,130 |
57,689 |
209,819 |
202,728 | ||||||||
Exploration expenses |
1,389 |
3,987 |
9,591 |
8,726 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total (gain) loss on derivatives, net |
(9,945) |
(15,237) |
(82,015) |
21,768 | ||||||||
Total cash received on derivatives, net |
12,884 |
5,274 |
16,534 |
83,241 | ||||||||
Non-cash (gain) loss on derivatives, net |
2,939 |
(9,963) |
(65,481) |
105,009 | ||||||||
Non-cash equity compensation |
11,919 |
13,228 |
32,490 |
34,274 | ||||||||
EBITDAX (non-GAAP) |
$ |
563,767 |
$ |
386,789 |
$ |
1,525,730 |
$ |
1,229,507 |
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended September 30, |
Nine months ended September 30, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net cash provided by operating activities |
$ |
431,409 |
$ |
366,167 |
$ |
1,347,981 |
$ |
863,888 | ||||
Current income tax provision (benefit) |
(1) |
(10) |
- |
2 | ||||||||
Interest expense |
74,756 |
82,074 |
218,672 |
244,949 | ||||||||
Exploration expenses, excluding dry hole costs |
1,389 |
3,960 |
9,434 |
8,493 | ||||||||
Gain on sale of assets, net |
3,562 |
6,158 |
703 |
103,174 | ||||||||
Tax deficiency from stock-based compensation |
- |
(9,460) |
- |
(9,460) | ||||||||
Other, net |
(7,278) |
(2,002) |
(9,251) |
(9,023) | ||||||||
Changes in assets and liabilities |
59,930 |
(60,098) |
(41,809) |
27,484 | ||||||||
EBITDAX (non-GAAP) |
$ |
563,767 |
$ |
386,789 |
$ |
1,525,730 |
$ |
1,229,507 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended September 30, | ||||||||
2017 |
2016 | |||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||
Net income (loss) (GAAP) |
$ 10,621 |
$ 0.03 |
$(109,621) |
$ (0.30) | ||||
Adjustments: |
||||||||
Non-cash (gain) loss on derivatives |
2,939 |
(9,963) |
||||||
Property impairments |
35,130 |
57,689 |
||||||
Gain on sale of assets |
(3,562) |
(6,158) |
||||||
Total tax effect of adjustments |
(12,966) |
(14,800) |
||||||
Total adjustments, net of tax |
21,541 |
0.06 |
26,768 |
0.08 | ||||
Adjusted net income (loss) (non-GAAP) |
$ 32,162 |
$ 0.09 |
$ (82,853) |
$ (0.22) | ||||
Weighted average diluted shares outstanding |
373,015 |
370,483 |
||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$0.09 |
$ (0.22) |
||||||
Nine months ended September 30, | ||||||||
2017 |
2016 | |||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||
Net loss (GAAP)(1) |
$(52,467) |
$ (0.14) |
$(427,348) |
$ (1.15) | ||||
Adjustments: |
||||||||
Non-cash (gain) loss on derivatives |
(65,481) |
105,009 |
||||||
Property impairments |
209,819 |
202,728 |
||||||
Gain on sale of assets |
(703) |
(103,174) |
||||||
Total tax effect of adjustments |
(54,026) |
(76,447) |
||||||
Total adjustments, net of tax |
89,609 |
0.24 |
128,116 |
0.34 | ||||
Adjusted net income (loss) (non-GAAP) |
$ 37,142 |
$ 0.10 |
$(299,232) |
$ (0.81) | ||||
Weighted average diluted shares outstanding |
373,588 |
370,327 |
||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ 0.10 |
$ (0.81) |
(1) In 1Q 2017 we adopted ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which requires, among other things, that companies recognize excess tax benefits and deficiencies from stock-based compensation as income tax benefit or expense in the income statement rather than through additional paid-in capital. This change resulted in a $3.9 million ($0.01 per diluted share) increase in net loss for YTD 2017 with no comparable impact in the prior period. |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | ||
2017 Guidance(1) | ||
As of November 7, 2017 | ||
2017 | ||
Full year average production |
238,000 to 242,000 Boe per day | |
Exit rate average production |
280,000 to 290,000 Boe per day | |
Capital expenditures (non-acquisition) |
$1.95 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.50 to $3.90 | |
Production tax (% of oil & gas revenue) |
6.75% to 7.25% | |
Cash G&A expense per Boe(2) |
$1.35 to $1.75 | |
Non-cash equity compensation per Boe |
$0.50 to $0.60 | |
DD&A per Boe |
$18.00 to $20.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($5.25) to ($5.75) | |
Henry Hub natural gas (per Mcf) |
($0.10) to ($0.50) | |
Income tax rate |
38% | |
Deferred taxes |
90% to 95% |
(1) Changed items are shown in bold |
(2) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.85 to $2.35 per Boe. |
View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-third-quarter-2017-results-300551269.html
SOURCE Continental Resources
OKLAHOMA CITY, Oct. 17, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced its first-ever sale of Bakken oil specifically for delivery overseas. The Company has sold 1,005,000 barrels of Bakken crude oil for November delivery to Atlantic Trading and Marketing ("ATMI"), which intends to export the oil to China.
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Daily sales transactions of 33,500 barrels per day in November will take place in Cushing, Oklahoma. ATMI then plans to transport the oil for loading on tankers at Texas ports.
"This is a historic day for Continental and begins a new chapter in our long-term strategy to establish multiple international markets for American light sweet oil," said Harold Hamm, Continental's Chairman and Chief Executive Officer. "This new normal was created by the American shale energy revolution and the lifting of the 1977 crude oil export ban. We expect to see many similar industry transactions in coming months and years."
In December 2015 the U.S. lifted its ban on oil exports, allowing foreign sales to be transacted without a license. Oil exports have grown steadily in the past two years, primarily to foreign refineries configured specifically to process light sweet crude oil. "We recognized back in 2015, when we were working to lift the export ban, that American light sweet oil would be a good fit for these refineries, especially in Europe and Asia," Mr. Hamm said.
"The current $6 discount to Brent should not exist, given the consistency and high quality of WTI, as well as relative shipping costs," he said. "Stabilized U.S. production and increasing industry sales of American crude to international markets will drive down U.S. inventories, correcting much of the recent disparity between Brent and WTI prices. Modern modes of transport in the crude oil sector today eliminate price disparities between markets and allow free markets to work."
He noted that Continental continues to develop additional international markets for its light sweet oil.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-sale-of-1-million-barrels-of-bakken-oil-for-export-to-china-300538363.html
SOURCE Continental Resources
OKLAHOMA CITY, Oct. 5, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce third quarter 2017 results on Tuesday, November 7, 2017 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss third quarter 2017 results on Wednesday, November 8, 2017 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
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Time and date: |
12 p.m. ET, Wednesday, November 8, 2017 |
Dial-in: |
844-309-6572 |
Intl. dial-in: |
484-747-6921 |
Conference ID: |
89145961 |
A replay of the call will be available for 14 days on the Company's website or by dialing: | |
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
89145961 |
Continental plans to publish a third quarter 2017 summary presentation to its website at www.CLR.com prior to the start of its conference call on November 8, 2017.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
View original content:http://www.prnewswire.com/news-releases/continental-resources-to-announce-third-quarter-2017-results-on-tuesday-november-7-2017-300532058.html
SOURCE Continental Resources
OKLAHOMA CITY, Aug. 8, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced second quarter operating and financial results. Continental reported a net loss of $63.6 million, or $0.17 per diluted share, for the quarter ended June 30, 2017.
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The Company's net loss includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net loss." In second quarter 2017, these typically excluded items in aggregate represented $61.8 million, or $0.17 per diluted share, of Continental's reported net loss. Adjusted net loss for the second quarter was $1.8 million, or $0.00 per diluted share.
Net cash provided by operating activities for second quarter 2017 was $446.4 million. EBITDAX for second quarter 2017 was $479.5 million. Definitions and reconciliations of adjusted net income and net loss, adjusted net income and net loss per share, EBITDAX and cash G&A expense to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables and 2017 guidance summary at the conclusion of this press release.
"Continental remained disciplined and strategic with its capital spending during the quarter," said Harold Hamm, Chairman and Chief Executive Officer. "The results have been exceptional, raising our production guidance for 2017 and lowering our guidance for operating costs. We now expect to exit 2017 with production up 24% to 31% over the fourth quarter of 2016, with a lower range of capital expenditures for the year targeting cash neutrality between $45 and $51 WTI."
Mr. Hamm noted the Company recently surpassed a significant production milestone, with individual days of output of 250,000 Boe per day. "We're bringing on a lot of pad projects. Looking ahead, given the anticipated timing of additional pad projects in the Bakken and STACK, we expect third quarter 2017 production will average 240,000 to 250,000 Boe per day, with 58% of production being crude oil," he said.
"The continuous improvements we are achieving position Continental for even better results in 2018."
Improved 2017 Guidance Reflects Superior Assets, Efficiency Gains and Disciplined Capital Program
The Company now expects annual production will be in a higher range of 230,000 to 240,000 Boe per day, compared to its previous guidance of 220,000 to 230,000 Boe per day. Continental expects to exit the year with production between 260,000 and 275,000 Boe per day, compared to the previous exit-rate guidance of 250,000 to 260,000 Boe per day. Continental is also adjusting its capital expenditures for 2017 to a range between $1.75 billion and $1.95 billion. This level of capital expenditure is expected to maintain cash neutrality at WTI prices between $45 and $51 per barrel for the year. Adjustments to capital expenditures will be accomplished primarily by reducing completion crews and rigs. The rig count for the second half of the year is projected to average 18, with 14 in Oklahoma and four in Bakken. The Company has reduced its Bakken completion crew count to four and has six crews in Oklahoma. As a result, the Company expects to exit 2017 with a drilled but uncompleted (DUC) inventory in the Bakken of approximately 160 gross operated wells, including approximately 35 already stimulated with first production expected in 2018, providing a strong catalyst for further oil focused production growth in 2018.
Continental reduced 2017 guidance for production expense per Boe, which is now expected to be in a range of $3.50 to $3.90 per Boe for the year, down from $3.50 to $4.00 per Boe.
The Company also reduced its G&A guidance for 2017, following lower G&A expense per Boe in the second quarter. Total G&A expense, which is comprised of cash and non-cash G&A expense, is expected to be $1.85 to $2.35 per Boe for 2017. Of this total, cash G&A expense is expected to be $1.35 to $1.75 per Boe for 2017, a reduction from the previous $1.50 to $2.00 per Boe. Non-cash equity compensation is expected to be $0.50 to $0.60 per Boe, a reduction from the previous $0.60 to $0.70 per Boe.
Continental also reduced 2017 guidance for DD&A to $18.00 to $20.00 per Boe for the year, down approximately 7% from the previous range.
Finally, the Company improved its outlook for oil price differentials, reflecting the impact of additional pipeline capacity in the Bakken and continued infrastructure improvements in Oklahoma. Average crude oil price differential for 2017 companywide is expected to be in a range of $5.50 to $6.50 per barrel of oil (Bo), $1.00 below the previous guidance of $6.50 to $7.50. The Company expects further improvements to its crude oil price differential in 2018. The Company also adjusted its outlook for natural gas price differentials, reflecting continued natural gas liquids price weakness. The differential is now expected to be a negative $0.10 to a negative $0.50 per Mcf.
2017 Updated Guidance Metrics |
Previous 2017 Guidance |
Updated 2017 Guidance |
Annual production (Boe per day) |
220,000 to 230,000 |
230,000 to 240,000 |
Exit rate production (Boe per day) |
250,000 to 260,000 |
260,000 to 275,000 |
Capital expenditures (non-acquisition) |
$1.95 billion |
$1.75 to $1.95 billion |
Production expense per Boe |
$3.50 to $4.00 |
$3.50 to $3.90 |
Cash G&A expense per Boe(1) |
$1.50 to $2.00 |
$1.35 to $1.75 |
Non-cash equity compensation per Boe |
$0.60 to $0.70 |
$0.50 to $0.60 |
DD&A per Boe |
$19.00 to $22.00 |
$18.00 to $20.00 |
Average price differential for NYMEX WTI crude oil (per Bo) |
($6.50) to ($7.50) |
($5.50) to ($6.50) |
Average price differential for Henry Hub natural gas (per Mcf) |
$0.10 to ($0.40) |
($0.10) to ($0.50) |
1. |
Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.85 to $2.35 per Boe. |
The Company's full 2017 guidance is stated in a table at the conclusion of this release.
"The superior quality of our assets and operations continues to translate to the bottom line," said Jack Stark, President. "As our historical performance and updated guidance show, Continental is one of the lowest cost operators in the industry, delivering some of the best margins and recycle ratios among our peers."
Production
Second quarter 2017 net production totaled 20.6 million Boe, or 226,213 Boe per day, up 12,458 Boe per day from first quarter 2017, or approximately 6%.
Total net production for second quarter 2017 included 125,381 Bo per day (55% of production) and 605 million cubic feet (MMcf) of natural gas per day (45% of production).
The following table provides the Company's average daily production by region for the periods presented.
2Q |
1Q |
2Q |
YTD |
YTD | ||||||
Boe per day |
2017 |
2017 |
2016 |
2017 |
2016 | |||||
North Region: |
||||||||||
North Dakota Bakken |
112,397 |
101,012 |
114,554 |
106,736 |
121,861 | |||||
Montana Bakken |
7,464 |
7,980 |
10,474 |
7,720 |
10,454 | |||||
Red River Units |
9,878 |
10,089 |
11,075 |
9,983 |
11,188 | |||||
Other |
483 |
333 |
695 |
409 |
672 | |||||
South Region: |
||||||||||
SCOOP |
61,107 |
62,178 |
64,669 |
61,640 |
64,642 | |||||
STACK |
31,934 |
29,216 |
14,610 |
30,582 |
12,868 | |||||
Arkoma |
1,788 |
1,754 |
1,862 |
1,771 |
1,950 | |||||
Other |
1,162 |
1,193 |
1,384 |
1,177 |
1,428 | |||||
Total |
226,213 |
213,755 |
219,323 |
220,018 |
225,063 |
Bakken: Type Curve ROR Doubled to 82%
Continental's Bakken net production averaged 119,861 Boe per day in second quarter 2017. The Company had 100 gross (38 net) operated and non-operated Bakken wells completed during second quarter 2017. At June 30, 2017, the Company had 205 gross operated DUCs.
In the second quarter, the Company had 19 gross operated wells with first production with an average 24-hour initial production (IP) rate of 1,606 Boe per day (82% oil). Five of the second quarter wells rank in the Company's top 10 all-time producing Bakken wells, based on 30 days of production. Also during the quarter, Continental expanded the success of its optimized completions 40 miles south of existing activity in northeast McKenzie County to central Dunn County.
Based on the success of its optimized completions, the Company announced a 12% increase in its type curve EUR to 1,100 MBoe per well with a 24-hour IP of approximately 1,500 Boe. At an estimated completed well cost of $7.5 million for a 2-mile lateral well, a 1,100 MBoe EUR Bakken well will yield an 82% ROR at $50 per barrel WTI and $3.25 per Mcf of gas. This is more than double the ROR compared to the previous 980 MBoe Bakken type curve. Cumulative production at 180 days is approximately 64,000 Boe higher compared to the 980 MBoe type curve, generating over $2 million more revenue in the first six months. The new 1,100 MBoe type curve has a quicker estimated payout period of 1.25 years, compared to 2.5 years for wells with the previous type curve.
"In 2017 our Bakken team has doubled our rate of return and reduced the payout period by 50%, based on our new type curve," said Gary Gould, Senior Vice President of Production and Resource Development. "This is a step-change improvement in Bakken economics."
STACK: The Company Announces Record Well and Initial Type Curve with 80% ROR for Condensate Window
Continental's STACK net production averaged 31,934 Boe per day in second quarter 2017. The Company had 36 gross (12 net) operated and non-operated STACK wells completed during second quarter 2017. By the end of August, the Company will have nine operated rigs in the play, with seven rigs targeting the Meramec formation and two targeting the Woodford formation.
The Company reported six operated standalone wells in the STACK Meramec over-pressured oil and condensate windows. Initial 24-hour production test rates for these six wells averaged 1,915 Boe per day (45% oil) from an average 6,860-foot lateral.
In early August the Company completed a record well in STACK. The Tres C FIU 1-35-2XH flowed an impressive 1,021 Bo and 29.6 MMcf of gas (5,953 Boe) in its initial 24-hour test, with flowing casing pressure of 6,500 pounds per square inch from a 9,748-foot lateral. Adding an additional 1,978 barrels of anticipated natural gas liquids post-processing, Continental estimates the initial 24-hour IP rate for the Tres C would be a record 7,442 Boe (40% liquids) on a three-stream basis.
The Company also announced a type curve EUR of 2,400 MBoe (14% oil) for wells in the STACK over-pressured condensate window. At a targeted completed well cost of $10 million, a 9,800-foot lateral condensate well would generate an 80% ROR at $50 per barrel WTI and $3.25 per Mcf of natural gas.
The Company recently began flowing back the third of seven Meramec density tests it has in process to establish proper well spacing for future development of the Meramec reservoirs. The Blurton unit was an 8-well density test, with three new wells in the upper Meramec and four new wells and the existing parent well in the lower Meramec. Average lateral length was approximately 10,000 feet per well. The unit is still in the early stages of flowing back and has not reached peak production rates. To date the combined 24-hour initial rate recorded from the eight wells is 10,514 Boe per day, with 78% of production being oil. Including estimated post-processing natural gas liquids, the combined 24-hour IP rate would have been approximately 11,883 Boe per day. The Company continues to monitor the flowback of these wells and will incorporate the results from the Blurton with those of other density tests to guide future development in STACK.
SCOOP: Springer Shines
In second quarter 2017, SCOOP net production averaged 61,107 Boe per day (27% oil). Continental had 8 gross (2 net) operated and non-operated wells completed during second quarter 2017. Continental currently has five operated drilling rigs working in SCOOP, targeting the Springer, Sycamore and Woodford formations.
During the quarter, Continental announced one SCOOP Springer well, the Robinson 2-15-10XHS. The initial 24-hour production test rate was 1,636 Boe per day (82% oil) from a 7,700-foot lateral. The Robinson outperformed the Company's historical 940 MBoe Springer type curve by 89% in the first 60 days on production.
Last quarter, the Company announced the completion of the Cash 1-26H, an optimized Springer producing well. At 90 days the Cash outperformed the Company's 940 MBoe type curve by 82%. At a cost of $7.6 million and an estimated EUR of 1,160 MBoe, the Cash well has an estimated rate of return of over 100% and pays out in 12 months, assuming $50 per barrel WTI and $3.25 per Mcf of gas. Longer laterals, combined with shorter drill times and optimized completions, are improving Springer well economics.
A notable second quarter well in the SCOOP Woodford oil window was the Romanoff 1-25-24-13XH in eastern Grady County, which had a 24-hour IP rate of 1,188 Bo and 2.3 MMcf (1,563 Boe) from a 14,900-foot lateral. This was the Company's first 3-mile lateral well in SCOOP. At 30 days, the well was outperforming offset wells by over 25%, when normalized to a 7,500-foot lateral, and had an average 30-day production rate of 1,424 Boe per day (75% oil).
Two other recent completions in the SCOOP Woodford condensate window were the Renea 1-23-14XH and Cottonwood East 1-25-24XH wells. The Renea's 24-hour IP was 2,322 Boe per day (18% oil) from a 10,160-foot lateral. The Cottonwood East's 24-hour IP was 1,918 (34% oil) from a 7,800-foot lateral. The Renea and Cottonwood outperformed legacy offset wells by 80% to 90% during their first 30 days. They are located in an area of Stephens County where the Company has not been active for the past two years.
Company Agrees to Sell Non-Strategic Leasehold and Property for $147.5 Million
Continental announced today it has signed two definitive purchase and sale agreements with undisclosed buyers to sell 6,590 net acres of non-core leasehold in the oil window of STACK in northern Blaine County, Oklahoma for $72.5 million, and 26,000 net acres of leasehold in the Arkoma Basin located in Atoka, Coal, Hughes and Pittsburg counties, Oklahoma for $68.0 million. The leaseholds are non-strategic and include minimal proved reserves. The agreements provide for customary closing conditions and adjustments. The Company is also selling oil-loading facilities in Oklahoma for $7.0 million. The Company intends to use the proceeds from the sales to reduce outstanding debt and noted that it has other opportunities for non-core asset sales.
Financial Update
"Continental's results through the first half of the year reflect strong outperformance and continued operating cost and capital expenditure discipline," said John Hart, Chief Financial Officer. "We are raising our production estimates while lowering guidance for operating costs. The updated guidance metrics are expected to be achieved while targeting cash neutrality between $45 and $51 WTI with capital expenditures ranging from $1.75 billion to $1.95 billion.
"Oil production was 55% of total production for second quarter, slightly lower than consensus primarily due to working interest adjustments. For third quarter we are projecting production to be 58% oil as additional Bakken and Springer wells are completed."
In second quarter 2017, Continental's average realized sales price excluding the effects of derivative positions was $41.91 per barrel of oil and $2.63 per Mcf of gas, or $30.31 per Boe. Based on realizations without the effect of derivatives, the Company's second quarter 2017 oil differential was $6.31 per barrel below the NYMEX daily average for the period, $0.78 better than the first quarter differential. The realized wellhead natural gas price for the quarter was on average $0.56 per Mcf below the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.99 for second quarter 2017. Other select operating costs and expenses for second quarter 2017 included production taxes of 6.7% of oil and natural gas sales, DD&A of $19.14 per Boe, and total G&A of $1.89 per Boe.
Non-acquisition capital expenditures for second quarter 2017 totaled approximately $551.9 million. Non-acquisition capital expenditures for the quarter included $471.0 million in exploration and development drilling, $51.6 million in leasehold and seismic, and $29.3 million in workovers, recompletions and other.
As of June 30, 2017, Continental's balance sheet included approximately $17.2 million in cash and cash equivalents and $6.56 billion in long-term debt, essentially in-line with first quarter 2017.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended June 30, |
Six months ended June 30, | ||||||
2017 |
2016 |
2017 |
2016 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
125,381 |
133,044 |
122,308 |
139,756 | |||
Natural gas (Mcf per day) |
604,991 |
517,677 |
586,263 |
511,837 | |||
Crude oil equivalents (Boe per day) |
226,213 |
219,323 |
220,018 |
225,063 | |||
Average sales prices, excluding effect from derivatives: |
|||||||
Crude oil ($/Bbl) |
$41.91 |
$38.38 |
$43.26 |
$31.76 | |||
Natural gas ($/Mcf) |
$2.63 |
$1.31 |
$2.81 |
$1.33 | |||
Crude oil equivalents ($/Boe) |
$30.31 |
$26.36 |
$31.56 |
$22.73 | |||
Production expenses ($/Boe) |
$3.99 |
$3.72 |
$3.89 |
$3.74 | |||
Production taxes (% of oil and gas revenues) |
6.7% |
7.4% |
6.6% |
7.5% | |||
DD&A ($/Boe) |
$19.14 |
$22.15 |
$19.48 |
$22.16 | |||
Total general and administrative expenses ($/Boe) (1) |
$1.89 |
$1.82 |
$2.16 |
$1.68 | |||
Net loss (in thousands) |
($63,557) |
($119,402) |
($63,088) |
($317,727) | |||
Diluted net loss per share |
($0.17) |
($0.32) |
($0.17) |
($0.86) | |||
Adjusted net income (loss) (non-GAAP) (in thousands) (2) |
($1,801) |
($65,910) |
$4,979 |
($216,378) | |||
Adjusted diluted net income (loss) per share (non-GAAP) (2) |
$0.00 |
($0.18) |
$0.01 |
($0.58) | |||
Net cash provided by operating activities |
$446,371 |
$218,819 |
$916,572 |
$497,721 | |||
EBITDAX (non-GAAP) (in thousands) (2) |
$479,490 |
$528,109 |
$961,963 |
$842,718 | |||
(1) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.45, $1.22, $1.65, and $1.16 for 2Q 2017, 2Q 2016, YTD 2017 and YTD 2016, respectively. Non-cash equity compensation expense per Boe was $0.44, $0.60, $0.51, and $0.52 for 2Q 2017, 2Q 2016, YTD 2017 and YTD 2016, respectively. |
(2) Adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or net cash provided by operating activities as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Second Quarter Earnings Conference Call
Continental plans to host a conference call to discuss second quarter results on Wednesday, August 9, 2017, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Wednesday, August 9, 2017 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
30586076 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
30586076 |
Continental plans to publish a second quarter 2017 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on August 9, 2017.
Upcoming Conferences
Members of Continental's management team plan to participate in the following investment conferences:
August 23, 2017 |
Heikkinen Energy Conference, Houston |
September 5-6, 2017 |
Barclays CEO Energy-Power Conference, New York |
September 27-28, 2017 |
Deutsche Bank Annual Energy 1x1 Conference, Boston |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Senior Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||||||
Unaudited Condensed Consolidated Statements of Loss | |||||||
Three months ended June 30, |
Six months ended June 30, | ||||||
2017 |
2016 |
2017 |
2016 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 626,548 |
$ 525,711 |
$ 1,260,398 |
$ 929,302 | |||
Gain (loss) on crude oil and natural gas derivatives, net |
28,022 |
(82,257) |
74,880 |
(40,145) | |||
Crude oil and natural gas service operations |
6,916 |
7,757 |
11,636 |
15,227 | |||
Total revenues |
661,486 |
451,211 |
1,346,914 |
904,384 | |||
Operating costs and expenses: |
|||||||
Production expenses |
82,474 |
74,083 |
155,328 |
152,724 | |||
Production taxes |
41,965 |
39,141 |
83,198 |
69,634 | |||
Exploration expenses |
3,204 |
1,674 |
8,202 |
4,739 | |||
Crude oil and natural gas service operations |
4,478 |
3,576 |
7,315 |
6,618 | |||
Depreciation, depletion, amortization and accretion |
395,770 |
441,761 |
777,926 |
905,752 | |||
Property impairments |
123,316 |
66,112 |
174,689 |
145,039 | |||
General and administrative expenses |
39,186 |
36,246 |
86,407 |
68,654 | |||
Net (gain) loss on sale of assets and other |
134 |
(100,835) |
5,669 |
(99,127) | |||
Total operating costs and expenses |
690,527 |
561,758 |
1,298,734 |
1,254,033 | |||
Income (loss) from operations |
(29,041) |
(110,547) |
48,180 |
(349,649) | |||
Other income (expense): |
|||||||
Interest expense |
(72,744) |
(81,922) |
(143,916) |
(162,875) | |||
Other |
373 |
435 |
815 |
819 | |||
(72,371) |
(81,487) |
(143,101) |
(162,056) | ||||
Loss before income taxes |
(101,412) |
(192,034) |
(94,921) |
(511,705) | |||
Benefit for income taxes |
37,855 |
72,632 |
31,833 |
193,978 | |||
Net loss |
$ (63,557) |
$ (119,402) |
$ (63,088) |
$ (317,727) | |||
Basic net loss per share |
$ (0.17) |
$ (0.32) |
$ (0.17) |
$ (0.86) | |||
Diluted net loss per share |
$ (0.17) |
$ (0.32) |
$ (0.17) |
$ (0.86) |
Continental Resources, Inc. and Subsidiaries | |||||
Unaudited Condensed Consolidated Balance Sheets | |||||
June 30, 2017 |
December 31, 2016 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
934,042 |
$ |
913,233 | |
Net property and equipment (1) |
12,921,875 |
12,881,227 | |||
Other noncurrent assets |
15,340 |
17,316 | |||
Total assets |
$ |
13,871,257 |
$ |
13,811,776 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
1,094,978 |
$ |
932,393 | |
Long-term debt, net of current portion |
6,553,740 |
6,577,697 | |||
Other noncurrent liabilities |
1,968,204 |
1,999,690 | |||
Total shareholders' equity |
4,254,335 |
4,301,996 | |||
Total liabilities and shareholders' equity |
$ |
13,871,257 |
$ |
13,811,776 | |
(1) Balance is net of accumulated depreciation, depletion and amortization of $8.49 billion and $7.65 billion as of June 30, 2017 and December 31, 2016, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||||||
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net loss |
$ |
(63,557) |
$ |
(119,402) |
$ |
(63,088) |
$ |
(317,727) | ||||
Adjustments to reconcile net loss to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
465,966 |
470,257 |
877,921 |
903,030 | ||||||||
Changes in assets and liabilities |
43,962 |
(132,036) |
101,739 |
(87,582) | ||||||||
Net cash provided by operating activities |
446,371 |
218,819 |
916,572 |
497,721 | ||||||||
Net cash used in investing activities |
(490,049) |
(158,983) |
(879,320) |
(517,794) | ||||||||
Net cash (used in) provided by financing activities |
43,666 |
(56,181) |
(36,719) |
25,161 | ||||||||
Effect of exchange rate changes on cash |
14 |
(22) |
14 |
9 | ||||||||
Net change in cash and cash equivalents |
2 |
3,633 |
547 |
5,097 | ||||||||
Cash and cash equivalents at beginning of period |
17,188 |
12,927 |
16,643 |
11,463 | ||||||||
Cash and cash equivalents at end of period |
$ |
17,190 |
$ |
16,560 |
$ |
17,190 |
$ |
16,560 |
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income (loss) or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net loss to EBITDAX for the periods presented.
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net loss |
$ |
(63,557) |
$ |
(119,402) |
$ |
(63,088) |
$ |
(317,727) | ||||
Interest expense |
72,744 |
81,922 |
143,916 |
162,875 | ||||||||
Benefit for income taxes |
(37,855) |
(72,632) |
(31,833) |
(193,978) | ||||||||
Depreciation, depletion, amortization and accretion |
395,770 |
441,761 |
777,926 |
905,752 | ||||||||
Property impairments |
123,316 |
66,112 |
174,689 |
145,039 | ||||||||
Exploration expenses |
3,204 |
1,674 |
8,202 |
4,739 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total (gain) loss on derivatives, net |
(27,109) |
78,057 |
(72,070) |
37,005 | ||||||||
Total cash received on derivatives, net |
3,844 |
38,778 |
3,650 |
77,967 | ||||||||
Non-cash (gain) loss on derivatives, net |
(23,265) |
116,835 |
(68,420) |
114,972 | ||||||||
Non-cash equity compensation |
9,133 |
11,839 |
20,571 |
21,046 | ||||||||
EBITDAX (non-GAAP) |
$ |
479,490 |
$ |
528,109 |
$ |
961,963 |
$ |
842,718 |
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2017 |
2016 |
2017 |
2016 | ||||||||
Net cash provided by operating activities |
$ |
446,371 |
$ |
218,819 |
$ |
916,572 |
$ |
497,721 | ||||
Current income tax provision |
- |
6 |
1 |
12 | ||||||||
Interest expense |
72,744 |
81,922 |
143,916 |
162,875 | ||||||||
Exploration expenses, excluding dry hole costs |
3,204 |
1,468 |
8,045 |
4,533 | ||||||||
Gain (loss) on sale of assets, net |
780 |
96,907 |
(2,859) |
97,016 | ||||||||
Other, net |
353 |
(3,049) |
(1,973) |
(7,021) | ||||||||
Changes in assets and liabilities |
(43,962) |
132,036 |
(101,739) |
87,582 | ||||||||
EBITDAX (non-GAAP) |
$ |
479,490 |
$ |
528,109 |
$ |
961,963 |
$ |
842,718 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended June 30, | ||||||||||||
2017 |
2016 | |||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||||||
Net loss (GAAP) |
$ (63,557) |
$ (0.17) |
$(119,402) |
$ (0.32) | ||||||||
Adjustments: |
||||||||||||
Non-cash (gain) loss on derivatives |
(23,265) |
116,835 |
||||||||||
Property impairments |
123,316 |
66,112 |
||||||||||
Gain on sale of assets |
(780) |
(96,907) |
||||||||||
Total tax effect of adjustments |
(37,515) |
(32,548) |
||||||||||
Total adjustments, net of tax |
61,756 |
0.17 |
53,492 |
0.14 | ||||||||
Adjusted net loss (non-GAAP) |
$ (1,801) |
$0.00 |
$ (65,910) |
$ (0.18) | ||||||||
Weighted average diluted shares outstanding |
371,111 |
370,435 |
||||||||||
Adjusted diluted net loss per share (non-GAAP) |
$0.00 |
$ (0.18) |
||||||||||
Six months ended June 30, | ||||||||||||
2017 |
2016 | |||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||||||
Net loss (GAAP)(1) |
$ (63,088) |
$ (0.17) |
$(317,727) |
$ (0.86) | ||||||||
Adjustments: |
||||||||||||
Non-cash (gain) loss on derivatives |
(68,420) |
114,972 |
||||||||||
Property impairments |
174,689 |
145,039 |
||||||||||
(Gain) loss on sale of assets |
2,859 |
(97,016) |
||||||||||
Total tax effect of adjustments |
(41,061) |
(61,646) |
||||||||||
Total adjustments, net of tax |
68,067 |
0.18 |
101,349 |
0.28 | ||||||||
Adjusted net income (loss) (non-GAAP) |
$ 4,979 |
$ 0.01 |
$(216,378) |
$ (0.58) | ||||||||
Weighted average diluted shares outstanding |
373,518 |
370,248 |
||||||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ 0.01 |
$ (0.58) |
||||||||||
(1) In 1Q 2017 we adopted ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which requires, among other things, that companies recognize excess tax benefits and deficiencies from stock-based compensation as income tax benefit or expense in the income statement rather than through additional paid-in capital. This change resulted in a $3.8 million ($0.01 per diluted share) increase in net loss for YTD 2017 with no comparable impact in the prior period. |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | ||
2017 Guidance(1) | ||
As of August 8, 2017 | ||
2017 | ||
Full year average production |
230,000 to 240,000 Boe per day | |
Exit rate average production |
260,000 to 275,000 Boe per day | |
Capital expenditures (non-acquisition) |
$1.75 to $1.95 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.50 to $3.90 | |
Production tax (% of oil & gas revenue) |
6.75% to 7.25% | |
Cash G&A expense per Boe(2) |
$1.35 to $1.75 | |
Non-cash equity compensation per Boe |
$0.50 to $0.60 | |
DD&A per Boe |
$18.00 to $20.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($5.50) to ($6.50) | |
Henry Hub natural gas (per Mcf) |
($0.10) to ($0.50) | |
Income tax rate |
38% | |
Deferred taxes |
90% to 95% | |
(1) |
Changed items are shown in bold | |
(2) |
Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.85 to $2.35 per Boe. |
View original content:http://www.prnewswire.com/news-releases/continental-resources-reports-second-quarter-2017-results-and-updates-full-year-guidance-300501522.html
SOURCE Continental Resources
OKLAHOMA CITY, July 6, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce second quarter 2017 results on Tuesday, August 8, 2017 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss second quarter 2017 results on Wednesday, August 9, 2017 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
Time and date: |
12 p.m. ET, Wednesday, August 9, 2017 |
Dial-in: |
844-309-6572 |
Intl. dial-in: |
484-747-6921 |
Conference ID: |
30586076 |
A replay of the call will be available for 14 days on the Company's website or by dialing: | |
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
30586076 |
Continental plans to publish a second quarter 2017 summary presentation to its website at www.CLR.com prior to the start of its conference call on August 9, 2017.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore discoveries and the STACK play. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company is celebrating 50 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, May 3, 2017 /PRNewswire/ --
Bakken Wells Exceed 980 MBoe EUR Type Curve by an Average 65% in First 30 Days
SCOOP Springer Wells Outperform 940 MBoe EUR Type Curve by an Average 60% in First 30 Days
Sycamore Expansion Adds Approximately 300,000 Net Reservoir Acres Under Existing Leasehold in SCOOP
STACK Meramec Wells Flow 1,907 to 3,011 Boe per Day During Initial 24-Hour Tests
Second Quarter 2017 Production Trending Ahead of Forecast; Now Expected to Range from 220,000 to 225,000 Boe per Day
Continental Resources, Inc. (NYSE: CLR) (the Company) today announced first quarter operating and financial results. Continental reported net income of $0.47 million, or $0.00 per diluted share, for the quarter ended March 31, 2017.
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In first quarter 2017, these typically excluded items in aggregate represented $6.3 million, or $0.02 per diluted share, of Continental's reported net income. Adjusted net income for the first quarter was $6.8 million, or $0.02 per diluted share.
Net cash provided by operating activities for first quarter 2017 was $470.2 million. EBITDAX for first quarter 2017 was $482.5 million. Definitions and reconciliations of adjusted net income, adjusted net income per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided in the supporting tables at the conclusion of this press release.
"I am very pleased with the performance of our assets and operations so far this year. Relative to 2017 guidance, we are ahead on production, under on CAPEX and expect to be at the top-end or better than our production guidance for the year," said Harold Hamm, Chairman and Chief Executive Officer. "In the Bakken, we have seen industry-wide basin wellhead netbacks strengthen by approximately $2.00 per barrel with new pipeline capacity and additional markets becoming available. This will begin to positively impact our economics over the next several months."
Mr. Hamm noted that Continental continues to expand the strategic scope of its premier assets with the Sycamore reservoir in Oklahoma's SCOOP play. "On top of all of the other great news, we are pleased to announce the addition of approximately 300,000 net reservoir acres in Sycamore, a new reservoir layer within SCOOP. Our world-class asset portfolio continues to expand."
Production Accelerates in March
First quarter 2017 net production totaled 19.2 million barrels of oil equivalent (Boe), or 213,755 Boe per day, up approximately 4,000 Boe per day from fourth quarter 2016. March production averaged approximately 222,500 Boe per day. The Company now expects second quarter 2017 production will be in a range of 220,000 to 225,000 Boe per day. The Company is currently tracking at the top end or better than its annual production guidance, and if warranted, it will update guidance in August.
Total net production for first quarter 2017 included 119,201 barrels of oil (Bo) per day (56% of production) and 567 million cubic feet (MMcf) of natural gas per day (44% of production). Oil as a percentage of total production is expected to continue increasing to approximately 60% at year-end 2017.
The following table provides the Company's average daily production by region for the periods presented.
1Q |
4Q |
1Q | ||||
Boe per day |
2017 |
2016 |
2016 | |||
North Region: |
||||||
North Dakota Bakken |
101,012 |
96,035 |
129,168 | |||
Montana Bakken |
7,980 |
8,489 |
10,434 | |||
Red River Units |
10,089 |
10,140 |
11,300 | |||
Other |
333 |
4,109 |
649 | |||
South Region: |
||||||
SCOOP |
62,178 |
63,490 |
64,616 | |||
STACK |
29,216 |
24,426 |
11,127 | |||
Arkoma |
1,754 |
1,929 |
2,037 | |||
Other |
1,193 |
1,243 |
1,471 | |||
Total |
213,755 |
209,861 |
230,802 |
Bakken: Outperformance Continues as a Result of Optimized Completions
Continental's Bakken net production averaged 108,992 Boe per day in first quarter 2017. The Company had 50 gross (17 net) operated and non-operated Bakken wells with first production during first quarter 2017.
In the first quarter there were 16 gross operated wells with first production, all of which were completed using the Company's optimized completion techniques, which includes tighter stage spacing, increased proppant per foot, diverter technology, more aggressive flowback, and high-capacity lift technology.
Of these, 14 gross operated wells had 30 days or more of production, and all are outperforming the 980 MBoe (thousand Boe) estimated ultimate recovery (EUR) type curve by an average of 65% at 30 days. Based on an average well cost of $7.0 million and $55 WTI, the 14 wells are expected to average approximately a 75% rate of return, almost double the 40% rate of return originally targeted by the 2017 Bakken drilling program.
Included in this group are four wells with record 30-day production rates:
Continental previously announced seven optimized Bakken completions in February 2017, and they continue to outperform the Bakken 980 MBoe EUR type curve by an average of 55% at 150 days, compared with 35% outperformance of the type curve model at 90 days.
"Our optimized completions are another game changer for the Bakken," said Jack Stark, President. "This technology is delivering record 30-day production rates and almost doubling the rates of return expected from our previous economic models."
Drilling performance continues to advance year-over-year with first quarter 2017 spud-to-total depth cycle times averaging 12 days, a 16% reduction over full-year 2016.
Continental has four operated drilling rigs working in the Bakken and plans to maintain that level through year end. The Company also has seven stimulation crews working in the play and plans to be at nine by mid-year.
SCOOP: Springer Delivers Impressive Results
In first quarter 2017, SCOOP net production averaged 62,178 Boe per day (27% oil), or 29% of the Company's total production in first quarter. Continental had 14 gross (5 net) operated and non-operated wells with first production in first quarter 2017. Continental currently has five operated drilling rigs working in SCOOP.
During the quarter, Continental announced three SCOOP Springer wells. All three wells are outperforming the Company's historical 940 MBoe Springer type curve for a 4,500-foot lateral in their first 30-to-60 days on production. The Cash 1-26H well is outperforming the type curve by 75% at 30 days, the Strassle 1-28-33XH is outperforming the type curve by 35% at 60 days, and the Trammel 1-11-14-23XH is outperforming the type curve by 100% at 60 days.
The wells are located in Grady County, Oklahoma and are the first Springer wells completed by the Company since third quarter 2015. The wells were completed using the Company's latest stimulation designs, including increased proppant per foot and tighter stage spacing.
Initial 24-hour production test rates for these wells are as follows:
Springer drilling times were also reduced through improved drilling and directional control technology. The Cash 1-26H, which was a 4,775-foot lateral, was drilled in 34 days from spud to total depth, down 45% from comparable wells drilled in third quarter 2015. Including costs for the larger stimulation, total completed well cost for the Cash 1-26H was $7.6 million, down $2.7 million, or approximately 25%, compared to the third quarter 2015 Springer wells.
The Company has elected to increase activity in the Springer during 2017 and now plans to complete up to 10 Springer wells during the year.
The Company has approximately 197,000 net acres in the SCOOP Springer, which is located approximately 1,000 feet above the Woodford formation.
Sycamore Further Expands SCOOP Asset Value
Continental announced its first two well completions targeting the Sycamore formation in Grady County, adding yet another highly productive layer in SCOOP to its portfolio. The Company has approximately 300,000 net reservoir acres in the Sycamore, which lies directly above the Woodford formation.
Initial 24-hour production test rates for the Company's new wells included:
The wells have been on production approximately 170 and 180 days, respectively.
Continental is projecting that its SCOOP Sycamore wells will have an average EUR between 1.6 and 2.0 MMBoe, based on a 7,500-foot lateral.
"We are excited about Continental's Sycamore position and the added value it will bring to the Company," said Mr. Stark. "We plan to drill five to seven additional wells during the year focused on delineating the high-liquids windows of the play."
STACK: Continued Successful Well Results
STACK production increased 20% to 29,216 Boe per day in first quarter 2017, compared to fourth quarter 2016. Continental had 27 gross (8 net) operated and non-operated wells with first production in STACK in first quarter 2017.
The Company reported three operated standalone wells in the STACK Meramec over-pressured oil window and one operated well in the over-pressured condensate window.
Initial 24-hour production test rates and flowing casing pressures in pounds per square inch (psi) for these wells included:
The Company has 11 operated rigs in the play, with six rigs targeting the Meramec formation in the over-pressured oil and condensate windows and five targeting the Woodford formation in the Northwest Cana joint development agreement area in Blaine and Custer counties.
Financial Update
"Improving production results, strong cash management and additional operating efficiencies combined to deliver an excellent first quarter," said John Hart, Chief Financial Officer. "This enabled us to come in $33 million below budget on non-acquisition capital expenditures and to reduce debt by $70 million for the quarter."
Continental continues to see accelerating production growth throughout the year and thereafter, he said. "We expect to achieve annual production growth of 20% from 2018 through 2020 while reducing debt below $6 billion. These plans are cash neutral each year at oil prices between $50 and $55 per barrel, reflecting strong well productivity and cost efficiency."
In first quarter 2017, Continental's average realized sales price excluding the effects of derivative positions was $44.69 per barrel of oil and $3.00 per Mcf of gas, or $32.90 per Boe. Based on realizations without the effect of derivatives, the Company's first quarter 2017 oil differential was $7.09 per barrel below the NYMEX daily average for the period. The realized wellhead natural gas price for the quarter was on average $0.29 per Mcf below the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.78 for first quarter 2017. Other select operating costs and expenses for first quarter 2017 included production taxes of 6.5% of oil and natural gas sales; DD&A of $19.84 per Boe; and total G&A of $2.45 per Boe.
Non-acquisition capital expenditures for first quarter 2017 totaled approximately $427.0 million, which was 7% lower than budgeted. Non-acquisition capital expenditures for the quarter included $329.8 million in exploration and development drilling, $69.8 million in leasehold and seismic, and $27.4 million in workovers, recompletions and other.
As of March 31, 2017, Continental's balance sheet included approximately $17.2 million in cash and cash equivalents and $6.5 billion in long-term debt.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
1Q |
4Q |
1Q | |||
2017 |
2016 |
2016 | |||
Average daily production: |
|||||
Crude oil (Bbl per day) |
119,201 |
116,486 |
146,469 | ||
Natural gas (Mcf per day) |
567,328 |
560,251 |
505,998 | ||
Crude oil equivalents (Boe per day) |
213,755 |
209,861 |
230,802 | ||
Average sales prices, excluding effect from derivatives: |
|||||
Crude oil ($/Bbl) |
$44.69 |
$42.23 |
$25.72 | ||
Natural gas ($/Mcf) |
$3.00 |
$2.70 |
$1.36 | ||
Crude oil equivalents ($/Boe) |
$32.90 |
$30.64 |
$19.27 | ||
Production expenses ($/Boe) |
$3.78 |
$3.60 |
$3.76 | ||
Production taxes (% of oil and gas revenues) |
6.5% |
6.4% |
7.6% | ||
DD&A ($/Boe) |
$19.84 |
$20.11 |
$22.16 | ||
Total general and administrative expenses ($/Boe) (1) |
$2.45 |
$2.93 |
$1.55 | ||
Net income (loss) (in thousands) |
$469 |
$27,670 |
($198,326) | ||
Diluted net income (loss) per share |
$0.00 |
$0.07 |
($0.54) | ||
Adjusted net income (loss) (non-GAAP) (in thousands) (2) |
$6,782 |
($27,416) |
($150,467) | ||
Adjusted diluted net income (loss) per share (non-GAAP) (2) |
$0.02 |
($0.07) |
($0.41) | ||
Net cash provided by operating activities |
$470,201 |
$262,031 |
$278,902 | ||
EBITDAX (non-GAAP) (in thousands) (2) |
$482,472 |
$652,382 |
$314,609 |
(1) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.86, $2.21, and $1.11 for 1Q 2017, 4Q 2016, and 1Q 2016, respectively. Non-cash equity compensation expense per Boe was $0.59, $0.72, and $0.44 for 1Q 2017, 4Q 2016, and 1Q 2016, respectively. |
(2) Adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or net cash provided by operating activities as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
First Quarter Earnings Conference Call
Continental plans to host a conference call to discuss first quarter results on Thursday, May 4, 2017, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, May 4, 2017 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
85738716 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
85738716 |
Continental plans to publish a first quarter 2017 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on May 4, 2017.
Upcoming Conferences
Members of Continental's management team plan to participate in the following investment conferences:
May 8-9, 2017 |
Morgan Stanley E&P and Oil Services Conference, Houston |
May 23, 2017 |
UBS Global Oil and Gas Conference, Austin |
June 6, 2017 |
RBC Global Energy & Power Executive Conference, New York |
June 6, 2017 |
Bank of America Merrill Lynch High Yield Conference, New York |
June 19-20, 2017 |
Wells Fargo West Coast Energy Conference, San Francisco |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||
Three months ended March 31, | |||
2017 |
2016 | ||
Revenues: |
In thousands, except per share data | ||
Crude oil and natural gas sales |
$633,850 |
$ 403,592 | |
Gain on crude oil and natural gas derivatives, net |
46,858 |
42,112 | |
Crude oil and natural gas service operations |
4,719 |
7,470 | |
Total revenues |
685,427 |
453,174 | |
Operating costs and expenses: |
|||
Production expenses |
72,854 |
78,640 | |
Production taxes |
41,234 |
30,493 | |
Exploration expenses |
4,998 |
3,066 | |
Crude oil and natural gas service operations |
2,837 |
3,043 | |
Depreciation, depletion, amortization and accretion |
382,156 |
463,992 | |
Property impairments |
51,372 |
78,927 | |
General and administrative expenses |
47,220 |
32,407 | |
Net loss on sale of assets and other |
5,535 |
1,709 | |
Total operating costs and expenses |
608,206 |
692,277 | |
Income (loss) from operations |
77,221 |
(239,103) | |
Other income (expense): |
|||
Interest expense |
(71,172) |
(80,953) | |
Other |
442 |
384 | |
(70,730) |
(80,569) | ||
Income (loss) before income taxes |
6,491 |
(319,672) | |
(Provision) benefit for income taxes (1) |
(6,022) |
121,346 | |
Net income (loss) |
$ 469 |
$(198,326) | |
Basic net income (loss) per share |
$ - |
$ (0.54) | |
Diluted net income (loss) per share |
$ - |
$ (0.54) |
(1) In 1Q 2017 we adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which requires, among other things, that companies recognize excess tax benefits and deficiencies from stock-based compensation as income tax benefit or expense in the income statement rather than through additional paid-in-capital. This change resulted in a $3.3 million increase in income tax expense in 1Q 2017 with no comparable impact in the prior period. |
Continental Resources, Inc. and Subsidiaries | |||||
March 31, 2017 |
December 31, 2016 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
929,506 |
$ |
913,233 | |
Net property and equipment (1) |
12,880,357 |
12,881,227 | |||
Other noncurrent assets |
16,197 |
17,316 | |||
Total assets |
$ |
13,826,060 |
$ |
13,811,776 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
1,005,321 |
$ |
932,393 | |
Long-term debt, net of current portion |
6,508,209 |
6,577,697 | |||
Other noncurrent liabilities |
2,003,176 |
1,999,690 | |||
Total shareholders' equity |
4,309,354 |
4,301,996 | |||
Total liabilities and shareholders' equity |
$ |
13,826,060 |
$ |
13,811,776 | |
(1) Balance is net of accumulated depreciation, depletion and amortization of $8.03 billion and $7.65 billion as of March 31, 2017 and December 31, 2016, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||
Three months ended March 31, | ||||||
In thousands |
2017 |
2016 | ||||
Net income (loss) |
$ |
469 |
$ |
(198,326) | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||
Non-cash expenses |
411,955 |
432,774 | ||||
Changes in assets and liabilities |
57,777 |
44,454 | ||||
Net cash provided by operating activities |
470,201 |
278,902 | ||||
Net cash used in investing activities |
(389,271) |
(358,811) | ||||
Net cash (used in) provided by financing activities |
(80,385) |
81,342 | ||||
Effect of exchange rate changes on cash |
- |
31 | ||||
Net change in cash and cash equivalents |
545 |
1,464 | ||||
Cash and cash equivalents at beginning of period |
16,643 |
11,463 | ||||
Cash and cash equivalents at end of period |
$ |
17,188 |
$ |
12,927 |
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income (loss) or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.
In thousands |
1Q 2017 |
4Q 2016 |
1Q 2016 | ||||||
Net income (loss) |
$ |
469 |
$ |
27,670 |
$ |
(198,326) | |||
Interest expense |
71,172 |
75,613 |
80,953 | ||||||
Provision (benefit) for income taxes |
6,022 |
26,478 |
(121,346) | ||||||
Depreciation, depletion, amortization and accretion |
382,156 |
388,321 |
463,992 | ||||||
Property impairments |
51,372 |
34,564 |
78,927 | ||||||
Exploration expenses |
4,998 |
8,246 |
3,066 | ||||||
Impact from derivative instruments: |
|||||||||
Total (gain) loss on derivatives, net |
(44,961) |
45,331 |
(41,052) | ||||||
Total cash (paid) received on derivatives, net |
(194) |
6,281 |
39,189 | ||||||
Non-cash (gain) loss on derivatives, net |
(45,155) |
51,612 |
(1,863) | ||||||
Non-cash equity compensation |
11,438 |
13,823 |
9,206 | ||||||
Loss on extinguishment of debt |
- |
26,055 |
- | ||||||
EBITDAX |
$ |
482,472 |
$ |
652,382 |
$ |
314,609 | |||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
In thousands |
1Q 2017 |
4Q 2016 |
1Q 2016 | ||||||
Net cash provided by operating activities |
$ |
470,201 |
$ |
262,031 |
$ |
278,902 | |||
Current income tax provision |
1 |
(22,941) |
6 | ||||||
Interest expense |
71,172 |
75,613 |
80,953 | ||||||
Exploration expenses, excluding dry hole costs |
4,841 |
3,613 |
3,066 | ||||||
Gain (loss) on sale of assets, net |
(3,638) |
201,315 |
109 | ||||||
Other, net |
(2,328) |
(1,981) |
(3,973) | ||||||
Changes in assets and liabilities |
(57,777) |
134,732 |
(44,454) | ||||||
EBITDAX |
$ |
482,472 |
$ |
652,382 |
$ |
314,609 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
1Q 2017 |
4Q 2016 |
1Q 2016 | ||||||||||||
In thousands, except per share data |
After-Tax $ |
Diluted EPS |
After-Tax $ |
Diluted EPS |
After-Tax $ |
Diluted EPS | ||||||||
Net income (loss) (GAAP) (1) |
$ 469 |
$ - |
$ 27,670 |
$ 0.07 |
$(198,326) |
$(0.54) | ||||||||
Adjustments: |
||||||||||||||
Non-cash (gain) loss on derivatives |
(45,155) |
51,612 |
(1,863) |
|||||||||||
Property impairments |
51,372 |
34,564 |
78,927 |
|||||||||||
(Gain) loss on sale of assets |
3,638 |
(201,315) |
(109) |
|||||||||||
Loss on extinguishment of debt |
- |
26,055 |
- |
|||||||||||
Total tax effect of adjustments |
(3,542) |
33,998 |
(29,096) |
|||||||||||
Total adjustments, net of tax |
6,313 |
0.02 |
(55,086) |
(0.14) |
47,859 |
0.13 | ||||||||
Adjusted net income (loss) (non-GAAP) |
$ 6,782 |
$0.02 |
$ (27,416) |
$(0.07) |
$(150,467) |
$(0.41) | ||||||||
Weighted average diluted shares outstanding |
373,353 |
370,539 |
370,062 |
|||||||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ 0.02 |
$ (0.07) |
$ (0.41) |
|||||||||||
(1) In 1Q 2017 we adopted ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which requires, among other things, that companies recognize excess tax benefits and deficiencies from stock-based compensation as income tax benefit or expense in the income statement rather than through additional paid-in capital. This change resulted in a $3.3 million ($0.01 per diluted share) decrease in net income in 1Q 2017 with no comparable impact in the prior period. |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | ||
2017 Guidance | ||
As of May 3, 2017 | ||
2017 | ||
Full year average production |
220,000 to 230,000 Boe per day | |
Exit rate average production |
250,000 to 260,000 Boe per day | |
Capital expenditures (non-acquisition) |
$1.95 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.50 to $4.00 | |
Production tax (% of oil & gas revenue) |
6.75% to 7.25% | |
Cash G&A expense per Boe(1) |
$1.50 to $2.00 | |
Non-cash equity compensation per Boe |
$0.60 to $0.70 | |
DD&A per Boe |
$19.00 to $22.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($6.50) to ($7.50) | |
Henry Hub natural gas (per Mcf) |
$0.10 to ($0.40) | |
Income tax rate |
38% | |
Deferred taxes |
90% to 95% |
(1) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $2.10 to $2.70 per Boe. |
SOURCE Continental Resources
OKLAHOMA CITY, April 3, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce first quarter 2017 results on Wednesday, May 3, 2017 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss first quarter 2017 results on Thursday, May 4, 2017 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
Time and date: |
12 p.m. ET, Thursday, May 4, 2017 |
Dial-in: |
844-309-6572 |
Intl. dial-in: |
484-747-6921 |
Conference ID: |
85738716 |
A replay of the call will be available for 14 days on the Company's website or by dialing: | |
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
85738716 |
Continental plans to publish a first quarter 2017 summary presentation to its website at www.CLR.com prior to the start of its conference call on May 4, 2017.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Feb. 22, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced fourth quarter and full-year 2016 operating and financial results. Continental reported net income of $27.7 million, or $0.07 per diluted share, for the quarter ended December 31, 2016. For full-year 2016, the Company reported a net loss of $399.7 million, or $1.08 per diluted share.
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The Company's net income or net loss includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net loss." In fourth quarter 2016, these typically excluded items in aggregate represented $55.1 million, or $0.14 per diluted share, of Continental's reported net income. Adjusted net loss for the fourth quarter was $27.4 million, or $0.07 per diluted share. For full-year 2016, these typically excluded items in aggregate represented $73.0 million, or $0.20 per diluted share. Adjusted net loss for full-year 2016 was $326.6 million, or $0.88 per diluted share.
Key Achievements/Value-Drivers
Net cash provided by operating activities for fourth quarter 2016 was $262.0 million and $1.13 billion for full-year 2016. EBITDAX for fourth quarter 2016 was $652.4 million, contributing to full-year 2016 EBITDAX of $1.9 billion. Definitions and reconciliations of adjusted net loss, adjusted net loss per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures can be found in the supporting tables at the conclusion of this press release.
"I am very proud of our accomplishments in 2016. In another year of volatile commodity markets, Continental's performance really stood out," said Harold Hamm, Chairman and Chief Executive Officer. "Among our key achievements, we expanded the extent of the over-pressured oil window in STACK and are now beginning density development in this premier Oklahoma play. Also, using the latest enhanced completion designs, we set new Company early production records for wells in STACK, SCOOP and the Bakken.
"In the North Dakota Bakken, we began harvesting our high-value backlog of uncompleted wells that will benefit production and cash generation in 2017 and 2018," he said. "I'm also proud that Continental did not dilute shareholders by issuing equity in an adverse market in the past two years. We reduced debt by more than $600 million from its peak in May of 2016 and expect to continue to reduce debt this year.
"Looking to 2017, our strategy is to remain disciplined in our spending to deliver full value to shareholders. We are focused on oil-concentrated production growth and strong investment returns as oil prices stabilize at higher levels," Mr. Hamm said. "As we announced in late January, we expect multi-year production growth of 20% on a cash neutral basis."
Production
Fourth quarter 2016 net production totaled 19.3 million Boe, or approximately 210,000 Boe per day, up slightly from third quarter 2016. Severe weather primarily in the Bakken reduced total production for the fourth quarter by approximately 6,500 Boe per day. February production is estimated to be approximately 215,000 Boe per day, an increase from January, which was also impacted by weather.
Total net production for fourth quarter 2016 included 116,500 barrels of oil (Bo) per day (55% of production) and 560.3 million cubic feet (MMcf) of natural gas per day (45% of production). Full-year 2016 production averaged 216,900 Boe per day. As announced in January, Continental expects to exit 2017 with production in a range of 250,000 to 260,000 Boe per day, a 19%-to-24% increase compared with fourth quarter 2016 production.
The following table provides the Company's average daily production by region for the periods presented.
4Q |
3Q |
4Q |
FY |
FY | ||||||
Boe per day |
2016 |
2016 |
2015 |
2016 |
2015 | |||||
North Region: |
||||||||||
North Dakota Bakken |
96,035 |
99,251 |
125,583 |
109,686 |
124,503 | |||||
Montana Bakken |
8,489 |
8,678 |
10,772 |
9,514 |
12,617 | |||||
Red River Units |
10,140 |
10,475 |
11,654 |
10,745 |
12,342 | |||||
Other |
4,109 |
1,189 |
902 |
1,665 |
1,103 | |||||
South Region: |
||||||||||
SCOOP |
63,490 |
67,462 |
64,534 |
65,062 |
61,586 | |||||
STACK |
24,426 |
17,680 |
7,709 |
16,983 |
5,560 | |||||
Arkoma |
1,929 |
1,833 |
2,124 |
1,915 |
2,104 | |||||
Other |
1,243 |
1,272 |
1,658 |
1,342 |
1,900 | |||||
Total |
209,861 |
207,840 |
224,936 |
216,912 |
221,715 |
STACK Continues to Expand
STACK production increased 38% to approximately 24,400 Boe per day in fourth quarter 2016, compared with third quarter 2016. Production of approximately 17,000 Boe per day for full-year 2016 was three times STACK production for 2015, reflecting the ramp up in activity throughout 2016.
Continental has increased its STACK Meramec leasehold to more than 200,000 net acres, compared with 155,000 net acres at year-end 2015. The Company currently has 12 operated rigs in STACK, with seven targeting the Meramec formation in the over-pressured oil window and five targeting the Woodford formation in the Northwest Cana joint development agreement (JDA) area in Blaine and Custer counties.
The Company reported seven new completions in the STACK Meramec over-pressured oil window for the fourth quarter. Initial 24-hour production test rates for these wells were as follows:
Flowing casing pressures ranged from 2,850 to 3,925 pounds per square inch (psi).
Approximately 47,000 net acres, or 60% of the Company's leasehold in the over-pressured oil window of STACK, has been de-risked and is in development. This includes an estimated 55 operated units that the Company expects will be developed in two Meramec zones, as well as in the Woodford, with a pattern of up to six wells per zone.
Continental is currently drilling or completing five of these units, including the Bernhardt, Blurton, Gillilan, Verona, and Compton units, and it plans to commence a sixth test in the Angus Trust unit in the over-pressured condensate window. These density tests will include up to six wells per zone in combinations of the Upper, Middle and Lower Meramec and the Woodford.
The results of the Company's first density test at the Ludwig unit were announced in November 2016. To date, the eight Meramec wells in the Ludwig unit have produced a combined 1.75 MMBoe.
Deep STACK Success
Another key success in second half 2016 was Continental's completion of three Meramec wells in the over-pressured gas window of STACK. These three wells are located in the southwestern part of the Company's leasehold, in an area called Deep STACK, where the Meramec is encountered at depths of at least 13,000 feet.
Initial 24-hour production test rates included:
Flowing casing pressures ranged from 5,900 to 7,500 psi.
Combined, the three wells have produced 5.8 Bcf and 12.3 MBo and are currently producing 50 MMcf per day and 100 Bo per day at flowing casing pressures between 4,000 and 5,000 psi.
Wells in Deep STACK are projected to have an average EUR of 20 Bcf per well from a 9,800-foot lateral. This would generate an approximate 50% rate of return at a completed well cost of $11.0 million, based on $3.50 per Mcf of gas.
"STACK has clearly become a key catalyst for Continental's growth," said Jack Stark, Continental's President and Chief Operating Officer. "We have never had a play this prolific evolve so quickly. The results have exceeded our early expectations, and the impact on Continental's production growth both near term and long term will be significant."
SCOOP
In fourth quarter 2016, SCOOP net production averaged 63,490 Boe per day (27% oil), or 30% of the Company's total production in fourth quarter. Continental completed 12 gross (5 net) operated and non-operated wells with first production in SCOOP in fourth quarter 2016.
For full-year 2016, the Company completed 71 gross (28 net) operated and non-operated wells with first production in SCOOP. In 2017, the Company plans to average five operated rigs in the play.
SCOOP Woodford Condensate Type Curve EUR Increased Again
Continental announced an additional 15% increase in the type curve EUR for SCOOP Woodford condensate wells to 2.3 MMBoe for a 7,500-foot lateral. This is the second increase in EUR since the Company implemented enhanced completion designs in the play.
At the new EUR, SCOOP condensate wells are expected to generate an impressive 80% rate of return at $55 oil WTI and $3.50 Mcf of gas. This assumes an average completed well cost of $10.3 million for a 7,500-foot lateral.
"As our teams optimize enhanced completions, we are continuing to see wells outperform their offsets," said Gary Gould, Senior Vice President, Production and Resource Development. "Enhanced completions are a successful value driver for us not only in SCOOP, but in all of our plays."
Two recent SCOOP Woodford initial 24-hour production test rates included:
SCOOP Woodford Oil Update
In early 2017 Continental completed the Emery 1R-9-16XH in the SCOOP Woodford oil window. The Emery flowed at an initial 24-hour production rate of 1,334 Boe per day (77% oil) from a 9,700-foot lateral and utilized shorter completion stage spacing.
As announced in November 2016, Continental completed the May unit density test in the SCOOP Woodford oil window. The test included five new wells and two parent wells in the Upper Woodford. To date, the seven wells have produced 934 MBoe (74% oil), and they continue to outperform the type curve.
SCOOP Springer: Resuming Activity
Continental has resumed drilling activity in the SCOOP Springer, which is located approximately 1,000 feet above the Woodford. The Company has approximately 200,000 net acres in the Springer and plans in 2017 to drill and complete five wells in the fairway to test the latest stimulation designs and longer laterals.
Bakken: Larger Enhanced Completions
Continental's Bakken net production averaged 104,500 Boe per day in fourth quarter 2016. The Company completed 64 gross (16 net) operated and non-operated Bakken wells with first production during fourth quarter 2016, compared with a total 204 gross (47 net) operated and non-operated Bakken wells with first production for full-year 2016. The Company ended 2016 with a drilled-well inventory of 187 gross operated wells, including 12 gross operated wells with stimulation complete or in progress, but which did not have first sales in 2016.
Completion activity is accelerating in the first half of 2017, reflecting the addition of completion crews in the play in late 2016. The Company currently has five stimulation crews in the play and plans to increase to eight by mid-May. Continental has four operated drilling rigs working in the Bakken and plans to maintain that level through year end. The Company is targeting completing 148 Bakken gross operated wells with first production in 2017, and ending the year with 72 additional wells stimulated with first production in 2018.
The Company has continued to test various enhanced stimulation designs, along with more aggressive flowback and high-rate production lift. Completion testing has included proppant volumes of up to 2,000 pounds per foot, as well as the use of diverters. The completion designs in combination with more aggressive flowback procedures have increased initial 90-day production rates by approximately 35% for initial wells drilled in units, compared with the 980 MBoe EUR type curve the Company is targeting for its uncompleted well backlog.
Select initial 24-hour production test rates include:
The Holstein Federal 13-25H, combined with the Rath Federal 5-22H and the Brangus North 1-2H2 reported last quarter, have produced the Company's three all-time highest 30-day Bakken rates.
2016 Proved Reserves Increase Despite Lower Commodity Prices
The Company announced proved reserves of 1.27 billion Boe at December 31, 2016, a 4% increase compared with year-end 2015 proved reserves. The 2016 increase was achieved despite lower SEC average commodity prices for the year. The 2016 average SEC oil price was $42.75 per barrel, 15% below the 2015 average price of $50.28 per barrel. The 2016 average SEC natural gas price was $2.49 per MMBtu, compared with $2.58 per MMBtu for 2015.
At December 31, 2016, Continental had a Standardized Measure of discounted future net cash flows of $5.51 billion. Continental's 2016 proved reserves had a net present value discounted at 10% (PV-10) of $6.65 billion. PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $1.14 billion. Continental and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves without regard to specific income tax characteristics.
Year-end 2016 proved reserves were 50% crude oil, 88% operated by the Company, and approximately 41% proved developed producing (PDP).
The Bakken accounted for 592 million Boe, or 46% of Continental's year-end 2016 proved reserves. The SCOOP Woodford and SCOOP Springer plays accounted for 472 MMBoe, or 37% of Continental's year-end 2016 proved reserves.
The STACK Meramec and STACK Woodford plays grew significantly in the past year, and at year end accounted for 161 MMBoe, or 13% of Continental's year-end 2016 proved reserves.
The Company had a total of 1,715 gross (963 net) proved undeveloped (PUD) locations at year-end 2016, with the Bakken accounting for 1,081 gross (600 net) PUD locations. SCOOP accounted for an additional 370 gross (250 net) PUD locations, while STACK accounted for 264 gross (113 net) PUD locations at year-end 2016.
"The impact of STACK on our proved reserves is only beginning to be realized," said Mr. Stark. "The play continues to expand, and at this time we believe it could add as much as 35% to our net unrisked resource potential."
Financial Update: Low Costs per Boe throughout 2016
"We were very pleased to finish 2016 in line with all aspects of our budget," said John Hart, Chief Financial Officer. "Production expense per Boe was down 15% from 2015, even with lower production for the year. This speaks directly to the performance of our operating teams and the premier quality of our assets.
"At year end, long-term debt was slightly under $6.6 billion, reflecting more than a $600 million reduction from peak debt levels in 2016, and leverage metrics continue to improve," he said. "We remain focused on spending within cash flow and plan to sell additional non-strategic assets to further reduce debt."
In fourth quarter 2016, Continental's average realized sales price excluding the effects of derivative positions was $42.23 per barrel of oil and $2.70 per Mcf of gas, or $30.64 per Boe. Based on realizations without the effect of derivatives, the Company's fourth quarter 2016 oil differential was $6.95 per barrel below the NYMEX daily average for the period. The realized wellhead natural gas price for the quarter was on average $0.28 per Mcf below the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.60 for fourth quarter 2016, compared with $3.86 per Boe for fourth quarter 2015. Other select operating costs and expenses for fourth quarter 2016 included production taxes of 6.4% of oil and natural gas sales; DD&A of $20.11 per Boe; and G&A of $2.93 per Boe. On a full-year basis, these expense categories were within guidance.
As of December 31, 2016, Continental's balance sheet included $16.6 million in cash and cash equivalents and $905 million of borrowings against the Company's revolving credit facility. Continental had approximately $1.84 billion in available borrowing capacity under its revolving credit facility as of December 31, 2016, a decrease from the October 31, 2016 level of $2.45 billion, due to borrowings incurred to fund the November redemption of $600 million of Senior Notes.
Continental's 2017 guidance remains as announced on January 25, 2017 and can be found at the conclusion of this press release.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended December 31, |
Year ended December 31, | ||||||
2016 |
2015 |
2016 |
2015 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
116,486 |
145,576 |
128,005 |
146,622 | |||
Natural gas (Mcf per day) |
560,251 |
476,160 |
533,442 |
450,558 | |||
Crude oil equivalents (Boe per day) |
209,861 |
224,936 |
216,912 |
221,715 | |||
Average sales prices, excluding effect from derivatives: |
|||||||
Crude oil ($/Bbl) |
$42.23 |
$34.23 |
$35.51 |
$40.50 | |||
Natural gas ($/Mcf) |
$2.70 |
$2.07 |
$1.87 |
$2.31 | |||
Crude oil equivalents ($/Boe) |
$30.64 |
$26.57 |
$25.55 |
$31.48 | |||
Production expenses ($/Boe) |
$3.60 |
$3.86 |
$3.65 |
$4.30 | |||
Production taxes (% of oil and gas revenues) |
6.4% |
7.8% |
7.0% |
7.8% | |||
DD&A ($/Boe) |
$20.11 |
$22.20 |
$21.54 |
$21.57 | |||
Total general and administrative expenses ($/Boe) (1) |
$2.93 |
$2.24 |
$2.14 |
$2.34 | |||
Net income (loss) (in thousands) |
$27,670 |
($139,677) |
($399,679) |
($353,668) | |||
Diluted net income (loss) per share |
$0.07 |
($0.38) |
($1.08) |
($0.96) | |||
Adjusted net loss (non-GAAP) (in thousands) (2) |
($27,416) |
($86,644) |
($326,648) |
($115,525) | |||
Adjusted diluted net loss per share (non-GAAP) (2) |
($0.07) |
($0.23) |
($0.88) |
($0.31) | |||
Net cash provided by operating activities |
$262,031 |
$441,609 |
$1,125,919 |
$1,857,101 | |||
EBITDAX (non-GAAP) (in thousands) (2) |
652,382 |
$420,239 |
$1,881,889 |
$1,978,896 | |||
(1) |
Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $2.21, $1.68, $1.53, and $1.70 for 4Q 2016, 4Q 2015, FY 2016, and FY 2015, respectively. Non-cash equity compensation expense per Boe was $0.72, $0.56, $0.61, and $0.64 for 4Q 2016, 4Q 2015, FY 2016, and FY 2015, respectively. |
(2) |
Adjusted net loss, adjusted diluted net loss per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or net cash provided by operating activities as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net loss, adjusted diluted net loss per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Fourth Quarter and Full-Year Earnings Conference Call
Continental plans to host a conference call to discuss fourth quarter and full-year results on Thursday, February 23, 2017, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, February 23, 2017 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
26962968 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
26962968 |
Continental plans to publish a fourth quarter and full-year 2016 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 23, 2017.
Upcoming Conferences
Members of Continental's management team plan to participate in the following investment conferences:
March 2-3, 2017 |
17th Annual Simmons/Piper Jaffray Energy Conference, Las Vegas |
March 6-7, 2017 |
Raymond James 38th Annual Institutional Investor Conference, Orlando |
March 7, 2017 |
Evercore ISI Energy/Power Summit 2017, Houston |
March 27-28, 2017 |
Scotia Howard Weil 45th Annual Energy Conference, New Orleans |
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, and once filed, for the year ended December 31, 2016, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||||||
Consolidated Statements of Income (Loss) | |||||||
Three months ended December 31, |
Year ended December 31, | ||||||
2016 |
2015 |
2016 |
2015 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 591,764 |
$ 551,380 |
$ 2,026,958 |
$ 2,552,531 | |||
Gain (loss) on crude oil and natural gas derivatives, net |
(47,382) |
16,540 |
(71,859) |
91,085 | |||
Crude oil and natural gas service operations |
5,307 |
7,560 |
25,174 |
36,551 | |||
Total revenues |
549,689 |
575,480 |
1,980,273 |
2,680,167 | |||
Operating costs and expenses: |
|||||||
Production expenses |
69,544 |
80,185 |
289,289 |
348,897 | |||
Production taxes and other expenses |
38,172 |
43,048 |
142,388 |
200,637 | |||
Exploration expenses |
8,246 |
4,732 |
16,972 |
19,413 | |||
Crude oil and natural gas service operations |
2,162 |
2,292 |
11,386 |
17,337 | |||
Depreciation, depletion, amortization and accretion |
388,321 |
460,778 |
1,708,744 |
1,749,056 | |||
Property impairments |
34,564 |
81,001 |
237,292 |
402,131 | |||
General and administrative expenses |
56,537 |
46,478 |
169,580 |
189,846 | |||
Net gain on sale of assets and other |
(203,154) |
(218) |
(307,844) |
(23,149) | |||
Total operating costs and expenses |
394,392 |
718,296 |
2,267,807 |
2,904,168 | |||
Income (loss) from operations |
155,297 |
(142,816) |
(287,534) |
(224,001) | |||
Other income (expense): |
|||||||
Interest expense |
(75,613) |
(80,175) |
(320,562) |
(313,079) | |||
Loss on extinguishment of debt |
(26,055) |
- |
(26,055) |
- | |||
Other |
519 |
520 |
1,697 |
1,995 | |||
(101,149) |
(79,655) |
(344,920) |
(311,084) | ||||
Income (loss) before income taxes |
54,148 |
(222,471) |
(632,454) |
(535,085) | |||
Provision (benefit) for income taxes |
26,478 |
(82,794) |
(232,775) |
(181,417) | |||
Net income (loss) |
$ 27,670 |
$ (139,677) |
$ (399,679) |
$ (353,668) | |||
Basic net income (loss) per share |
$ 0.07 |
$ (0.38) |
$ (1.08) |
$ (0.96) | |||
Diluted net income (loss) per share |
$ 0.07 |
$ (0.38) |
$ (1.08) |
$ (0.96) |
Continental Resources, Inc. and Subsidiaries | |||||
Consolidated Balance Sheets | |||||
December 31, 2016 |
December 31, 2015 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
913,233 |
$ |
822,339 | |
Net property and equipment (1) |
12,881,227 |
14,063,328 | |||
Other noncurrent assets |
17,316 |
34,141 | |||
Total assets |
$ |
13,811,776 |
$ |
14,919,808 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
932,393 |
$ |
923,028 | |
Long-term debt, net of current portion |
6,577,697 |
7,115,644 | |||
Other noncurrent liabilities |
1,999,690 |
2,212,236 | |||
Total shareholders' equity |
4,301,996 |
4,668,900 | |||
Total liabilities and shareholders' equity |
$ |
13,811,776 |
$ |
14,919,808 |
(1) Balance is net of accumulated depreciation, depletion and amortization of $7.65 billion and $6.45 billion as of December 31, 2016 and December 31, 2015, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||||||
Consolidated Statements of Cash Flows | ||||||||||||
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net income (loss) |
$ |
27,670 |
$ |
(139,677) |
$ |
(399,679) |
$ |
(353,668) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
369,093 |
477,006 |
1,687,814 |
1,982,147 | ||||||||
Changes in assets and liabilities |
(134,732) |
104,280 |
(162,216) |
228,622 | ||||||||
Net cash provided by operating activities |
262,031 |
441,609 |
1,125,919 |
1,857,101 | ||||||||
Net cash (used in) provided by investing activities |
17,256 |
(448,548) |
(532,965) |
(3,046,247) | ||||||||
Net cash (used in) provided by financing activities |
(282,132) |
3,492 |
(587,773) |
1,187,189 | ||||||||
Effect of exchange rate changes on cash |
(8) |
(2,045) |
(1) |
(10,961) | ||||||||
Net change in cash and cash equivalents |
(2,853) |
(5,492) |
5,180 |
(12,918) | ||||||||
Cash and cash equivalents at beginning of period |
19,496 |
16,955 |
11,463 |
24,381 | ||||||||
Cash and cash equivalents at end of period |
$ |
16,643 |
$ |
11,463 |
$ |
16,643 |
$ |
11,463 |
Non-GAAP Financial Measures
PV-10
The Company's PV-10 value, a non-GAAP financial measure, is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, 2016, the Company's PV-10 totaled approximately $6.65 billion. The Standardized Measure of discounted future net cash flows was approximately $5.51 billion at December 31, 2016, representing a $1.14 billion difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at the Standardized Measure. The Company believes the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of the Company's proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company's crude oil and natural gas properties.
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net income (loss) |
$ |
27,670 |
$ |
(139,677) |
$ |
(399,679) |
$ |
(353,668) | ||||
Interest expense |
75,613 |
80,175 |
320,562 |
313,079 | ||||||||
Provision (benefit) for income taxes |
26,478 |
(82,794) |
(232,775) |
(181,417) | ||||||||
Depreciation, depletion, amortization and accretion |
388,321 |
460,778 |
1,708,744 |
1,749,056 | ||||||||
Property impairments |
34,564 |
81,001 |
237,292 |
402,131 | ||||||||
Exploration expenses |
8,246 |
4,732 |
16,972 |
19,413 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total (gain) loss on derivatives, net |
45,331 |
(16,540) |
67,099 |
(91,085) | ||||||||
Total cash received on derivatives, net |
6,281 |
21,019 |
89,522 |
69,553 | ||||||||
Non-cash (gain) loss on derivatives, net |
51,612 |
4,479 |
156,621 |
(21,532) | ||||||||
Non-cash equity compensation |
13,823 |
11,545 |
48,097 |
51,834 | ||||||||
Loss on extinguishment of debt |
26,055 |
- |
26,055 |
- | ||||||||
EBITDAX (non-GAAP) |
$ |
652,382 |
$ |
420,239 |
$ |
1,881,889 |
$ |
1,978,896 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net cash provided by operating activities |
$ |
262,031 |
$ |
441,609 |
$ |
1,125,919 |
$ |
1,857,101 | ||||
Current income tax provision (benefit) |
(22,941) |
2 |
(22,939) |
24 | ||||||||
Interest expense |
75,613 |
80,175 |
320,562 |
313,079 | ||||||||
Exploration expenses, excluding dry hole costs |
3,613 |
4,535 |
12,106 |
11,032 | ||||||||
Gain on sale of assets, net |
201,315 |
218 |
304,489 |
23,149 | ||||||||
Tax benefit (deficiency) from stock-based compensation |
(368) |
- |
(9,828) |
13,177 | ||||||||
Other, net |
(1,613) |
(2,020) |
(10,636) |
(10,044) | ||||||||
Changes in assets and liabilities |
134,732 |
(104,280) |
162,216 |
(228,622) | ||||||||
EBITDAX (non-GAAP) |
$ |
652,382 |
$ |
420,239 |
$ |
1,881,889 |
$ |
1,978,896 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended December 31, | ||||||||||||||
2016 |
2015 | |||||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||||||||
Net income (loss) (GAAP) |
$ 27,670 |
$ 0.07 |
$(139,677) |
$ (0.38) | ||||||||||
Adjustments: |
||||||||||||||
Non-cash loss on derivatives |
51,612 |
4,479 |
||||||||||||
Property impairments |
34,564 |
81,001 |
||||||||||||
Gain on sale of assets |
(201,315) |
(218) |
||||||||||||
Loss on extinguishment of debt |
26,055 |
- |
||||||||||||
Total tax effect of adjustments |
33,998 |
(32,229) |
||||||||||||
Total adjustments, net of tax |
(55,086) |
(0.14) |
53,033 |
0.15 | ||||||||||
Adjusted net loss (non-GAAP) |
$ (27,416) |
$ (0.07) |
$ (86,644) |
$ (0.23) | ||||||||||
Weighted average diluted shares outstanding |
370,539 |
369,662 |
||||||||||||
Adjusted diluted net loss per share (non-GAAP) |
$ (0.07) |
$ (0.23) |
||||||||||||
Year ended December 31, | ||||||||||||||
2016 |
2015 | |||||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | ||||||||||
Net loss (GAAP) |
$(399,679) |
$ (1.08) |
$(353,668) |
$ (0.96) | ||||||||||
Adjustments: |
||||||||||||||
Non-cash (gain) loss on derivatives |
156,621 |
(21,532) |
||||||||||||
Property impairments |
237,292 |
402,131 |
||||||||||||
Gain on sale of assets |
(304,489) |
(23,149) |
||||||||||||
Loss on extinguishment of debt |
26,055 |
- |
||||||||||||
Total tax effect of adjustments |
(42,448) |
(119,307) |
||||||||||||
Total adjustments, net of tax |
73,031 |
0.20 |
238,143 |
0.65 | ||||||||||
Adjusted net loss (non-GAAP) |
$(326,648) |
$ (0.88) |
$(115,525) |
$ (0.31) | ||||||||||
Weighted average diluted shares outstanding |
370,380 |
369,540 |
||||||||||||
Adjusted diluted net loss per share (non-GAAP) |
$ (0.88) |
$ (0.31) |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | ||
2017 Guidance | ||
As of February 22, 2017 | ||
2017 | ||
Full year average production |
220,000 to 230,000 Boe per day | |
Exit rate average production |
250,000 to 260,000 Boe per day | |
Capital expenditures (non-acquisition) |
$1.95 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.50 to $4.00 | |
Production tax (% of oil & gas revenue) |
6.75% to 7.25% | |
Cash G&A expense per Boe(1) |
$1.50 to $2.00 | |
Non-cash equity compensation per Boe |
$0.60 to $0.70 | |
DD&A per Boe |
$19.00 to $22.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($6.50) to ($7.50) | |
Henry Hub natural gas (per Mcf) |
$0.10 to ($0.40) | |
Income tax rate |
38% | |
Deferred taxes |
90% to 95% | |
(1) |
Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $2.10 to $2.70 per Boe. |
SOURCE Continental Resources
OKLAHOMA CITY, Jan. 25, 2017 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced a 2017 capital expenditures budget of $1.95 billion, which is expected to accelerate production growth in second half 2017 to an exit rate of 250,000 to 260,000 barrels of oil equivalent (Boe) per day. Crude oil is projected to account for approximately 59% of total production by year end, compared with approximately 55% in the fourth quarter 2016.
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Fourth quarter 2016 production averaged approximately 210,000 Boe per day, reflecting persistent severe weather in North Dakota since late November 2016. The Company expects production to range between 210,000 and 215,000 Boe per day through first half 2017, after which production is expected to significantly accelerate due to the timing of pad completions in the Bakken and six new multi-well density projects in the over-pressured oil window of Oklahoma's STACK play.
Full-year 2017 production is expected to average approximately 220,000 to 230,000 Boe per day, compared with approximately 217,000 Boe per day for 2016.
Of the total $1.95 billion budget, the Company is allocating $1.72 billion to drilling and completion activities, with the remainder planned to be invested in other opportunities including leasehold and facilities.
More than 80% of the drilling and completion budget is focused on completing the Company's deep inventory of uncompleted wells in North Dakota, additional drilling in the Bakken, and further STACK development, which will drive the 2017 increase in crude oil volumes as a percent of total production. Crude oil production is expected to grow to approximately 150,000 barrels of oil (Bo) per day by year-end 2017, a 29% increase compared with approximately 116,500 Bo per day for fourth quarter 2016. Natural gas production is expected to increase to approximately 630 million cubic feet (MMcf) per day at year-end 2017, an approximate 12% increase over fourth quarter 2016.
The capital budget is projected to be cash neutral for full-year 2017 at an average $55 per barrel NYMEX WTI and $3.14 per thousand cubic feet (Mcf) of natural gas Henry Hub. Continental noted that, at a full-year average $60 per barrel WTI price, the Company would expect to generate approximately $200 million in additional cash.
Budgeted completed well costs reflect further enhancements in completion designs and potential increases in service costs, partially offset by drilling efficiencies and lower drilling day rates as long-term rig contracts expire.
Continental intends to adjust the level of spend if necessary to remain cash neutral for the year. It also continues to target reducing long-term debt to $6 billion or lower using proceeds from the potential sale of non-strategic assets.
2017 Operating Plan
Continental plans to operate an average 20 drilling rigs in 2017, an increase of one rig from 2016. The Company expects to complete a total of 280 gross (178 net) operated wells with first production in 2017. The Company also plans to participate in completing 40 net non-operated wells in 2017, 35 of which will be in the Bakken.
The Company plans to complete 131 gross (100 net) operated wells out of its Bakken uncompleted well inventory with first production commencing by year end. In addition, Continental plans to complete with first production approximately 17 gross (8 net) newly drilled Bakken wells in 2017. At year-end 2017, the Company expects to have 140 Bakken wells in inventory, of which 72 gross (40 net) wells will have been completed but waiting on first sales and 68 gross (47 net) operated wells will be waiting on completion.
In Oklahoma, the Company expects to complete 132 gross (70 net) operated wells with first production in 2017, including 98 gross (50 net) operated wells in STACK and 34 gross (20 net) operated wells in SCOOP.
Outlook for 2018 and Beyond
The Company projects its current inventory will support an average annual production growth rate of more than 20% in 2018 to 2020 at $60 to $65 per barrel NYMEX WTI oil prices and remain cash neutral. At these prices the Company expects to deliver a 2018 exit rate of 290,000 to 310,000 Boe per day, which is an increase of approximately 18% over the projected 2017 exit rate (midpoint to midpoint). Continental expects crude oil production will continue increasing at an accelerated rate, accounting for 60% to 65% of total production in years after 2017.
"We are capitalizing on the exceptional performance delivered by our operating teams the last two years," said Harold Hamm, Chairman and Chief Executive Officer. "Our disciplined 2017 budget and growth plan will position the Company for multiple years of double-digit production growth. I've never been more excited by Continental's opportunities to realize the value of our premier assets and to deliver exceptional shareholder value."
Bakken Well Completions Drive Production Increase
Continental expects to grow Bakken production by approximately 26% in 2017, when comparing the 2017 exit rate to the fourth quarter 2016.
Approximately $550 million, or 70%, of the operated Bakken capital investment in 2017 will be focused on completing wells from the Company's uncompleted well inventory. The Company has five stimulation crews working currently and plans to average seven crews for 2017 as a whole.
Continental plans to apply various enhanced stimulation techniques on all Bakken completions in 2017 to define the optimum designs for future completions. This includes larger proppant loads, diverter technology, shorter stage lengths and shorter cluster spacing. The Company is also applying high-rate production lift technology to accelerate fluid recovery and early production rates. Combined, these techniques add an average of approximately $1.4 million to the previous standard enhanced completion cost of $3.5 million.
For the uncompleted well inventory, the average budgeted completion cost for the larger enhanced completion is approximately $4.9 million per well. The incremental investment is budgeted to deliver an average estimated ultimate recovery (EUR) of 980,000 Boe per well, or approximately 15% over the previous average EUR of 850,000 Boe per well. At $55 per barrel WTI, these completions should generate a cost forward average rate of return in excess of 100%.
The Company also plans to maintain four operated drilling rigs in the Bakken throughout 2017 and drill 101 gross (57 net) operated wells, with 17 gross (8 net) of these wells completed in 2017 with first production. The 17 gross wells will have an average budgeted well cost of approximately $7.0 million. The average EUR for wells drilled in 2017 is expected to be 920,000 Boe per well. At a WTI price of $55 per barrel, these wells should generate over a 40% rate of return.
Oklahoma Outlook: New STACK Density Projects
In Oklahoma, strong liquids-weighted production growth in 2017 will be driven by the completion of six density projects in the over-pressured oil window of STACK, where the Company announced several record-production wells in the past year. STACK year-over-year production growth is expected to be approximately 130% in 2017.
Continental plans to operate an average of 16 drilling rigs this year, of which 11 rigs will be in STACK targeting the Meramec and Woodford formations and five rigs will be drilling in the SCOOP play. The Company plans to average four completion crews in Oklahoma. In 2017, the Company will have an expected average working interest in STACK of approximately 57%, versus an average 42% working interest in 2016.
In the STACK over-pressured oil window, the Company's average budgeted completed well cost is approximately $9.0 million. Wells in the SCOOP Woodford condensate window have an average budgeted completed well cost of $10.3 million. STACK Woodford wells completed as part of the joint development agreement with SK E&S of South Korea have an average budgeted completed well cost of $13.0 million. As noted in Continental's newly posted investor presentation on its website (www.clr.com), new wells in its Oklahoma plays typically generate rates of return ranging from 55% to more than 100% at $55 per barrel WTI and $3.50 per Mcf of natural gas.
2017 Guidance Table
Continental Resources, Inc. | ||
2016 Guidance | ||
As of November 2, 2016 (1) | ||
2017 | ||
Full year average production |
220,000 to 230,000 Boe per day | |
Exit rate average production |
250,000 to 260,000 Boe per day | |
Capital expenditures (non-acquisition) |
$1.95 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.50 to $4.00 | |
Production tax (% of oil & gas revenue) |
6.75% to 7.25% | |
Cash G&A expense per Boe(1) |
$1.50 to $2.00 | |
Non-cash equity compensation per Boe |
$0.60 to $0.70 | |
DD&A per Boe |
$19.00 to $22.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($6.50) to ($7.50) | |
Henry Hub natural gas (per Mcf) |
$0.10 to ($0.40) | |
Income tax rate |
38% | |
Deferred taxes |
90% to 95% |
(1) |
Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $2.10 to $2.70 per Boe. |
Fourth Quarter and Full-Year 2016 Earnings Conference Call
Continental plans to host a conference call to discuss fourth quarter and full-year 2016 results on Thursday, February 23, 2017 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, February 23, 2017 |
Dial-in: |
844-309-6572 |
Intl. dial-in: |
484-747-6921 |
Conference ID: |
26962968 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
26962968 |
Continental plans to publish a fourth quarter and full-year 2016 summary presentation to its website at www.CLR.com prior to the start of its conference call on February 23, 2017.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Dec. 13, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced a new Company record well in the over-pressured oil window of the Oklahoma STACK play. The Angus Trust 1-4-33XH produced 4,642 barrels of oil equivalent (Boe) per day in a 24-hour test, comprised of 2,088 barrels of oil (Bo) and 15.3 million cubic feet (MMcf) of natural gas. During this initial production test, the Angus Trust flowed at 5,200 psi (pounds per square inch). Continental has a 78% working interest in the well.
The Angus Trust well is located immediately north of Continental's Boden 1-15-10XH in south central Blaine County. The Boden produced an initial 24-hour test rate of 3,508 Boe, 28% oil, at a flowing casing pressure of more than 5,000 psi. The Boden was Continental's first completion in the condensate window of the over-pressured STACK. In just over a year, the Boden has produced 591,000 Boe, 26% oil. The Boden is currently producing 1,815 Boe per day, 22% oil, at a flowing casing pressure of 2,900 psi.
"The Angus Trust is another tremendous STACK Meramec well," said Harold Hamm, Chairman and Chief Executive Officer. "Aside from being a Company record well, it further validates our perspective of the extent of the over-pressured oil window."
The Company estimates its total completed well cost for the Angus Trust is $8.9 million, approximately 30% less than the Boden. The Angus Trust's 9,500-foot lateral was completed in 36 stages, with 20 million pounds of white sand, similar to the Boden.
December Production Exit Rate Revised Higher
As a result of strong production in both North Dakota and Oklahoma, the Company has increased its expected production exit rate for December 2016. The Company now expects to exit 2016 with production in a range of 213,000 to 218,000 Boe per day, compared with the previous guidance range of 205,000 to 210,000 Boe per day. The Company expects to maintain approximately this production level through the first quarter of 2017.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Nov. 2, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today reported a net loss of $109.6 million, or $0.30 per diluted share, for the quarter ended September 30, 2016.
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The Company's net loss includes certain items typically excluded by the investment community in published estimates, the result of which is often referred to as "adjusted net loss." In third quarter 2016, these typically excluded items in aggregate represented $26.8 million, or $0.08 per diluted share, of Continental's reported net loss.
EBITDAX for third quarter 2016 was $386.8 million. The Company has defined and reconciled adjusted net loss, adjusted net loss per diluted share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures in supporting tables at the conclusion of this press release under the header Non-GAAP Financial Measures.
"We have expanded the productive footprint of STACK, SCOOP and the Bakken core, and are increasing the value of these assets with density testing and enhanced completions," commented Harold Hamm, Chairman and Chief Executive Officer. "The results of the Ludwig density test in STACK have given us confidence to begin development on acreage we have de-risked in the over-pressured oil window.
"Additionally, we brought on several excellent producers in the Bakken using enhanced completion designs, including two wells that generated CLR-record 30-day initial rates for the Bakken. This is an encouraging start as the Company begins working down its large backlog of Bakken uncompleted wells and capturing their value."
Updated 2016 Guidance Reflects Outperformance and Increased Activity
The Company now expects full-year production will range between 215,000 and 220,000 barrels of oil equivalent (Boe) per day, an increase of 5,000 Boe per day from the low end of previous guidance given in August 2016, and 15,000 to 20,000 Boe per day higher than the original guidance given in January 2016. Continental expects to exit the year with production between 205,000 and 210,000 Boe per day, reflecting a 10,000 Boe per day increase from the low end of previous guidance given in August 2016.
Continental has again improved 2016 guidance for production expense per Boe. The new range is $3.50 to $4.00 per Boe for the year, down $0.25 per Boe from previous guidance. Continued efficiencies in both the Bakken and in Oklahoma are contributing to the lower guidance.
The Company is updating guidance for non-cash equity compensation per Boe by $0.15, to a range of $0.50 to $0.70 per Boe. This brings total G&A (inclusive of cash G&A and non-cash equity compensation) down to an expected range of $1.70 to $2.30 per Boe.
The Company plans to increase the total number of gross operated well completions in 2016 by 32, relative to its previous plan. The Company now expects to complete 119 gross operated wells with first production for the year, including 29 gross operated wells in the Bakken, 33 in SCOOP, 25 in Northwest Cana JDA and 32 in STACK Meramec.
The Company plans to increase from two to four stimulation crews in North Dakota by year-end 2016. The Company now expects to end 2016 with approximately 175 gross operated uncompleted wells in the Bakken and approximately 45 gross operated uncompleted wells in Oklahoma. The projected year-end Bakken uncompleted well count of 175 excludes approximately 15 wells that will have been stimulated by year-end 2016, but not produced with first sales until 2017.
Along with increased well completion activity, Continental has increased its average working interest in both operated and non-operated wells across its plays. Consequently, the Company is increasing guidance for 2016 capital expenditures (non-acquisition) by $180 million to a new budget target of $1.1 billion. Even with the increase, the Company expects to remain cash flow positive in the fourth quarter and for the year, with excess cash flow currently planned for further reduction of debt.
2016 Updated Guidance Metrics |
Updated 2016 Guidance |
August 2016 Guidance |
Production guidance (Boe per day) |
215,000 to 220,000 |
210,000 to 220,000 |
Capital expenditures (non-acquisition) |
$1.1 billion |
$920 million |
Production expense per Boe |
$3.50 to $4.00 |
$3.75 to $4.25 |
Non-cash equity compensation per Boe |
$0.50 to $0.70 |
$0.65 to $0.85 |
The Company's full 2016 guidance is stated in a table at the conclusion of this release.
Solid Third Quarter Production Results Even with Curtailed Production
Third quarter 2016 net production totaled approximately 19.1 million Boe (MMBoe), or 207,840 Boe per day, down 5% from second quarter 2016 and 9% lower than third quarter 2015. This decline, as expected, was concentrated in the Bakken play. However, third quarter 2016 production in Continental's Southern Region was a record 88,247 Boe per day. The Company curtailed Bakken production by approximately 12,000 net Boe per day during August and September due to lower commodity prices. Curtailed production was brought back online at the end of third quarter. Current total production is approximately 214,000 Boe per day.
Total net production for third quarter 2016 included 116,277 barrels of oil (Bo) per day (56% of total production) and 549.4 million cubic feet (MMcf) of natural gas per day (44% of total production). The oil and gas split for the third quarter reflected the curtailed oil production in the quarter and heightened activity in Oklahoma.
The following table provides the Company's average daily production by region for the periods presented.
3Q |
2Q |
3Q |
YTD |
YTD | |||||||
Boe per day |
2016 |
2016 |
2015 |
2016 |
2015 | ||||||
North Region: |
|||||||||||
North Dakota Bakken |
99,251 |
114,554 |
123,560 |
114,269 |
124,139 | ||||||
Montana Bakken |
8,678 |
10,474 |
12,049 |
9,858 |
13,239 | ||||||
Red River Units |
10,475 |
11,075 |
12,110 |
10,949 |
12,574 | ||||||
Other |
1,189 |
695 |
992 |
845 |
1,171 | ||||||
South Region: |
|||||||||||
SCOOP |
67,462 |
64,669 |
69,136 |
65,589 |
60,592 | ||||||
STACK/NW Cana |
17,680 |
14,610 |
6,629 |
14,484 |
4,836 | ||||||
Arkoma |
1,833 |
1,862 |
2,056 |
1,911 |
2,097 | ||||||
Other |
1,272 |
1,384 |
1,746 |
1,375 |
1,982 | ||||||
Total |
207,840 |
219,323 |
228,278 |
219,280 |
220,630 |
STACK: Ludwig Density Results Provide a Vision for Future Development of the Over-Pressured Oil Window
STACK/Northwest Cana production increased 21% to 17,680 Boe per day in third quarter 2016, compared with second quarter 2016.
A key milestone in the third quarter was Continental's completion of its first density test in the over-pressured oil window of STACK. This was an eight-well Meramec density test in the Ludwig unit, including seven new wells and the original Ludwig 1-22-15XH well. The combined peak 24-hour rate from all eight Meramec wells in the unit was 21,354 Boe per day. The seven new Meramec wells flowed at a combined peak 24-hour rate of 18,572 Boe per day, or 2,653 Boe per day per well, with 70% of the production being oil. The initial Ludwig well has produced 298,000 Boe (74% oil) in 338 days and continues to flow at 815 Boe per day.
The average flowing casing pressure on the seven new wells was 1,775 psi, in line with the original Ludwig well of 1,800 psi at the time of its initial production. The density test included four wells in the Upper Meramec and four wells in the Middle Meramec, spaced 1,320 feet apart in the same zone, and offset 660 feet between zones with approximately 100 feet of vertical separation. Average lateral length for the new wells was 9,700 feet.
The Ludwig density project demonstrates the efficiency gains of multi-well pad drilling. Drilling times for the new Ludwig density wells averaged 25 days, a 36% reduction compared with the initial Ludwig well drilled in June 2015. Average completed well cost for the new Ludwig density wells was $7.8 million per well, 30% below the initial Ludwig well's cost of $11.1 million. This provides a rate of return of more than 100% for these wells at $50 per barrel WTI and $3.00 per Mcf.
"We couldn't be more pleased with the Ludwig density results," said Jack Stark, President and Chief Operating Officer. "Initial production rates were right in line with expectations, demonstrating the remarkable consistency of production and the enormous value of our leasehold in STACK. As expected, well costs came down significantly, due to pad drilling efficiencies. These efficiencies will benefit future development in STACK."
The Company currently considers approximately 47,000 net acres of its leasehold in the over-pressured oil window of STACK to be de-risked and ready for development. This includes an estimated 55 operated units that the Company expects to be developed in up to three Meramec zones and the Woodford, with typically four or more wells per zone.
The Company is currently in the process of drilling four unit developments in the over-pressured oil window including the Bernhardt, Blurton, Gillilan and Verona units in Blaine County. These unit developments will include up to five wells per zone in combinations of the Upper, Middle and Lower Meramec and Woodford zones. An additional 11 units are planned for development, and preparations are underway to facilitate ongoing unit development, including installation of additional water gathering and recycling facilities.
In addition to the Ludwig density wells, in the third quarter the Company completed the McBee 1-3H flowing 1,232 Bo and 5.3 MMcf (2,110 Boe) per day at 3,850 psi flowing casing pressure. The McBee 1-3H was drilled with a 4,760-foot lateral and is located approximately 12 miles west of the Ludwig unit.
The cost of a standalone extended lateral well in the over-pressured oil window of STACK continues to come down as efficiencies build. Continental is now targeting an average completed well cost of $8.5 million for a standalone extended-lateral well in the over-pressured oil window of STACK. This is $500,000 per well below the previous year-end 2016 target and $2.5 million below the cost for a single operated well at year-end 2015. At this targeted cost, Continental estimates a well in the over-pressured oil window should deliver more than a 100% rate of return at $50 per barrel WTI and $3.00 per Mcf. This rate of return assumes an estimated ultimate recovery (EUR) of 1.7 MMBoe per well.
During the third quarter, Continental increased its STACK Meramec leasehold by approximately 4,000 net acres to over 186,000 net acres, located primarily in Blaine, Dewey and Custer counties. Since year-end 2015, the Company has added approximately 31,000 net acres of leasehold in STACK. The Company estimates 95% of its STACK leasehold is in the over-pressured window, of which 40% is in the oil window, 40% is in the condensate window and 20% is in the gas window. The Company has 11 operated rigs in STACK, with six targeting the Meramec formation in Blaine County and five targeting the Woodford formation in the Northwest Cana JDA area in Blaine and Custer counties.
The Company also reported four new STACK Woodford completions in the NW Cana JDA in third quarter, with the NE Atteberry reporting a record 24-hour production rate for a NW Cana JDA well. The Reece Jane is still cleaning up with expectations the initial production rate will improve. Current initial 24-hour production test rates for these wells with flowing casing pressures expressed in pounds per square inch (psi) include:
The Company's previously announced STACK Woodford completion in NW Cana, the Lacretia 1-29-20XH, continues to produce at strong rates and pressure. The Lacretia has produced approximately 2.7 Bcf in 230 days and continues to flow at 8.8 MMcf per day, with a flowing casing pressure of 2,250 psi.
SCOOP Play: Excellent Woodford Density Results in the May Unit
In third quarter 2016, total SCOOP net production averaged 67,462 Boe per day, 4% above second quarter 2016 and slightly lower than third quarter 2015. SCOOP production represented 32% of the Company's total production in third quarter 2016. SCOOP Woodford net production averaged 60,222 Boe per day in third quarter 2016, compared with SCOOP Springer net production of 7,240 Boe per day.
Continental completed 8 net (12 gross) operated and non-operated wells in SCOOP Woodford in third quarter 2016, while operating an average of four rigs in the play.
Continental recently completed its first enhanced completion density test in the SCOOP Woodford oil window at the May unit. This was a seven-well density test, including five new wells and two parent wells in the Upper Woodford. The seven Woodford wells flowed at a combined peak 24-hour rate of 5,285 Bo and 9.6 MMcf per day (6,881 Boe per day). On a per-well basis, the seven wells average peak production was 983 Boe per day (77% oil), and the five new wells average peak production was 974 Boe per day (77% oil). Wells are spaced 775 feet apart, and average lateral length for the seven wells was 7,300 feet. Average completed well cost for the seven wells was approximately $9.3 million.
"Based on initial production, the May unit infill with enhanced completions has outperformed offset wells," said Gary Gould, Senior Vice President, Production and Resource Development. "The initial results are encouraging for future development in the SCOOP Woodford oil window."
Record Company Bakken Well Production from Enhanced Completions
Continental's Bakken production averaged 107,929 Boe per day in third quarter 2016, a decrease of 14% from second quarter 2016. Continental completed 13 net (50 gross) operated and non-operated wells in the Bakken in third quarter 2016, while operating an average of four drilling rigs in the play.
During the third quarter, the Company continued to test enhanced stimulation designs, with higher proppant volumes of up to 1,000 pounds per foot. Select initial 24-hour production test rates include:
The Brangus North and the Rath Federal wells, which used diverter technology, established Continental all-time record 30-day production rates for the Bakken. During the first 30 days, the Brangus North produced 51.8 MBoe (86% oil) and the Rath Federal produced 43.3 MBoe (84% oil).
"We are encouraged by the record performance from these enhanced stimulated wells," said Mr. Gould. "These are direct results of our team's success in continuing to optimize our stimulation designs, which will further improve production and profitability for our large, high rate-of-return uncompleted well inventory in 2017."
The Company has elected to begin completing its inventory of uncompleted Bakken wells. The Company is currently utilizing two stimulation crews, with plans to have a total of four stimulation crews operating by year-end 2016. With this increased activity, the Company expects to complete nine additional gross operated wells in 2016 above previous guidance. Also, an additional 15 gross operated wells will be stimulated, but will not have first sales until 2017. This will leave in inventory approximately 175 gross operated uncompleted wells at year-end 2016. This inventory has an average EUR of approximately 850,000 Boe per well, with an estimated average completion cost of $3.5 million per well. At $50 per barrel WTI and $3.00 per Mcf, the cost-forward rate of return on this incremental capital expenditure is more than 100%.
The Company's total completed well cost for a Bakken 2-mile lateral well with a standard 30-stage slick water enhanced stimulation design is approximately $6.0 million, down from $6.8 million at year-end 2015.
Financial Update
In third quarter 2016, Continental's average realized sales price, excluding the effects of derivative positions, was $37.66 per Bo and $2.02 per Mcf of gas, or $26.42 per Boe. Based on realizations without the effect of derivatives, the Company's third quarter 2016 oil differential was $7.27 per barrel below the NYMEX daily average for the period. Third quarter 2016 realized wellhead natural gas price, without the effect of derivatives, was on average $0.80 per Mcf below the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.50 for third quarter 2016, a decrease of $0.50 per Boe from third quarter 2015. Other select operating costs and expenses for third quarter 2016 included production taxes of 6.8% of oil and natural gas sales; DD&A of $21.66 per Boe; and G&A (cash and non-cash) of $2.32 per Boe.
As of September 30, 2016, Continental's balance sheet included $19.5 million in cash and cash equivalents and $565 million of borrowings against the Company's revolving credit facility, compared to the revolver balance of $885 million at June 30, 2016. As of October 31, 2016, borrowings against the revolving credit facility had declined further to $295 million. Continental had approximately $2.45 billion in available borrowing capacity under its revolving credit facility as of October 31, 2016. The decrease in revolving credit facility borrowings in October is primarily due to the use of proceeds from the completed sale in October of non-core SCOOP leasehold for $296 million, announced in August 2016. The Company plans to borrow $624 million in November to fund the redemption of $600 million of Senior Notes, along with associated redemption premiums and accrued interest.
Capital expenditures for third quarter 2016 were $247 million, including $8 million for acquisitions. Non-acquisition capital expenditures for third quarter 2016 included $198 million in exploration and development drilling, $24 million in leasehold and seismic, and $17 million in workovers, recompletions and other.
"Continental remains on track to be cash flow positive for both the fourth quarter and for the year, inclusive of the increase in our capital expenditures budget," said John Hart, Chief Financial Officer. "We plan to continue reducing long-term debt and improving our leverage metrics through a combination of non-strategic asset sales and strengthened cash flow. Specific 2017 guidance should be announced early next year."
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations, and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended September 30, |
Nine months ended September 30, | ||||||
2016 |
2015 |
2016 |
2015 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
116,277 |
147,472 |
131,873 |
146,975 | |||
Natural gas (Mcf per day) |
549,374 |
484,834 |
524,441 |
441,930 | |||
Crude oil equivalents (Boe per day) |
207,840 |
228,278 |
219,280 |
220,630 | |||
Average sales prices, excluding effect from derivatives: |
|||||||
Crude oil ($/Bbl) |
$37.66 |
$38.95 |
$33.51 |
$42.60 | |||
Natural gas ($/Mcf) |
$2.02 |
$2.23 |
$1.57 |
$2.39 | |||
Crude oil equivalents ($/Boe) |
$26.42 |
$29.90 |
$23.91 |
$33.18 | |||
Production expenses ($/Boe) |
$3.50 |
$4.00 |
$3.66 |
$4.45 | |||
Production taxes (% of oil and gas revenues) |
6.8% |
7.6% |
7.3% |
7.8% | |||
DD&A ($/Boe) |
$21.66 |
$21.36 |
$22.00 |
$21.36 | |||
Total general and administrative expenses ($/Boe) (1) |
$2.32 |
$2.56 |
$1.88 |
$2.38 | |||
Net loss (in thousands) |
($109,621) |
($82,423) |
($427,348) |
($213,992) | |||
Diluted net loss per share |
($0.30) |
($0.22) |
($1.15) |
($0.58) | |||
Adjusted net loss (non-GAAP) (in thousands) (2) |
($82,853) |
($43,512) |
($299,232) |
($28,881) | |||
Adjusted diluted net loss per share (non-GAAP) (2) |
($0.22) |
($0.12) |
($0.81) |
($0.08) | |||
Net cash provided by operating activities |
$366,167 |
$498,680 |
$863,888 |
$1,415,492 | |||
EBITDAX (non-GAAP) (in thousands) (2) |
$386,789 |
$472,221 |
$1,229,507 |
$1,558,656 | |||
(1) Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.63, $1.95, $1.31, and $1.71 for 3Q 2016, 3Q 2015, YTD 2016, and YTD 2015, respectively. Non-cash equity compensation expense per Boe was $0.69, $0.61, $0.57, and $0.67 for 3Q 2016, 3Q 2015, YTD 2016, and YTD 2015, respectively. | |||||||
(2) Adjusted net loss, adjusted diluted net loss per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net loss, diluted net loss per share, or net cash provided by operating activities as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net loss, adjusted diluted net loss per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Third Quarter 2016 Earnings Conference Call
Continental plans to host a conference call to discuss third quarter results on Thursday, November 3, 2016, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, November 3, 2016 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
69753165 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
69753165 |
Continental plans to publish a third quarter 2016 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on November 3, 2016.
Upcoming Conferences
Members of Continental's management team will be participating in the following upcoming investment conferences:
November 17-18, 2016 – Bank of America Merrill Lynch Global Energy Conference, Miami
November 29, 2016 – Capital One STACK/SCOOP Day, New York
December 7-8, 2016 – Capital One 11th Annual Energy Conference, New Orleans
Presentation materials for all conferences listed above will be available on the Company's website at www.CLR.com on or prior to the day of the presentations.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2017, the Company will celebrate 50 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||||||
Unaudited Condensed Consolidated Statements of Loss | |||||||
Three months ended September 30, |
Nine months ended September 30, | ||||||
2016 |
2015 |
2016 |
2015 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 505,892 |
$ 628,457 |
$ 1,435,194 |
$ 2,001,151 | |||
Gain (loss) on crude oil and natural gas derivatives, net |
15,668 |
46,527 |
(24,477) |
74,545 | |||
Crude oil and natural gas service operations |
4,639 |
7,685 |
19,867 |
28,991 | |||
Total revenues |
526,199 |
682,669 |
1,430,584 |
2,104,687 | |||
Operating costs and expenses: |
|||||||
Production expenses |
67,022 |
84,036 |
219,745 |
268,712 | |||
Production taxes and other expenses |
34,583 |
47,682 |
104,216 |
157,589 | |||
Exploration expenses |
3,987 |
232 |
8,726 |
14,680 | |||
Crude oil and natural gas service operations |
2,605 |
4,059 |
9,224 |
15,045 | |||
Depreciation, depletion, amortization and accretion |
414,671 |
448,809 |
1,320,423 |
1,288,278 | |||
Property impairments |
57,689 |
96,697 |
202,728 |
321,130 | |||
General and administrative expenses |
44,389 |
53,798 |
113,043 |
143,368 | |||
Net gain on sale of assets and other |
(5,564) |
(288) |
(104,690) |
(22,930) | |||
Total operating costs and expenses |
619,382 |
735,025 |
1,873,415 |
2,185,872 | |||
Loss from operations |
(93,183) |
(52,356) |
(442,831) |
(81,185) | |||
Other income (expense): |
|||||||
Interest expense |
(82,074) |
(79,399) |
(244,949) |
(232,904) | |||
Other |
360 |
588 |
1,178 |
1,474 | |||
(81,714) |
(78,811) |
(243,771) |
(231,430) | ||||
Loss before income taxes |
(174,897) |
(131,167) |
(686,602) |
(312,615) | |||
Benefit for income taxes |
(65,276) |
(48,744) |
(259,254) |
(98,623) | |||
Net loss |
$ (109,621) |
$ (82,423) |
$ (427,348) |
$ (213,992) | |||
Basic net loss per share |
$ (0.30) |
$ (0.22) |
$ (1.15) |
$ (0.58) | |||
Diluted net loss per share |
$ (0.30) |
$ (0.22) |
$ (1.15) |
$ (0.58) |
Continental Resources, Inc. and Subsidiaries | |||||
Unaudited Condensed Consolidated Balance Sheets | |||||
September 30, 2016 |
December 31, 2015 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
750,875 |
$ |
822,339 | |
Net property and equipment (1) |
13,094,683 |
14,063,328 | |||
Other noncurrent assets |
19,694 |
34,141 | |||
Total assets |
$ |
13,865,252 |
$ |
14,919,808 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
802,350 |
$ |
923,028 | |
Long-term debt, net of current portion |
6,830,141 |
7,115,644 | |||
Other noncurrent liabilities |
1,972,063 |
2,212,236 | |||
Total shareholders' equity |
4,260,698 |
4,668,900 | |||
Total liabilities and shareholders' equity |
$ |
13,865,252 |
$ |
14,919,808 | |
(1) Balance is net of accumulated depreciation, depletion and amortization of $7.35 billion and $6.45 billion as of September 30, 2016 and December 31, 2015, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||||||
Three months ended September 30, |
Nine months ended September 30, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net loss |
$ |
(109,621) |
$ |
(82,423) |
$ |
(427,348) |
$ |
(213,992) | ||||
Adjustments to reconcile net loss to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
415,690 |
465,606 |
1,318,720 |
1,505,141 | ||||||||
Changes in assets and liabilities |
60,098 |
115,497 |
(27,484) |
124,343 | ||||||||
Net cash provided by operating activities |
366,167 |
498,680 |
863,888 |
1,415,492 | ||||||||
Net cash used in investing activities |
(32,427) |
(634,396) |
(550,221) |
(2,597,699) | ||||||||
Net cash (used in) provided by financing activities |
(330,802) |
132,031 |
(305,641) |
1,183,697 | ||||||||
Effect of exchange rate changes on cash |
(2) |
(4,818) |
7 |
(8,916) | ||||||||
Net change in cash and cash equivalents |
2,936 |
(8,503) |
8,033 |
(7,426) | ||||||||
Cash and cash equivalents at beginning of period |
16,560 |
25,458 |
11,463 |
24,381 | ||||||||
Cash and cash equivalents at end of period |
$ |
19,496 |
$ |
16,955 |
$ |
19,496 |
$ |
16,955 | ||||
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net loss and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net loss or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net loss to EBITDAX for the periods presented.
Three months ended September 30, |
Nine months ended September 30, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net loss |
$ |
(109,621) |
$ |
(82,423) |
$ |
(427,348) |
$ |
(213,992) | ||||
Interest expense |
82,074 |
79,399 |
244,949 |
232,904 | ||||||||
Benefit for income taxes |
(65,276) |
(48,744) |
(259,254) |
(98,623) | ||||||||
Depreciation, depletion, amortization and accretion |
414,671 |
448,809 |
1,320,423 |
1,288,278 | ||||||||
Property impairments |
57,689 |
96,697 |
202,728 |
321,130 | ||||||||
Exploration expenses |
3,987 |
232 |
8,726 |
14,680 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total (gain) loss on derivatives, net |
(15,237) |
(46,527) |
21,768 |
(74,545) | ||||||||
Total cash received on derivatives, net |
5,274 |
11,917 |
83,241 |
48,534 | ||||||||
Non-cash (gain) loss on derivatives, net |
(9,963) |
(34,610) |
105,009 |
(26,011) | ||||||||
Non-cash equity compensation |
13,228 |
12,861 |
34,274 |
40,290 | ||||||||
EBITDAX (non-GAAP) |
$ |
386,789 |
$ |
472,221 |
$ |
1,229,507 |
$ |
1,558,656 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended September 30, |
Nine months ended September 30, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net cash provided by operating activities |
$ |
366,167 |
$ |
498,680 |
$ |
863,888 |
$ |
1,415,492 | ||||
Current income tax provision (benefit) |
(10) |
12 |
2 |
22 | ||||||||
Interest expense |
82,074 |
79,399 |
244,949 |
232,904 | ||||||||
Exploration expenses, excluding dry hole costs |
3,960 |
51 |
8,493 |
6,497 | ||||||||
Gain on sale of assets, net |
6,158 |
288 |
103,174 |
22,930 | ||||||||
Tax benefit (deficiency) from stock-based compensation |
(9,460) |
13,177 |
(9,460) |
13,177 | ||||||||
Other, net |
(2,002) |
(3,889) |
(9,023) |
(8,023) | ||||||||
Changes in assets and liabilities |
(60,098) |
(115,497) |
27,484 |
(124,343) | ||||||||
EBITDAX (non-GAAP) |
$ |
386,789 |
$ |
472,221 |
$ |
1,229,507 |
$ |
1,558,656 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments and gains and losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended September 30, | |||||||||||||||
2016 |
2015 | ||||||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | |||||||||||
Net loss (GAAP) |
$(109,621) |
$ (0.30) |
$ (82,423) |
$ (0.22) | |||||||||||
Adjustments: |
|||||||||||||||
Non-cash gain on derivatives |
(9,963) |
(34,610) |
|||||||||||||
Property impairments |
57,689 |
96,697 |
|||||||||||||
Gain on sale of assets |
(6,158) |
(288) |
|||||||||||||
Total tax effect of adjustments |
(14,800) |
(22,888) |
|||||||||||||
Total adjustments, net of tax |
26,768 |
0.08 |
38,911 |
0.10 | |||||||||||
Adjusted net loss (non-GAAP) |
$ (82,853) |
$ (0.22) |
$ (43,512) |
$ (0.12) | |||||||||||
Weighted average diluted shares outstanding |
370,483 |
369,599 |
|||||||||||||
Adjusted diluted net loss per share (non-GAAP) |
$ (0.22) |
$ (0.12) |
|||||||||||||
Nine months ended September 30, | |||||||||||||||
2016 |
2015 | ||||||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | |||||||||||
Net loss (GAAP) |
$(427,348) |
$ (1.15) |
$(213,992) |
$ (0.58) | |||||||||||
Adjustments: |
|||||||||||||||
Non-cash (gain) loss on derivatives |
105,009 |
(26,011) |
|||||||||||||
Property impairments |
202,728 |
321,130 |
|||||||||||||
Gain on sale of assets |
(103,174) |
(22,930) |
|||||||||||||
Total tax effect of adjustments |
(76,447) |
(87,078) |
|||||||||||||
Total adjustments, net of tax |
128,116 |
0.34 |
185,111 |
0.50 | |||||||||||
Adjusted net loss (non-GAAP) |
$(299,232) |
$ (0.81) |
$ (28,881) |
$ (0.08) | |||||||||||
Weighted average diluted shares outstanding |
370,327 |
369,499 |
|||||||||||||
Adjusted diluted net loss per share (non-GAAP) |
$ (0.81) |
$ (0.08) |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | ||
2016 Guidance | ||
As of November 2, 2016 (1) | ||
2016 | ||
Full year average production |
215,000 - 220,000 Boe per day | |
Capital expenditures (non-acquisition) |
$1.1 billion | |
Operating Expenses: |
||
Production expense per Boe |
$3.50 - $4.00 | |
Production tax (% of oil & gas revenue) |
6.75% - 7.25% | |
Cash G&A expense per Boe(2) |
$1.20 - $1.60 | |
Non-cash equity compensation per Boe |
$0.50 - $0.70 | |
DD&A per Boe |
$20.00 - $22.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($7.00) - ($8.00) | |
Henry Hub natural gas (per Mcf) |
$0.00 - ($0.65) | |
Income tax rate |
38% | |
Deferred taxes |
90% - 95% | |
(1) Bolded items denote a guidance revision from the previous disclosure provided on August 3, 2016. | ||||
(2) Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. Guidance for total G&A (cash and non-cash) is an expected range of $1.70 to $2.30 per Boe. |
SOURCE Continental Resources
OKLAHOMA CITY, Oct. 4, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") announced today that it will redeem all of its outstanding 7 3/8% Senior Notes due 2020 (the "2020 Notes") and 7 1/8% Senior Notes due 2021 (the "2021 Notes") on November 10, 2016, the redemption date for both the 2020 Notes and 2021 Notes.
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The redemption price for the 2020 Notes will be equal to 102.458% of the principal amount plus accrued and unpaid interest, if any, to the redemption date of November 10, 2016 in accordance with the terms of the 2020 Notes and the related indenture under which the 2020 Notes were issued. The aggregate principal amount of the 2020 Notes outstanding is $200 million.
The redemption price for the 2021 Notes will be equal to 103.563% of the principal amount plus accrued and unpaid interest, if any, to the redemption date of November 10, 2016 in accordance with the terms of the 2021 Notes and the related indenture under which the 2021 Notes were issued. The aggregate principal amount of the 2021 Notes outstanding is $400 million.
John Hart, Chief Financial Officer, commented, "We are pleased to announce the Company is calling its 2020 Notes and 2021 Notes totaling $600 million. We expect to fund the redemptions from proceeds of our 2016 completed and pending asset divestitures. Once these bonds are redeemed, we expect total outstanding debt to be approximately $6.6 billion, down from approximately $7.2 billion at June 30, 2016. We will continue to consider options to further reduce debt while increasing cash flow from operations."
Additional information concerning the terms and conditions of the redemptions are fully described in the notices distributed to holders of the 2020 Notes and 2021 Notes. Beneficial holders with any questions about the redemptions should contact their respective brokerage firm or financial institution.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Sept. 30, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce third quarter 2016 results on Wednesday, November 2, 2016 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss third quarter 2016 results on Thursday, November 3, 2016 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
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Time and date: |
12 p.m. ET, Thursday, November 3, 2016 |
Dial-in: |
844-309-6572 |
Intl. dial-in: |
484-747-6921 |
Conference ID: |
69753165 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
69753165 |
Continental plans to publish a third quarter 2016 summary presentation to its website at www.CLR.com prior to the start of its conference call on November 3, 2016.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Aug. 18, 2016 /PRNewswire/ -- Continental announced today that it has signed a definitive purchase and sale agreement with an undisclosed buyer to sell non-strategic properties in North Dakota and Montana for $222 million. The sale includes 68,000 net acres of leasehold primarily in western Williams County, North Dakota, and 12,000 net acres of leasehold in Roosevelt County, Montana. The sale also includes net production of approximately 2,800 barrels of oil equivalent (Boe) per day. The agreement provides for customary closing conditions and adjustments.
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"This is our third sale of non-strategic assets this year, with total expected proceeds of more than $600 million. We plan to apply proceeds to reduce debt and strengthen our balance sheet," said Harold Hamm, Chairman and Chief Executive Officer.
In May 2016, the Company announced the sale of approximately 132,000 net acres of leasehold in the Washakie Basin in Wyoming for $110 million. On August 3, 2016, Continental announced it had signed a definitive purchase and sale agreement with an undisclosed buyer to sell approximately 29,500 net acres of non-strategic leasehold in the eastern SCOOP play in Oklahoma for $281 million.
"Our guidance for the year has not changed. The combination of Continental's high quality drilling inventory, strong balance sheet and $560 million investment in drilled but uncompleted wells (DUCs) provides the Company with a robust platform for high-value future growth," Mr. Hamm said. The $560 million investment includes both operated and non-operated DUCs, approximately 80% of which are in North Dakota.
Continental currently has approximately 215 gross operated DUCs in inventory, of which approximately 165 are in the Bakken. The Company expects the total to grow to approximately 240 gross operated DUCs at year-end 2016, with approximately 190 in the Bakken. The Company said its Bakken DUCs have an average estimated ultimate recovery (EUR) of 850,000 Boe per well and can be completed at an average cost of between $3.0 million to $3.5 million per well.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Aug. 3, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today reported a net loss of $119.4 million, or $0.32 per diluted share, for the quarter ended June 30, 2016.
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The Company's net loss includes certain items typically excluded by the investment community in published estimates, the result of which is often referred to as "adjusted net loss." In second quarter 2016, these typically excluded items in aggregate represented $53.5 million, or $0.14 per diluted share, of Continental's reported net loss.
EBITDAX for second quarter 2016 was $528.1 million. The Company has defined and reconciled adjusted net loss, adjusted net loss per diluted share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures in supporting tables at the conclusion of this press release under the header Non-GAAP Financial Measures.
"Continental once again outperformed production guidance in the second quarter thanks to the exceptional quality and performance of our Bakken, SCOOP and STACK assets, as well as exceptional execution by our teams," commented Harold Hamm, Chairman and Chief Executive Officer. "We are also on track to reduce long-term debt with our agreement to sell a second non-strategic asset for $281 million."
Updated 2016 Guidance Reflects Strong Performance
Based on strong operating results in first half 2016, the Company now expects production for the year will be in a range of 210,000 and 220,000 Boe per day, an increase of 5,000 Boe per day from previous guidance. Continental expects to exit the year with production between 195,000 and 205,000 Boe per day, also reflecting a 5,000 Boe per day increase.
Continental also reduced 2016 guidance for production expense per Boe and cash general and administrative (G&A) expense per Boe. Production expense is now expected to be in a range of $3.75 to $4.25 per Boe for the year, down approximately 11% ($0.50 per Boe) from the previous range. Efficiencies contributing to the lower guidance include reducing produced water expense and increasing artificial lift efficiency in the Bakken and reducing compression, saltwater disposal and chemical costs in Oklahoma.
Total G&A expense, including cash and non-cash G&A expense, is expected to be in a reduced range of $1.85 to $2.45 per Boe for 2016. Of this total, cash G&A expense is expected to be in a range of $1.20 to $1.60 per Boe for 2016, a reduction from the previous range of $1.25 to $1.75 per Boe.
Finally, the Company improved its outlook for oil price differential, reflecting increased crude oil production in Oklahoma, where it has lower transportation costs, and reduced transportation costs from the Bakken. Average crude oil price differential for 2016 is expected to be in a range of $7.00 to $8.00 per barrel of oil (Bo), compared with the previous range of $7.00 to $9.00.
2016 Updated Guidance Metrics |
Updated 2016 Guidance |
Previous 2016 Guidance |
Production guidance (Boe per day) |
210,000 to 220,000 |
205,000 to 215,000 |
Production expense per Boe |
$3.75 to $4.25 |
$4.25 to $4.75 |
Cash G&A expense per Boe |
$1.20 to $1.60 |
$1.25 to $1.75 |
Average price differential for NYMEX WTI crude oil (per Bo) |
($7.00) to ($8.00) |
($7.00) to ($9.00) |
The Company's full 2016 guidance is stated in a table at the conclusion of this release.
"Over the last 18 months, Continental has achieved a step-change improvement in capital efficiency," said Jack Stark, President and Chief Operating Officer. "Barrels of oil found per dollar invested have more than doubled, while production expense per Boe and G&A expense per Boe have decreased by a combined 36% since 2014. We believe the majority of these capital efficiencies are structural and sustainable, further strengthening CLR's performance going forward."
SCOOP Non-Strategic Asset Sale for $281 Million
Continental announced today it has signed a definitive purchase and sale agreement with an undisclosed buyer to sell approximately 29,500 net acres of non-strategic leasehold in the SCOOP play in Oklahoma for $281 million. The agreement provides for customary closing conditions and adjustments. Located primarily on the eastern side of SCOOP, the leasehold represents approximately 550 Boe per day of net production. After this transaction, the Company will retain approximately 384,000 net acres of leasehold in SCOOP.
"Proceeds from this sale and the previous sale of Wyoming assets will total nearly $400 million," said Mr. Stark. In May 2016, the Company announced the sale of approximately 132,000 net acres of leasehold in the Washakie Basin in Wyoming for $110 million.
"We have additional opportunities to sell non-strategic assets for continued debt reduction," he said.
Production Results
Second quarter 2016 net production totaled approximately 20.0 million Boe (MMBoe), or 219,300 Boe per day, down 5% from first quarter 2016 and 3% lower than second quarter 2015. The second quarter 2016 production decline, as expected, was concentrated in the Bakken play, where the Company continues to increase its drilled but uncompleted (DUC) well inventory.
Total net production for second quarter 2016 included approximately 133,000 Bo per day (61% of total production) and approximately 518 million cubic feet (MMcf) of natural gas per day (39% of total production).
The following table provides the Company's average daily production by region for the periods presented.
2Q |
1Q |
2Q |
YTD |
YTD | ||||||
Boe per day |
2016 |
2016 |
2015 |
2016 |
2015 | |||||
North Region: |
||||||||||
North Dakota Bakken |
114,554 |
129,168 |
127,872 |
121,861 |
124,434 | |||||
Montana Bakken |
10,474 |
10,434 |
13,116 |
10,454 |
13,844 | |||||
Red River Units |
11,075 |
11,300 |
12,669 |
11,188 |
12,810 | |||||
Other |
695 |
649 |
1,835 |
672 |
1,261 | |||||
South Region: |
||||||||||
SCOOP |
64,669 |
64,616 |
62,546 |
64,642 |
56,249 | |||||
STACK/NW Cana |
14,610 |
11,127 |
4,410 |
12,868 |
3,924 | |||||
Arkoma |
1,862 |
2,037 |
2,112 |
1,950 |
2,118 | |||||
Other |
1,384 |
1,471 |
1,987 |
1,428 |
2,102 | |||||
Total |
219,323 |
230,802 |
226,547 |
225,063 |
216,742 |
STACK / Northwest Cana Joint Development Agreement (JDA) Area, Oklahoma
STACK/Northwest Cana production increased 31% to 14,610 Boe per day in second quarter 2016, compared to first quarter 2016.
The Company reported five new Meramec completions in Blaine County. Initial 24-hour production test rates and flowing casing pressures (in pounds per square inch, or psi) for these wells were as follows:
All five new wells were drilled with extended laterals, ranging from approximately 7,100 to 9,900 feet.
"Results of the Madeline and Frankie Jo wells are outstanding," said Mr. Stark. "These two wells extend the known productive footprint of the over-pressured Meramec oil window 17 miles west of the Verona well we reported in May. The Madeline actually set a new record for Continental operated wells in STACK, flowing at an initial 24-hour rate of 3,538 Boe per day, with 71% of production being crude oil."
The Yocum is a strong gas producer and Continental's first completion in the over-pressured gas window of STACK. The Yocum was designed to test the productivity of the Meramec on the down-thrown side of a significant north-south trending fault that separates the Yocum from the Company's previously announced Boden 1-15-10XH well, which is located just over a mile to the northwest.
"The separating fault has up to 525 feet of vertical displacement, and the Yocum is clearly in the gas window on the down-thrown side of the fault," said Glen Brown, Senior Vice President of Exploration. "In contrast, the Boden is located in the condensate window on the fault's up-thrown side, and it has steadily produced 27% crude oil since December 2015. The Yocum's results place an additional 2% of Continental's STACK acreage in the gas window."
Continental finished drilling and is now completing its first STACK density pilot in the Ludwig unit, which is located in the over-pressured oil window of STACK. The Ludwig is testing four wells per zone in the Upper and Middle Meramec zones, with one well in the Woodford. Average lateral length for the Ludwig wells is approximately 9,500 feet. Multi-well pad development reduced drilling times for the Ludwig density wells to an average 25 days, down 44%, compared to the Company's average for STACK wells drilled in 2015. Average drilling cost for the Ludwig density wells is estimated at $3.2 million per well, 28% below the Ludwig legacy well drilled in June of 2015.
The Company has commenced drilling its second and third STACK density pilots in the over-pressured oil window at the Bernhardt and Blurton units in Blaine County. The Bernhardt density pilot is testing a five-well per zone pattern in the Lower Meramec, with targeted lateral lengths of 4,950 feet. The Blurton density pilot is testing three to five wells per zone in the Upper and Lower Meramec, with average lateral lengths of 10,300 feet.
Continental is now targeting an average completed well cost of $9.0 million per operated well for extended-lateral wells in the over-pressured oil window of STACK. This is $500,000 per well below the previous year-end 2016 target. At this targeted cost, Continental estimates a well in the over-pressured oil window should deliver more than an 85% rate of return at $45 per barrel WTI and $2.50 per Mcf of gas, based on an EUR of 1.7 MMBoe per well.
Continental increased its STACK leasehold by approximately 12,000 net acres in second quarter 2016 to approximately 183,000 net acres, located primarily in Blaine, Dewey and Custer counties. Since year-end 2015, the Company has added approximately 27,000 net acres of leasehold in STACK. The Company estimates 95% of its STACK leasehold is in the over-pressured window, of which 40% is in the oil window, 40% is in the condensate window and 20% is in the gas window. The Company has 11 operated rigs in STACK, with six targeting the Meramec formation in Blaine County and five targeting the Woodford formation in the Northwest Cana JDA area.
A notable second quarter 2016 well completion in the Northwest Cana JDA area was the Lacretia 1-29-20XH, which had initial 24-hour production of 17.6 MMcf per day (100% natural gas) with approximately a 7,500-foot lateral at 5,500 psi flowing casing pressure. Since inception in early April, the Lacretia has flowed a cumulative 1.7 Bcf of gas, and it is currently flowing approximately 11.8 MMcf per day at 3,250 psi flowing casing pressure.
SCOOP Play, Oklahoma: Woodford Oil Window EUR Increased to 1.3 MMBoe per Well
In second quarter 2016, total SCOOP net production averaged 64,669 Boe per day, slightly above first quarter 2016 and 3% higher than second quarter 2015. SCOOP production represented 29% of the Company's total production in second quarter 2016.
SCOOP Woodford net production averaged 56,511 Boe per day in second quarter 2016, compared with SCOOP Springer net production of 8,158 Boe per day.
The Company announced it has increased the EUR for 2-mile wells drilled in the SCOOP Woodford oil window by approximately 30% to 1.3 MMBoe per well, with 62% of production being crude oil. The increase in EUR was based on the results of 22 enhanced completions conducted over the past two years in the SCOOP Woodford oil window and assumes an average 9,800-foot lateral per well. Results show that 180-day production rates are on average 25%-to-30% higher than offsetting legacy wells. At a targeted completed well cost of $9.8 million per well, a 1.3 MMBoe EUR SCOOP Woodford oil well should yield a 32% rate of return at $45 per barrel WTI and $2.50 per Mcf of gas.
The most recent enhanced completion well in the SCOOP Woodford oil window was the RK Morris 1-29-17XH in eastern Grady County, which had an initial 24-hour production test rate of 1,003 Bo and 1.8 MMcf (1,297 Boe) from an 11,500-foot lateral, with flowing casing pressure of 690 psi. Along with solid initial production, the well is exhibiting a low decline rate, with an average 30-day production of 903 Bo and 1.6 MMcf per day at 560 psi.
Gary Gould, Senior Vice President of Production and Resource Development, said, "Enhanced completions once again are having a profound impact on production rates and EURs, this time in the oil window of SCOOP Woodford, just as we've experienced in the SCOOP condensate window. We estimate that at least 50,000 net acres in our Woodford oil window leasehold can be upgraded to the new 1.3 MMBoe EUR type curve, so the new approach obviously increases the value of this asset in a significant way." He added that enhanced completion designs will be applied in all future oil window wells in SCOOP Woodford, starting with the completion of the new wells in the May density pilot in Grady County.
Continental completed 6 net (24 gross) operated and non-operated wells in SCOOP in second quarter 2016, while operating an average of four rigs in the play. This includes 5.4 net (23 gross) wells targeting the Woodford formation and 0.3 net (1 gross) wells targeting the Springer formation.
Bakken Play, North Dakota
Continental's Bakken production averaged 125,028 Boe per day in second quarter 2016, a decrease of 10% from first quarter 2016. Continental completed 3 net (25 gross) operated and non-operated wells in Bakken in second quarter 2016, while operating an average of four drilling rigs in the play.
The Company recently elected to complete eight additional operated Bakken wells in the second half of 2016 to further test enhanced completion concepts including stage spacing, proppant volumes per stage, proppant size and diverter technology. Two stimulation crews were recently deployed in the field to execute these plans, and the Company anticipates first production for new wells in this program during third and fourth quarters 2016. This testing program is designed to provide additional data to help Continental optimize future development of its DUC inventory.
Continental's current Bakken DUC inventory has grown to approximately 165 gross operated DUCs, with expectations to end 2016 with approximately 190 gross operated DUCs. This represents a high-graded inventory with an average EUR of approximately 850,000 Boe per DUC well. The Company estimates a current average cost of between $3.0 million to $3.5 million per well to complete these wells. At $45 per barrel WTI and $2.50 per Mcf of gas, the cost-forward rate of return on this incremental capital expenditure is over 100%. "Our DUCs represent an exceptional value that we can capitalize on as markets recover," Mr. Gould said.
The Company's total completed well cost for a 2-mile lateral Bakken well is approximately $6.2 million, down from $6.8 million at year-end 2015. Continental expects to achieve an operated completed well cost of $6.0 million by year-end 2016.
Financial Update
"Continental's second quarter results clearly reflect continued discipline in terms of operating costs and capital expenditures," said John Hart, Chief Financial Officer. "We are currently cash flow positive and expect to remain so in the second half of the year, especially under our assumption that commodity prices will strengthen. Our credit metrics are improving and are expected to further improve as we apply asset divestiture proceeds to further reduce debt."
In second quarter 2016, Continental's average realized sales price, excluding the effects of derivative positions, was $38.38 per Bo and $1.31 per Mcf of gas, or $26.36 per Boe. Based on realizations without the effect of derivatives, the Company's second quarter 2016 oil differential was $7.21 per barrel below the NYMEX daily average for the period. The second quarter 2016 realized wellhead natural gas price, without the effect of derivatives, was on average $0.65 per Mcf below the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.72 for second quarter 2016, a decrease of $0.67 per Boe from second quarter 2015. Other select operating costs and expenses for second quarter 2016 included production taxes of 7.4% of oil and natural gas sales; DD&A of $22.15 per Boe; and G&A (cash and non-cash) of $1.82 per Boe.
As of June 30, 2016, Continental's balance sheet included $16.6 million in cash and cash equivalents and $885 million of borrowings against the Company's revolving credit facility, compared to the balance of $940 million at March 31, 2016. As of July 31, 2016, borrowings against the revolving credit facility had declined to $820 million. Continental had approximately $1.86 billion in available borrowing capacity under its revolving credit facility as of June 30, 2016, and approximately $1.93 billion was available as of July 31, 2016.
Capital expenditures for second quarter 2016 were $219.3 million, including $9.9 million for acquisitions. Non-acquisition capital expenditures for second quarter 2016 included $179.6 million in exploration and development drilling, $18.8 million in leasehold and seismic, and $11.0 million in workovers, recompletions and other. Year-to-date non-acquisition capital expenditures were consistent with the Company's spending plan under its budget of $920 million for 2016.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations, and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended June 30, |
Six months ended June 30, | ||||||
2016 |
2015 |
2016 |
2015 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
133,044 |
149,897 |
139,756 |
146,722 | |||
Natural gas (Mcf per day) |
517,677 |
459,898 |
511,837 |
420,123 | |||
Crude oil equivalents (Boe per day) |
219,323 |
226,547 |
225,063 |
216,742 | |||
Average sales prices, excluding effect from derivatives: |
|||||||
Crude oil ($/Bbl) |
$38.38 |
$49.84 |
$31.76 |
$44.46 | |||
Natural gas ($/Mcf) |
$1.31 |
$2.31 |
$1.33 |
$2.48 | |||
Crude oil equivalents ($/Boe) |
$26.36 |
$37.82 |
$22.73 |
$34.93 | |||
Production expenses ($/Boe) |
$3.72 |
$4.39 |
$3.74 |
$4.70 | |||
Production taxes (% of oil and gas revenues) |
7.4% |
7.8% |
7.5% |
8.0% | |||
DD&A ($/Boe) |
$22.15 |
$21.68 |
$22.16 |
$21.36 | |||
Total general and administrative expenses ($/Boe) (1) |
$1.82 |
$2.11 |
$1.68 |
$2.28 | |||
Net income (loss) (in thousands) |
($119,402) |
$403 |
($317,727) |
($131,568) | |||
Diluted net income (loss) per share |
($0.32) |
$0.00 |
($0.86) |
($0.36) | |||
Adjusted net income (loss) (non-GAAP) (in thousands) (2) |
($65,910) |
$48,450 |
($216,378) |
$14,631 | |||
Adjusted diluted net income (loss) per share (non-GAAP) (2) |
($0.18) |
$0.13 |
($0.58) |
$0.04 | |||
Net cash provided by operating activities |
$218,819 |
$394,622 |
$497,721 |
$916,812 | |||
EBITDAX (non-GAAP) (in thousands) (2) |
$528,109 |
$647,009 |
$842,718 |
$1,086,435 |
(1) |
Total general and administrative expense is comprised of cash general and administrative expense and non-cash equity compensation expense. Cash general and administrative expense per Boe was $1.22, $1.34, $1.16, and $1.58 for 2Q 2016, 2Q 2015, YTD 2016, and YTD 2015, respectively. Non-cash equity compensation expense per Boe was $0.60, $0.77, $0.52, and $0.70 for 2Q 2016, 2Q 2015, YTD 2016, and YTD 2015, respectively.
|
(2) |
Adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or net cash provided by operating activities as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Second Quarter 2016 Earnings Conference Call
Continental plans to host a conference call to discuss second quarter results on Thursday, August 4, 2016, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, August 4, 2016 |
Dial in: |
844-309-6572 |
Intl. dial in: |
484-747-6921 |
Pass code: |
28733877 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
28733877 |
Continental plans to publish a second quarter 2016 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on August 4, 2016.
Upcoming Conferences
Members of Continental's management team will be participating in the following upcoming investment conferences:
August 24, 2016 – Heikkinen Energy Conference, Houston
September 6-7, 2016 – Barclays CEO Energy-Power Conference, New York
Presentation materials for all conferences listed above will be available on the Company's website at www.CLR.com on or prior to the day of the presentations.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||||||
Three months ended June 30, |
Six months ended June 30, | ||||||
2016 |
2015 |
2016 |
2015 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 525,711 |
$ 790,102 |
$ 929,302 |
$ 1,372,694 | |||
Gain (loss) on crude oil and natural gas derivatives, net |
(82,257) |
(4,737) |
(40,145) |
28,018 | |||
Crude oil and natural gas service operations |
7,757 |
11,009 |
15,227 |
21,306 | |||
Total revenues |
451,211 |
796,374 |
904,384 |
1,422,018 | |||
Operating costs and expenses: |
|||||||
Production expenses |
74,083 |
91,735 |
152,724 |
184,675 | |||
Production taxes and other expenses |
39,141 |
61,545 |
69,634 |
109,908 | |||
Exploration expenses |
1,674 |
109 |
4,739 |
14,449 | |||
Crude oil and natural gas service operations |
3,576 |
7,092 |
6,618 |
10,986 | |||
Depreciation, depletion, amortization and accretion |
441,761 |
452,957 |
905,752 |
839,469 | |||
Property impairments |
66,112 |
76,872 |
145,039 |
224,432 | |||
General and administrative expenses |
36,246 |
44,190 |
68,654 |
89,571 | |||
Net gain on sale of assets and other |
(100,835) |
(20,573) |
(99,127) |
(22,643) | |||
Total operating costs and expenses |
561,758 |
713,927 |
1,254,033 |
1,450,847 | |||
Income (loss) from operations |
(110,547) |
82,447 |
(349,649) |
(28,829) | |||
Other income (expense): |
|||||||
Interest expense |
(81,922) |
(78,442) |
(162,875) |
(153,505) | |||
Other |
435 |
540 |
819 |
886 | |||
(81,487) |
(77,902) |
(162,056) |
(152,619) | ||||
Income (loss) before income taxes |
(192,034) |
4,545 |
(511,705) |
(181,448) | |||
Provision (benefit) for income taxes |
(72,632) |
4,142 |
(193,978) |
(49,880) | |||
Net income (loss) |
$ (119,402) |
$ 403 |
$ (317,727) |
$ (131,568) | |||
Basic net income (loss) per share |
$ (0.32) |
$ - |
$ (0.86) |
$ (0.36) | |||
Diluted net income (loss) per share |
$ (0.32) |
$ - |
$ (0.86) |
$ (0.36) |
Continental Resources, Inc. and Subsidiaries | |||||
June 30, 2016 |
December 31, 2015 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
797,212 |
$ |
822,339 | |
Net property and equipment (1) |
13,541,129 |
14,063,328 | |||
Other noncurrent assets |
21,395 |
34,141 | |||
Total assets |
$ |
14,359,736 |
$ |
14,919,808 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
818,059 |
$ |
923,028 | |
Long-term debt, net of current portion |
7,149,279 |
7,115,644 | |||
Other noncurrent liabilities |
2,025,449 |
2,212,236 | |||
Total shareholders' equity |
4,366,949 |
4,668,900 | |||
Total liabilities and shareholders' equity |
$ |
14,359,736 |
$ |
14,919,808 |
(1) |
Balance is net of accumulated depreciation, depletion and amortization of $7.36 billion and $6.45 billion as of June 30, 2016 and December 31, 2015, respectively. |
Continental Resources, Inc. and Subsidiaries Unaudited Condensed Consolidated Statements of Cash Flows | ||||||||||||
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net income (loss) |
$ |
(119,402) |
$ |
403 |
$ |
(317,727) |
$ |
(131,568) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
470,257 |
544,438 |
903,030 |
1,039,534 | ||||||||
Changes in assets and liabilities |
(132,036) |
(150,219) |
(87,582) |
8,846 | ||||||||
Net cash provided by operating activities |
218,819 |
394,622 |
497,721 |
916,812 | ||||||||
Net cash used in investing activities |
(158,983) |
(684,899) |
(517,794) |
(1,963,303) | ||||||||
Net cash provided by financing activities |
(56,181) |
267,283 |
25,161 |
1,051,666 | ||||||||
Effect of exchange rate changes on cash |
(22) |
807 |
9 |
(4,098) | ||||||||
Net change in cash and cash equivalents |
3,633 |
(22,187) |
5,097 |
1,077 | ||||||||
Cash and cash equivalents at beginning of period |
12,927 |
47,645 |
11,463 |
24,381 | ||||||||
Cash and cash equivalents at end of period |
$ |
16,560 |
$ |
25,458 |
$ |
16,560 |
$ |
25,458 |
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net income (loss) |
$ |
(119,402) |
$ |
403 |
$ |
(317,727) |
$ |
(131,568) | ||||
Interest expense |
81,922 |
78,442 |
162,875 |
153,505 | ||||||||
Provision (benefit) for income taxes |
(72,632) |
4,142 |
(193,978) |
(49,880) | ||||||||
Depreciation, depletion, amortization and accretion |
441,761 |
452,957 |
905,752 |
839,469 | ||||||||
Property impairments |
66,112 |
76,872 |
145,039 |
224,432 | ||||||||
Exploration expenses |
1,674 |
109 |
4,739 |
14,449 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total (gain) loss on derivatives, net |
78,057 |
4,737 |
37,005 |
(28,018) | ||||||||
Total cash received on derivatives, net |
38,778 |
13,182 |
77,967 |
36,617 | ||||||||
Non-cash loss on derivatives, net |
116,835 |
17,919 |
114,972 |
8,599 | ||||||||
Non-cash equity compensation |
11,839 |
16,165 |
21,046 |
27,429 | ||||||||
EBITDAX (non-GAAP) |
$ |
528,109 |
$ |
647,009 |
$ |
842,718 |
$ |
1,086,435 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended June 30, |
Six months ended June 30, | |||||||||||
In thousands |
2016 |
2015 |
2016 |
2015 | ||||||||
Net cash provided by operating activities |
$ |
218,819 |
$ |
394,622 |
$ |
497,721 |
$ |
916,812 | ||||
Current income tax provision |
6 |
5 |
12 |
10 | ||||||||
Interest expense |
81,922 |
78,442 |
162,875 |
153,505 | ||||||||
Exploration expenses, excluding dry hole costs |
1,468 |
109 |
4,533 |
6,446 | ||||||||
Gain on sale of assets, net |
96,907 |
20,573 |
97,016 |
22,643 | ||||||||
Other, net |
(3,049) |
3,039 |
(7,021) |
(4,135) | ||||||||
Changes in assets and liabilities |
132,036 |
150,219 |
87,582 |
(8,846) | ||||||||
EBITDAX (non-GAAP) |
$ |
528,109 |
$ |
647,009 |
$ |
842,718 |
$ |
1,086,435 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments and gains and losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three months ended June 30, | |||||||||||||||
2016 |
2015 | ||||||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | |||||||||||
Net income (loss) (GAAP) |
$(119,402) |
$ (0.32) |
$ 403 |
$ 0.00 | |||||||||||
Adjustments: |
|||||||||||||||
Non-cash loss on derivatives |
116,835 |
17,919 |
|||||||||||||
Property impairments |
66,112 |
76,872 |
|||||||||||||
Gain on sale of assets |
(96,907) |
(20,573) |
|||||||||||||
Total tax effect of adjustments |
(32,548) |
(26,171) |
|||||||||||||
Total adjustments, net of tax |
53,492 |
0.14 |
48,047 |
0.13 | |||||||||||
Adjusted net income (loss) (non-GAAP) |
$ (65,910) |
$ (0.18) |
$ 48,450 |
$ 0.13 | |||||||||||
Weighted average diluted shares outstanding |
370,435 |
370,873 |
|||||||||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ (0.18) |
$ 0.13 |
|||||||||||||
Six months ended June 30, | |||||||||||||||
2016 |
2015 | ||||||||||||||
In thousands, except per share data |
$ |
Diluted EPS |
$ |
Diluted EPS | |||||||||||
Net income (loss) (GAAP) |
$(317,727) |
$ (0.86) |
$(131,568) |
$ (0.36) | |||||||||||
Adjustments: |
|||||||||||||||
Non-cash loss on derivatives |
114,972 |
8,599 |
|||||||||||||
Property impairments |
145,039 |
224,432 |
|||||||||||||
Gain on sale of assets |
(97,016) |
(22,643) |
|||||||||||||
Total tax effect of adjustments |
(61,646) |
(64,189) |
|||||||||||||
Total adjustments, net of tax |
101,349 |
0.28 |
146,199 |
0.40 | |||||||||||
Adjusted net income (loss) (non-GAAP) |
$(216,378) |
$ (0.58) |
$ 14,631 |
$ 0.04 | |||||||||||
Weighted average diluted shares outstanding |
370,248 |
369,448 |
|||||||||||||
Adjusted diluted net income (loss) per share (non-GAAP) |
$ (0.58) |
$ 0.04 |
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
Continental Resources, Inc. | |
2016 Guidance | |
As of August 3, 2016 (1) | |
2016 | |
Full year average production |
210,000 - 220,000 Boe per day |
Capital expenditures (non-acquisition) |
$920 million |
Operating Expenses: |
|
Production expense per Boe |
$3.75 - $4.25 |
Production tax (% of oil & gas revenue) |
6.75% - 7.25% |
Cash G&A expense per Boe(2) |
$1.20 - $1.60 |
Non-cash equity compensation per Boe |
$0.65 - $0.85 |
DD&A per Boe |
$20.00 - $22.00 |
Average Price Differentials: |
|
NYMEX WTI crude oil (per barrel of oil) |
($7.00) - ($8.00) |
Henry Hub natural gas (per Mcf) |
$0.00 - ($0.65) |
Income tax rate |
38% |
Deferred taxes |
90% - 95% |
(1) |
Bolded items denote a positive guidance revision from the previous disclosure provided on May 4, 2016. | |
(2) |
Cash G&A is a non-GAAP measure and excludes the range of values shown for non-cash equity compensation per Boe in the item appearing immediately below. |
SOURCE Continental Resources
OKLAHOMA CITY, June 30, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce second quarter 2016 results on Wednesday, August 3, 2016 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss second quarter 2016 results on Thursday, August 4, 2016 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
Time and date: |
12 p.m. ET, Thursday, August 4, 2016 |
Dial-in: |
844-309-6572 |
Intl. dial-in: |
484-747-6921 |
Conference ID: |
28733877 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
28733877 |
Continental plans to publish a second quarter 2016 summary presentation to its website at www.CLR.com prior to the start of its conference call on August 4, 2016.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, June 27, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") is scheduled to present Wednesday, June 29 at the J.P. Morgan Inaugural Energy Equity Conference in New York City. The event will not be webcast, but updated presentation materials will be available on the Company's website at www.CLR.com prior to the presentation.
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About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, May 17, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("the Company") today announced the completion of an industry record well in the over-pressured oil window of Oklahoma's STACK play. The Verona 1-23-14XH flowed at an initial 24-hour test rate of 3,339 barrels of oil equivalent per day, comprised of 2,345 barrels of oil, or 70% of production, and 6.0 million cubic feet of 1,370-Btu natural gas (British thermal units). The Verona is producing from the Meramec reservoir through a 9,700-foot lateral at a flowing casing pressure of approximately 2,400 psi, on a 34/64-inch choke.
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"The Verona is another example of the exceptional results we are getting from wells drilled in the over-pressured oil window of STACK," said Harold Hamm, Chairman and Chief Executive Officer. "We couldn't be more pleased with the performance of our wells in STACK and the addition of this outstanding asset to our portfolio. Our STACK team also completed the Verona at a cost of approximately $9.0 million, which is $500,000 less than our year-end 2016 target cost for two-mile lateral wells in the over-pressured oil window. This is the Company's lowest cost completion in STACK to date."
The Verona is the Company's ninth well completed in the over-pressured oil window of STACK, and all have been strong producers. The Company is in the process of completing four additional Meramec wells. Continental currently has 11 operated rigs drilling in STACK, with six targeting the Meramec zone and five targeting the Woodford zone.
Located in Blaine County, Oklahoma, the Verona is immediately east of the Company's Ludwig unit, where Continental is currently drilling an eight-well density pilot, its first in the STACK play. The density pilot consists of seven new wells in the Upper and Middle Meramec reservoirs, as well as an additional well in the Woodford reservoir underlying the Meramec. Results from the Ludwig density pilot are expected to be announced by the Company's third quarter 2016 earnings release.
As announced earlier in the month, at March 31, 2016 Continental had approximately 171,000 net acres of leasehold in the STACK play, 95% of which is in the over-pressured window.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Senior Analyst, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, May 4, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today reported a net loss of $198.3 million, or $0.54 per diluted share, for the quarter ended March 31, 2016. Adjusted net loss for first quarter 2016 was $150.5 million, or $0.41 per diluted share.
EBITDAX for first quarter 2016 was $314.6 million. Definitions and reconciliations of adjusted net loss, adjusted earnings per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures can be found in the supporting tables at the conclusion of this press release.
"We started 2016 with record quarterly production, lower operating costs and excellent results in STACK," commented Harold Hamm, Continental's Chairman and Chief Executive Officer. "The resilience of our production has allowed us to increase our production guidance for 2016 without increasing capex. This reflects the quality of our assets and the success of our enhanced completion technology. Our new production guidance includes curtailing production approximately 10,000 Boe per day from early April through July. The majority of the reduced production is in STACK and SCOOP. We are managing production volumes for higher oil and natural gas prices that we expect in second half 2016."
Production Exceeds Expectations
First quarter 2016 net production totaled 21.0 million barrels of oil equivalent (Boe), or 230,800 Boe per day, up 3% from fourth quarter 2015 and 12% higher than first quarter 2015. Total net production for first quarter 2016 included 146,500 barrels of oil (Bo) per day (63% of production) and 506.0 million cubic feet (MMcf) of natural gas per day (37% of production).
Based on strong first quarter production, the Company today increased its production guidance for 2016. The Company expects to exit the year between 190,000 and 200,000 Boe per day, which is an increase of 10,000 Boe per day. Likewise, 2016 average production is now expected to be between 205,000 and 215,000 Boe per day.
The following table provides the Company's average daily production by region for the periods presented.
1Q |
4Q |
1Q | ||||
Boe per day |
2016 |
2015 |
2015 | |||
North Region: |
||||||
North Dakota Bakken |
129,168 |
125,583 |
120,957 | |||
Montana Bakken |
10,434 |
10,772 |
14,581 | |||
Red River Units |
11,300 |
11,654 |
12,953 | |||
Other |
649 |
902 |
681 | |||
South Region: |
||||||
SCOOP |
64,616 |
64,534 |
49,882 | |||
STACK/NW Cana |
11,127 |
7,709 |
3,433 | |||
Arkoma |
2,037 |
2,124 |
2,124 | |||
Other |
1,471 |
1,658 |
2,218 | |||
Total |
230,802 |
224,936 |
206,829 |
Over-Pressured STACK / NW Cana JDA
"A key factor driving our strong first quarter results is the exceptional performance of our over-pressured Meramec wells in STACK," said Jack Stark, President and Chief Operating Officer. "These wells are delivering some of the highest rates of return in the country. STACK has quickly become another premier growth platform for Continental Resources and our shareholders, potentially adding as much as 25% to the Company's net unrisked resource potential at current prices."
STACK/Northwest Cana production increased 44% to 11,127 Boe per day in first quarter 2016, compared to fourth quarter 2015. Continental has 11 operated rigs in STACK, after transferring one operated rig from SCOOP. Six of these rigs are targeting the Meramec formation, and five are targeting the Woodford formation in the Northwest Cana joint development area of STACK.
The Company reported three new Meramec completions in the over-pressured oil window of STACK. Initial 24-hour production test rates for these wells were as follows:
The Company also has five additional Meramec wells in STACK in various stages of completion, including the Gillilan 1-35-26XH, Verona 1-23-14XH, Madelin 1-9-4XH and Frankie Jo 1-25-24XH, which are located in the over-pressured oil window; and the Yocum 1-35-26XH well located in the over-pressured condensate window.
The Company's previously announced Meramec completions in STACK continue to produce at strong rates and pressures. Continental's first well in the over-pressured oil window, the Ludwig 1-22-15XH, which was announced in August 2015, has produced approximately 250,000 Boe (75% oil) in its first 270 days and continues to flow at restricted rates of 681 Boe per day (72% oil), with a tubing casing pressure of 1,600 psi on a 20/64" choke.
Continental's first over-pressured condensate well, the Boden 1-15-10XH, has produced approximately 240,000 Boe (28% oil) in its first 150 days and continues to flow at restricted rates of 1,267 Boe per day (26% oil), with a flowing tubing pressure of 4,700 psi on a 23/64" choke.
Completed well costs for Meramec wells in the over-pressured oil window of STACK have been reduced another 5%, to a targeted $9.5 million per operated well, based on efficiencies the Company has realized to date. Spud-to-TD drill times in first quarter 2016 averaged 30 days, down from an average of 44 days in 2015. At the current targeted cost of $9.5 million, the Company's economic model for a 9,800-foot lateral Meramec well in the over-pressured oil window delivers a 75% rate of return at $45 per barrel WTI and $2.25 per Mcf of gas, assuming an estimated ultimate recovery (EUR) of 1.7 MMBoe per well. The Company is targeting further cost reductions and efficiencies throughout the year.
Continental recently commenced drilling its first STACK density pilot at the Ludwig unit in Blaine County. The Ludwig density pilot is the first of three density pilots the Company plans to drill in 2016 to determine optimum well spacing for future field development. This will be an eight-well density test in the over-pressured oil window of STACK, including the original Ludwig 1-22-15XH and seven new Meramec wells, with four new wells in the Upper and three in the Middle Meramec, where the legacy Ludwig well is located. Wells will be spaced 1,320 feet apart in each horizon, and offset between horizons by 660 feet. Finally, an additional new well is planned for the Woodford formation in the Ludwig unit to facilitate micro-seismic monitoring and further develop the Woodford. Continental currently has four rigs drilling in the Ludwig density pilot and expects to announce results in fourth quarter 2016.
Continental added approximately 15,000 net acres to its over-pressured STACK leasehold in first quarter 2016, increasing its leasehold position to approximately 171,000 net acres primarily in Blaine, Dewey and Custer counties. Over 95% of the leasehold is located in the over-pressured STACK and approximately 70% of this leasehold is expected to be held by production at year-end 2016.
SCOOP Production
In first quarter 2016, total SCOOP net production averaged 64,616 Boe per day, slightly above fourth quarter 2015 and a 30% increase compared with first quarter 2015. SCOOP production represented 28% of the Company's total production in first quarter 2016, compared with 24% of Company production for first quarter 2015.
SCOOP Woodford net production averaged 55,474 Boe per day in first quarter 2016, or 86% of total SCOOP production. SCOOP Springer net production averaged 9,142 Boe per day, or 14% of total SCOOP production. The Springer formation is located approximately 1,000-to-1,500 feet above the Woodford.
Continental completed 6 net (20 gross) operated and non-operated wells in SCOOP in first quarter 2016, while operating an average of five rigs in the play. This includes 6 net (18 gross) wells targeting the Woodford formation and 0.2 net (2 gross) wells targeting the Springer.
SCOOP Woodford Enhanced Completions
As announced last quarter, the Company increased its EUR type curve for enhanced completed wells in the SCOOP condensate window by 15% to 2.0 MMBoe for a 7,500-foot lateral. The Company's SCOOP Woodford condensate enhanced completions have on average produced 35% higher 90-day rates and 40% higher 180-day rates, compared with offset wells completed with smaller volumes of sand. These results are approximately 5% higher than the earlier results reported last quarter.
"I am proud of our teams as they continue to increase production and improve well economics through our ongoing process for optimizing completion designs," said Gary Gould, Senior Vice President, Production and Resource Development. "We continue to apply enhanced completion designs on all new operated wells, by testing, for example, various proppant volumes, stage lengths and proppant sizes in order to determine the optimum completion design for each area in each play."
Two notable enhanced-completion step-out tests in the first quarter included:
The Gretta is a significant step-out test, located approximately 37 miles south of the Newy unit in SCOOP Woodford, mentioned below. It and the Sandy have been producing less than 90 days, but the early production shows these wells are producing at rates above legacy offset wells.
Average completed well cost for operated Woodford wells is currently $10 million, which includes the incremental cost of enhanced completions. Continental expects to achieve a targeted well cost of $9.6 million for a 7,500-foot lateral well by year-end 2016. At the targeted cost and projected 2.0 MMBoe EUR, these Woodford wells would typically generate a 30% rate of return based on $45 per barrel WTI and $2.25 per Mcf of gas.
Newy: Fourth SCOOP Woodford Density Pilot Completed
Continental recently completed its fourth Woodford dual-level density pilot in the Newy unit. This was an eight-well density test, including seven new wells and the original Newy 1-24H well. To date the seven new wells have flowed at a combined peak 24-hour rate of 87 MMcf and 3,928 Bo per day (18,475 Boe per day). On a per-well basis, average peak production was 2,639 Boe per day (21% oil), which is in line with average peak per-well rates for the Company's three prior density pilots. The Company expects flow rates from the seven recent Newy wells will continue to increase to a higher final combined 24-hour peak rate as the wells continue to flow and clean up.
The Newy project was a dual-level density pilot in the SCOOP Woodford condensate window, consisting of four wells in the Lower Woodford and four in the Upper Woodford. Wells are spaced 1,320 feet apart in each horizon, and offset between horizons by 660 feet with approximately 100 feet of vertical separation. Average lateral length for the seven new wells was 9,850 feet.
Bakken
Continental's Bakken production averaged 139,602 Boe per day in first quarter 2016, a slight increase over fourth quarter 2015. The Company had no stimulation crews in the Bakken during first quarter 2016, but brought online 10 net (12 gross) wells that had been drilled and completed in 2015, but not actively produced until first quarter 2016. Continental also participated in 5 net (42 gross) non-operated Bakken wells during the quarter.
Enhanced slickwater and hybrid completions continue to improve Bakken well performance. Continental now has 118 30-stage, 2-mile enhanced-completion wells in Williams and McKenzie counties with at least 180 days of production history. These wells are showing 45%-to-60% higher 180-day production rates and 35%-to-45% higher EURs when compared to direct offsets with historical standard designs. These initial production uplifts and higher EURs are superior to previously announced gains. The current completed well cost for a Bakken well is approximately $6.3 million, down $0.5 million from year-end 2015. Continental is targeting an operated completed well cost of $6.0 million by year end.
Continental also continues to reduce lease operating expense in the Bakken in first quarter 2016. On a monthly basis, operated Bakken net lease operating expense was reduced by $3.1 million per month, down 25% from first quarter 2015, while increasing the net operated well count by 10% in the Bakken during this time period.
Continental expects to end 2016 with approximately 195 gross operated drilled and uncompleted wells (DUCs) in the Bakken. The year-end 2016 DUC inventory represents a high-graded inventory with an average EUR per well of approximately 850,000 Boe. The Company's current estimate of average capital cost to complete the DUC backlog is approximately $3.5 million per well. At $45 WTI, the cost-forward rate of return on this current incremental capital would be more than 100%.
The Company has four operated drilling rigs in the North Dakota Bakken and plans to maintain this level through year end. Continental in April temporarily deployed a completion crew to complete the Maryland 2-16H and the Nashville 2-21H wells, which are beginning flow-back operations this week. The Company plans to have four additional operated Bakken completions this year, and currently has no stimulation crews deployed in the Bakken.
Wyoming Asset Sale
Continental also announced today it closed the sale in late April of approximately 132,000 net acres of leasehold in the Washakie Basin in Wyoming for $110 million. The leasehold was non-core, non-producing, undeveloped acreage in Sweetwater and Carbon counties and included no proved reserves. After this transaction, the Company retained non-operated production and approximately 40,000 net acres in the basin. The Company used the proceeds from the sale to reduce outstanding debt and noted that it has other opportunities for non-core asset sales.
Financial Update
In first quarter 2016, Continental's average realized sales price, excluding the effects of derivative positions, was $25.72 per barrel of oil and $1.36 per Mcf of gas, or $19.27 per Boe. Based on realizations without the effect of derivatives, the Company's first quarter 2016 oil differential was $7.78 per barrel below the NYMEX daily average for the period. The first quarter 2016 realized wellhead natural gas price, without the effect of derivatives, was on average $0.73 per Mcf below the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.76 for first quarter 2016, a decrease of $0.10 per Boe from fourth quarter 2015 and a decrease of $1.29 per Boe from first quarter 2015. Other select operating costs and expenses for first quarter 2016 included production taxes of 7.6% of oil and natural gas sales; DD&A of $22.16 per Boe; and G&A (cash and non-cash) of $1.55 per Boe.
As of March 31, 2016, Continental's balance sheet included $12.9 million in cash and cash equivalents and $940 million of borrowings against the Company's revolving credit facility, compared to the balance of $853 million at December 31, 2015. Continental had approximately $1.8 billion in available borrowing capacity under its revolving credit facility as of March 31, 2016, and approximately $1.9 billion was available as of April 29, 2016, after the Company used proceeds from its Wyoming leasehold sale to pay down outstanding debt. As noted in previous earnings releases, the Company expects its revolver balance to fluctuate somewhat through the year due to the timing of bond interest payments. On an annual basis at current commodity prices and current guidance, the Company expects to be cash flow positive for 2016 as a whole.
The Company's revolver is unsecured, and there are no terms in the facility that would mandate collateral or a borrowing base calculation coming back into place. The revolver's sole financial covenant is a net debt to total capitalization ratio of no greater than 0.65, and, as of March 31, 2016, the Company's net debt to total capitalization ratio was 0.59, compared with 0.58 at December 31, 2015. Under the terms of the credit agreement, the calculation of total capitalization specifically excludes any non-cash impairment charges incurred after June 30, 2014.
Non-acquisition capital expenditures for first quarter 2016 totaled $319.9 million, including $290.0 million in exploration and development drilling, $20.0 million in leasehold and seismic, and $9.9 million in workovers, recompletions and other. Approximately $30 million of the $319.9 million capital spend was attributable to Continental gaining working interest in key wells due to other participants non-consenting. Acquisition capital expenditures totaled $4.4 million for first quarter 2016. The first quarter's non-acquisition capital expenditures were consistent with the Company's spending plan under its budget of $920 million for 2016, with the quarterly rate of capital expenditures decreasing throughout the year.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
1Q |
4Q |
1Q | |||
2016 |
2015 |
2015 | |||
Average daily production: |
|||||
Crude oil (Bbl per day) |
146,469 |
145,576 |
143,511 | ||
Natural gas (Mcf per day) |
505,998 |
476,160 |
379,906 | ||
Crude oil equivalents (Boe per day) |
230,802 |
224,936 |
206,829 | ||
Average sales prices, excluding effect from derivatives: |
|||||
Crude oil ($/Bbl) |
$25.72 |
$34.23 |
$38.56 | ||
Natural gas ($/Mcf) |
$1.36 |
$2.07 |
$2.70 | ||
Crude oil equivalents ($/Boe) |
$19.27 |
$26.57 |
$31.65 | ||
Production expenses ($/Boe) |
$3.76 |
$3.86 |
$5.05 | ||
Production taxes (% of oil and gas revenues) |
7.6% |
7.8% |
8.2% | ||
DD&A ($/Boe) |
$22.16 |
$22.20 |
$21.00 | ||
General and administrative expenses ($/Boe) |
$1.11 |
$1.68 |
$1.85 | ||
Non-cash equity compensation ($/Boe) |
$0.44 |
$0.56 |
$0.61 | ||
Net loss (in thousands) |
($198,326) |
($139,677) |
($131,971) | ||
Diluted net loss per share |
($0.54) |
($0.38) |
($0.36) | ||
Adjusted net loss (in thousands) (1) |
($150,467) |
($86,644) |
($33,819) | ||
Adjusted diluted net loss per share (1) |
($0.41) |
($0.23) |
($0.09) | ||
EBITDAX (in thousands) (1) |
$314,609 |
$420,239 |
$439,427 |
(1) |
Adjusted net loss, adjusted diluted net loss per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or operating cash flows as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net loss, adjusted diluted net loss per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
First Quarter 2016 Earnings Conference Call
Continental plans to host a conference call to discuss first quarter results on Thursday, May 5, 2016, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, May 5, 2016 |
Dial in: |
855-291-6799 |
Intl. dial in: |
315-625-3058 |
Pass code: |
67924070 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Pass code: |
67924070 |
Continental plans to publish a first quarter 2016 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on May 5, 2016.
Upcoming Conferences
Members of Continental's management team will be participating in the following upcoming investment conferences:
May 25, 2016 – UBS Oil and Gas Conference, Austin
June 27, 2016 – Inaugural J.P. Morgan Energy Equity Investor Conference, New York
Presentation materials for all conferences listed above will be available on the Company's website at www.CLR.com on or prior to the day of the presentations.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries | |||
Unaudited Condensed Consolidated Statements of Loss | |||
Three months ended March 31, | |||
2016 |
2015 | ||
Revenues: |
In thousands, except per share data | ||
Crude oil and natural gas sales |
$ 403,592 |
$ 582,592 | |
Gain on crude oil and natural gas derivatives, net |
42,112 |
32,755 | |
Crude oil and natural gas service operations |
7,470 |
10,297 | |
Total revenues |
453,174 |
625,644 | |
Operating costs and expenses: |
|||
Production expenses |
78,640 |
92,941 | |
Production taxes and other expenses |
30,493 |
48,362 | |
Exploration expenses |
3,066 |
14,340 | |
Crude oil and natural gas service operations |
3,043 |
3,894 | |
Depreciation, depletion, amortization and accretion |
463,992 |
386,512 | |
Property impairments |
78,927 |
147,561 | |
General and administrative expenses |
32,407 |
45,380 | |
Other |
1,709 |
(2,070) | |
Total operating costs and expenses |
692,277 |
736,920 | |
Loss from operations |
(239,103) |
(111,276) | |
Other income (expense): |
|||
Interest expense |
(80,953) |
(75,063) | |
Other |
384 |
347 | |
(80,569) |
(74,716) | ||
Loss before income taxes |
(319,672) |
(185,992) | |
Benefit for income taxes |
(121,346) |
(54,021) | |
Net loss |
$ (198,326) |
$ (131,971) | |
Basic net loss per share |
$ (0.54) |
$ (0.36) | |
Diluted net loss per share |
$ (0.54) |
$ (0.36) |
Continental Resources, Inc. and Subsidiaries | |||||
Unaudited Condensed Consolidated Balance Sheets | |||||
March 31, 2016 |
December 31, 2015 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
760,181 |
$ |
822,339 | |
Net property and equipment (1) |
13,843,132 |
14,063,328 | |||
Other noncurrent assets |
30,076 |
34,141 | |||
Total assets |
$ |
14,633,389 |
$ |
14,919,808 | |
Liabilities and shareholders' equity |
|||||
Current liabilities |
$ |
865,358 |
$ |
923,028 | |
Long-term debt, net of current portion |
7,203,440 |
7,115,644 | |||
Other noncurrent liabilities |
2,089,471 |
2,212,236 | |||
Total shareholders' equity |
4,475,120 |
4,668,900 | |||
Total liabilities and shareholders' equity |
$ |
14,633,389 |
$ |
14,919,808 |
(1) |
Balance is net of accumulated depreciation, depletion and amortization of $6.92 billion and $6.45 billion as of March 31, 2016 and December 31, 2015, respectively. |
Continental Resources, Inc. and Subsidiaries | ||||||
Unaudited Condensed Consolidated Statements of Cash Flows | ||||||
Three months ended March 31, | ||||||
In thousands |
2016 |
2015 | ||||
Net loss |
$ |
(198,326) |
$ |
(131,971) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: |
||||||
Non-cash expenses |
432,774 |
495,096 | ||||
Changes in assets and liabilities |
44,454 |
159,065 | ||||
Net cash provided by operating activities |
278,902 |
522,190 | ||||
Net cash used in investing activities |
(358,811) |
(1,278,404) | ||||
Net cash provided by financing activities |
81,342 |
784,383 | ||||
Effect of exchange rate changes on cash |
31 |
(4,905) | ||||
Net change in cash and cash equivalents |
1,464 |
23,264 | ||||
Cash and cash equivalents at beginning of period |
11,463 |
24,381 | ||||
Cash and cash equivalents at end of period |
$ |
12,927 |
$ |
47,645 |
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net loss to EBITDAX for the periods presented.
In thousands |
1Q 2016 |
4Q 2015 |
1Q 2015 | ||||||
Net loss |
$ |
(198,326) |
$ |
(139,677) |
$ |
(131,971) | |||
Interest expense |
80,953 |
80,175 |
75,063 | ||||||
Benefit for income taxes |
(121,346) |
(82,794) |
(54,021) | ||||||
Depreciation, depletion, amortization and accretion |
463,992 |
460,778 |
386,512 | ||||||
Property impairments |
78,927 |
81,001 |
147,561 | ||||||
Exploration expenses |
3,066 |
4,732 |
14,340 | ||||||
Impact from derivative instruments: |
|||||||||
Total gain on derivatives, net |
(41,052) |
(16,540) |
(32,755) | ||||||
Total cash received on derivatives, net |
39,189 |
21,019 |
23,435 | ||||||
Non-cash (gain) loss on derivatives, net |
(1,863) |
4,479 |
(9,320) | ||||||
Non-cash equity compensation |
9,206 |
11,545 |
11,263 | ||||||
EBITDAX |
$ |
314,609 |
$ |
420,239 |
$ |
439,427 |
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
In thousands |
1Q 2016 |
4Q 2015 |
1Q 2015 | ||||||
Net cash provided by operating activities |
$ |
278,902 |
$ |
441,609 |
$ |
522,190 | |||
Current income tax provision |
6 |
2 |
5 | ||||||
Interest expense |
80,953 |
80,175 |
75,063 | ||||||
Exploration expenses, excluding dry hole costs |
3,066 |
4,535 |
5,939 | ||||||
Gain on sale of assets, net |
109 |
218 |
2,070 | ||||||
Other, net |
(3,973) |
(2,020) |
(6,775) | ||||||
Changes in assets and liabilities |
(44,454) |
(104,280) |
(159,065) | ||||||
EBITDAX |
$ |
314,609 |
$ |
420,239 |
$ |
439,427 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments and gains and losses on asset sales. Management believes these measures provide useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
1Q 2016 |
4Q 2015 |
1Q 2015 | ||||||||||||||||
In thousands, except per share data |
After-Tax $ |
Diluted EPS |
After-Tax $ |
Diluted EPS |
After-Tax $ |
Diluted EPS | ||||||||||||
Net loss (GAAP) |
$ (198,326) |
$ (0.54) |
$ (139,677) |
$ (0.38) |
$(131,971) |
$ (0.36) | ||||||||||||
Adjustments, net of tax: |
||||||||||||||||||
Non-cash (gain) loss on derivatives, net |
(1,155) |
- |
2,777 |
0.01 |
(5,778) |
(0.01) | ||||||||||||
Property impairments |
49,081 |
0.13 |
50,391 |
0.14 |
105,214 |
0.28 | ||||||||||||
Gain on sale of assets, net |
(67) |
- |
(135) |
- |
(1,284) |
- | ||||||||||||
Adjusted net loss (Non-GAAP) |
$ (150,467) |
$ (0.41) |
$ (86,644) |
$ (0.23) |
$ (33,819) |
$ (0.09) | ||||||||||||
Weighted average diluted shares outstanding |
370,062 |
369,662 |
369,385 |
|||||||||||||||
Adjusted diluted net loss per share (Non-GAAP) |
$ (0.41) |
$ (0.23) |
$ (0.09) |
Continental Resources, Inc. | ||
2016 Guidance | ||
As of May 4, 2016 (1) | ||
2016 | ||
Full year average production |
205,000 - 215,000 Boe per day | |
Capital expenditures (non-acquisition) |
$920 million | |
Operating Expenses: |
||
Production expense per Boe |
$4.25 - $4.75 | |
Production tax (% of oil & gas revenue) |
6.75% - 7.25% | |
G&A expense per Boe |
$1.25 - $1.75 | |
Non-cash equity compensation per Boe |
$0.65 - $0.85 | |
DD&A per Boe |
$20.00 - $22.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($7.00) - ($9.00) | |
Henry Hub natural gas (per Mcf) |
$0.00 - ($0.65) | |
Income tax rate |
38% | |
Deferred taxes |
90% - 95% |
(1) |
"Full year average production" is bolded to denote a positive guidance revision from the previous disclosure provided on February 24, 2016. |
SOURCE Continental Resources
OKLAHOMA CITY, April 5, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") plans to announce first quarter 2016 results on Wednesday, May 4, 2016 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss first quarter 2016 results on Thursday, May 5, 2016 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
Time and date: |
12 p.m. ET, Thursday, May 5, 2016 |
Dial-in: |
855-291-6799 |
Intl. dial-in: |
315-625-3058 |
Conference ID: |
67924070 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay: |
800-585-8367 |
Conference ID: |
67924070 |
Continental plans to publish a first quarter 2016 summary presentation to its website at www.CLR.com prior to the start of its conference call on May 5, 2016.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has leading positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Manager, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Feb. 24, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced fourth quarter and full-year 2015 operating and financial results. Continental reported a net loss of $139.7 million, or $0.38 per diluted share, for the quarter ended December 31, 2015. Adjusted net loss for fourth quarter 2015 was $86.6 million, or $0.23 per diluted share.
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
For full-year 2015, the Company reported a net loss of $353.7 million, or $0.96 per diluted share. Adjusted net loss for full-year 2015 was $115.5 million, or $0.31 per diluted share.
EBITDAX for fourth quarter 2015 was $420.2 million, contributing to full-year 2015 EBITDAX of $1.98 billion. Definitions and reconciliations of adjusted net loss, adjusted earnings per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures can be found in the supporting tables at the conclusion of this press release.
"Our teams did an outstanding job in 2015 adjusting to market changes and working to align capital expenditures with cash flow. For 2016, we will remain patient and disciplined in our activities while striving to enhance shareholder value through continued improvements in our core plays, including our newest addition, the over-pressured STACK," commented Harold Hamm, Continental's Chairman and Chief Executive Officer.
He noted that three new wells in Oklahoma's STACK play further demonstrate the outstanding potential of Continental's leasehold position. "The Boden well was a significant step-out in southern Blaine County, and all three recent completions support our view of the upside of the over-pressured STACK Meramec formation," Mr. Hamm said.
"Our SCOOP Woodford team has engineered a step-change increase in 90-day and 180-day production rates by applying enhanced completion techniques using increased proppant loading," he said. "This has translated into higher estimated ultimate recoveries and made SCOOP an even more valuable growth platform."
Production
Fourth quarter 2015 net production totaled 20.7 million barrels of oil equivalent (Boe), or 224,900 Boe per day, down slightly from third quarter 2015 and 16% higher than fourth quarter 2014. February 2016 production is expected to be approximately 225,000 Boe per day.
Total net production for the fourth quarter included 145,600 barrels of oil (Bo) per day (65% of production) and 476.2 million cubic feet (MMcf) of natural gas per day (35% of production). Full-year 2015 production averaged 221,700 Boe per day, an increase of 27% compared with full-year 2014.
The following table provides the Company's average daily production by region for the periods presented.
4Q |
3Q |
4Q |
FY |
FY | ||||||
Boe per day |
2015 |
2015 |
2014 |
2015 |
2014 | |||||
North Region: |
||||||||||
North Dakota Bakken |
125,583 |
123,560 |
115,137 |
124,503 |
100,050 | |||||
Montana Bakken |
10,772 |
12,049 |
15,646 |
12,617 |
14,665 | |||||
Red River Units |
11,654 |
12,110 |
13,259 |
12,342 |
13,815 | |||||
Other |
902 |
992 |
690 |
1,103 |
800 | |||||
South Region: |
||||||||||
SCOOP |
64,534 |
69,136 |
40,403 |
61,586 |
35,128 | |||||
NW Cana/STACK |
7,709 |
6,629 |
3,780 |
5,560 |
4,906 | |||||
Arkoma |
2,124 |
2,056 |
2,318 |
2,104 |
2,493 | |||||
Other |
1,658 |
1,746 |
2,223 |
1,900 |
2,332 | |||||
Total |
224,936 |
228,278 |
193,456 |
221,715 |
174,189 |
Impressive New STACK Results Include 16-Mile Step-Out Well
The Company's new STACK completions were the Boden 1-15-10XH, the Compton 1-2-35XH and the Blurton 1-7-6XH, all extended lateral tests targeting the over-pressured Meramec formation in Blaine County.
The Boden is a significant step-out test located 16 miles southwest of Continental's first STACK well, the Ludwig 1-22-15XH. The Boden flowed at an impressive 24-hour initial production rate of 1,000 Bo and 15 MMcf of natural gas (3,508 Boe) from a 9,800-foot lateral. It is the Company's deepest test of the Meramec reservoir to date, with the lateral section of the well positioned at an average vertical depth of 12,550 feet. Through the first 80 days of production, the Boden has continued to exhibit strong flowing casing pressure of more than 5,000 psi on a 20/64" choke.
The Compton and Blurton wells were closer step-out tests located five miles southwest and three miles northwest, respectively, of the Ludwig. The Compton flowed at an initial 24-hour production rate of 1,817 Bo and 4.4 MMcf of natural gas (2,547 Boe) from a 9,800-foot lateral. The Blurton flowed at an initial 24-hour production rate of 1,818 Bo and 3.1 MMcf of natural gas (2,328 Boe) from a 9,600-foot lateral.
"Our over-pressured Meramec wells in STACK are delivering some of the highest returns in the Company. We clearly have another high impact, long-term platform for growth underlying our 155,000 net acres of leasehold in STACK," said Jack Stark, Continental's President and Chief Operating Officer. "The exceptional performance of these new wells supports our observation that over-pressured STACK wells produce on average three times more volume than wells in the normally-pressured STACK in their first 90 days, when normalized for a 9,800' foot lateral. This is significant, as almost all of Continental's STACK acreage is located in the over-pressured window."
Based on early production from recent Continental completions and other non-operated wells in the over-pressured oil window, the Company is estimating an average estimated ultimate recovery (EUR) of 1.7 MMBoe per well. Continental is targeting a completed operated well cost of $10 million for a 9,800-foot lateral well, which would generate a 55% rate of return at $40 per barrel WTI and $2.25 per thousand cubic feet (Mcf) of natural gas.
The Company plans to average four-to-five operated drilling rigs in STACK in 2016, which would enable it to drill approximately 15 net (25 gross) operated wells and complete approximately nine net (15 gross) operated wells this year in the play. Continental's STACK leasehold is primarily in Blaine, Dewey and Custer counties, and the Company anticipates more than 70% of it will be held by production by year-end 2016.
SCOOP Fourth Quarter Production Increases 60% Year over Year
In fourth quarter 2015, total SCOOP net production averaged 64,500 Boe per day, a 60% increase compared with the fourth quarter of 2014, and a 7% decrease sequentially compared with third quarter 2015, reflecting reduced completion activity. SCOOP production represented 29% of the Company's total production in fourth quarter 2015, compared with 21% of Company production for fourth quarter 2014.
Of total SCOOP production, SCOOP Woodford net production averaged 54,100 Boe per day in fourth quarter 2015, or 84% of the total. SCOOP Springer net production averaged 10,400 Boe per day.
Continental completed eight net (38 gross) operated and non-operated wells in SCOOP in fourth quarter 2015, while operating an average of seven rigs in the play. Of these, the Company completed 7.5 net (36 gross) wells targeting the Woodford formation and 0.5 net (two gross) wells targeting the Springer formation.
For full-year 2015, Continental completed 74 net (204 gross) operated and non-operated SCOOP wells. These included 54 net (175 gross) wells targeting the Woodford, and 20 net (29 gross) wells targeting the Springer.
For all Oklahoma plays, Continental ended 2015 with approximately 35 gross operated wells drilled and uncompleted (DUCs) and plans to end 2016 with approximately 50 gross operated DUCs. The Company noted that its DUC inventory may also include wells that are drilled and completed, but not yet producing to sales.
SCOOP Woodford Enhanced Completions Deliver Step-Change Production Improvement
Continental has tested enhanced completions, primarily involving larger proppant volumes, on 15 SCOOP Woodford condensate wells. All are producing in excess of the Company's standard type curve based on a 1.7 MMBoe EUR for a 7,500' lateral. Enhanced completions have increased initial 90-day and 180-day production rates 30% to 35%, compared with offset wells. Based on the performance of the enhanced completed wells, the Company is increasing its SCOOP Woodford condensate EUR by 15% to 2.0 MMBoe per well.
The incremental cost for the large enhanced completions being done currently is approximately $400,000, bringing the completed well cost for these wells to approximately $9.9 million. This cost is expected to decline during 2016 to a targeted well cost of $9.6 million. At a target cost of $9.6 million, these wells generate a 25% ROR based on $40 per barrel WTI and $2.25 per Mcf of gas.
"We are encouraged by the results from our enhanced completions in SCOOP, and we continue to work to optimize our stimulation designs," said Gary Gould, Senior Vice President of Production and Resource Development. "Our new type curves were built on data from initial enhanced completions with at least 90 days of production, and this well set had completion designs that averaged approximately 1,100 pounds of proppant per foot. More recently we've applied higher proppant concentrations averaging approximately 1,500 pounds per foot, and we're seeing even higher early production from these higher sand volumes."
SCOOP Woodford Density Test: Vanarkel Production Beats Enhanced Type Curve
Continental's Vanarkel density project came online in fourth quarter 2015. Vanarkel involved seven gross (four net) wells that were stimulated with enhanced completions averaging approximately 1,500 pounds per foot of proppant. Early initial production for the Vanarkel wells is beating the Company's updated SCOOP Woodford condensate type curve for enhanced completions. The wells flowed at an average total combined peak production rate of 52.4 MMcf and 4,980 Bo per day, or a total combined 13,713 Boe per day. Average peak production was 1,959 Boe per day per well in the project. Vanarkel production is 36% oil, comparable to the nearby Honeycutt density test.
The Vanarkel project was the Company's third dual-level density pilot in the SCOOP Woodford condensate window, consisting of wells in the upper and lower Woodford, spaced 660 feet apart between well bores with approximately 100 feet of vertical separation. Average lateral length for the new Vanarkel wells was 7,400 feet.
SCOOP Springer
Continental participated in completing two notable non-operated wells targeting the Springer formation in fourth quarter 2015. The first non-operated well flowed at a rate of approximately 2,100 Boe (88% oil) per day, and the second was announced by its operator as flowing at a rate of 1,007 Boe (89% oil) per day.
Bakken DUC Inventory Growing in 2016
Continental's Bakken production averaged 136,400 Boe per day in fourth quarter 2015, a slight increase over third quarter 2015.
The Company completed and initiated first sales for 22 net (105 gross) operated and non-operated Bakken wells during fourth quarter 2015, compared with a total 171 net (638 gross) operated and non-operated Bakken wells for full-year 2015. Continental's operated wells with initial production in fourth quarter 2015 involved wells that had been previously drilled and completed, but not actively produced with first sales until the fourth quarter.
In 2015, the Bakken team doubled capital efficiency and cut finding costs in half. This was accomplished through a combination of inventory high-grading, cost reductions and operating efficiencies. The Company reduced average drilling time for spud-to-total-depth (TD) by 23% and average drilling cost by 33%, compared to fourth quarter 2014. The average spud-to-TD time in fourth quarter 2015 was 13.4 days for a well with a two-mile lateral, down from 17.4 days for fourth quarter 2014.
In 2016, the Bakken drilling program will continue to focus on high rate-of-return areas in McKenzie and Mountrail counties, targeting wells with an average EUR of 900,000 Boe per well. Based on the higher EUR and a lower targeted completed well cost of $6.7 million per well, the Company expects capital efficiency to increase 17% and finding cost to decrease 15% in 2016.
Given its plans to defer most Bakken completions in 2016, Continental expects to increase its Bakken DUC inventory to approximately 195 gross operated DUCs at year-end 2016. The year-end 2016 DUC inventory represents a high-graded inventory with an average EUR per well of approximately 850,000 Boe. At year-end 2015, the Company's Bakken DUC inventory was approximately 135 gross operated DUCs.
The Company currently has four operated drilling rigs in the North Dakota Bakken and plans to maintain this level through year end. The Company currently has no stimulation crews deployed in the Bakken.
Financial Update
In fourth quarter 2015, Continental's average realized sales price excluding the effects of derivative positions was $34.23 per barrel of oil and $2.07 per Mcf of gas, or $26.57 per Boe. Based on realizations without the effect of derivatives, the Company's fourth quarter 2015 oil differential was $7.71 per barrel below the NYMEX daily average for the period. The fourth quarter 2015 realized wellhead natural gas price was on average $0.20 per Mcf below the average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.86 for fourth quarter 2015, a decrease of $1.45 per Boe from fourth quarter 2014. Other select operating costs and expenses for fourth quarter 2015 included production taxes of 7.8% of oil and natural gas sales; DD&A of $22.20 per Boe; and G&A (cash and non-cash) of $2.24 per Boe. On a full-year basis, these expense categories were within or better than guidance.
As of December 31, 2015, Continental's balance sheet included $11.5 million in cash and cash equivalents and $853 million of borrowings against the Company's revolving credit facility. Continental had approximately $1.9 billion in available borrowing capacity under its revolving credit facility as of December 31, 2015, and approximately $1.9 billion remains available at this time. The Company's revolver is unsecured, and there are no terms in the facility that would mandate collateral or a borrowing base calculation coming back into place. The revolver's sole financial covenant is a net debt to total capitalization ratio of no greater than 0.65, and as of December 31, 2015, the Company's net debt to total capitalization ratio was 0.58. Under the terms of the credit agreement, the calculation of total capitalization specifically excludes any non-cash impairment charges incurred after June 30, 2014.
Non-acquisition capital expenditures for fourth quarter 2015 totaled $394.0 million, including $343.6 million in exploration and development drilling, $32.8 million in leasehold and seismic and $17.6 million in workovers, recompletions and other. Acquisition capital expenditures totaled $17.8 million for fourth quarter 2015.
Full-year 2015 non-acquisition capital expenditures totaled $2.5 billion, in line with commentary made on the third quarter 2015 earnings call. Acquisition capital expenditures totaled $61.0 million for the year.
John Hart, Continental's Chief Financial Officer, commented, "We were very pleased to finish the year $200 million under our $2.7 billion budget, while still growing production 27% year-over-year. This speaks to the quality of our operating teams and assets. Looking ahead, our strategy is to stay focused on cash flow neutrality and maintaining our financial strength. We have ample liquidity with no near-term debt maturities."
Continental's 2016 guidance remains as announced on January 26, 2016 and can be found at the conclusion of this press release.
The following table provides the Company's production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended December 31, |
Year ended December 31, | ||||||
2015 |
2014 |
2015 |
2014 | ||||
Average daily production: |
|||||||
Crude oil (Bbl per day) |
145,576 |
136,972 |
146,622 |
121,999 | |||
Natural gas (Mcf per day) |
476,160 |
338,907 |
450,558 |
313,137 | |||
Crude oil equivalents (Boe per day) |
224,936 |
193,456 |
221,715 |
174,189 | |||
Average sales prices, excluding effect from derivatives: |
|||||||
Crude oil ($/Bbl) |
$34.23 |
$61.53 |
$40.50 |
$81.26 | |||
Natural gas ($/Mcf) |
$2.07 |
$4.36 |
$2.31 |
$5.40 | |||
Crude oil equivalents ($/Boe) |
$26.57 |
$51.11 |
$31.48 |
$66.53 | |||
Production expenses ($/Boe) |
$3.86 |
$5.31 |
$4.30 |
$5.58 | |||
Production taxes (% of oil and gas revenues) |
7.8% |
8.3% |
7.8% |
8.2% | |||
DD&A ($/Boe) |
$22.20 |
$22.39 |
$21.57 |
$21.51 | |||
General and administrative expenses ($/Boe) |
$1.68 |
$2.00 |
$1.70 |
$2.06 | |||
Non-cash equity compensation ($/Boe) |
$0.56 |
$0.85 |
$0.64 |
$0.86 | |||
Net income (loss) (in thousands) |
($139,677) |
$114,048 |
($353,668) |
$977,341 | |||
Diluted net income (loss) per share |
($0.38) |
$0.31 |
($0.96) |
$2.64 | |||
Adjusted net income (loss) (in thousands) (1) |
($86,644) |
$420,770 |
($115,525) |
$1,271,171 | |||
Adjusted diluted net income (loss) per share (1) |
($0.23) |
$1.14 |
($0.31) |
$3.43 | |||
EBITDAX (in thousands) (1) |
$420,239 |
$1,185,071 |
$1,978,896 |
$3,776,051 |
(1) |
Adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income (loss), diluted net income (loss) per share, or operating cash flows as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income (loss), adjusted diluted net income (loss) per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures. |
Fourth Quarter and Full-Year Earnings Conference Call
Continental plans to host a conference call to discuss fourth quarter and full-year results on Thursday, February 25, 2016, at 12 p.m. ET (11 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: |
12 p.m. ET, Thursday, February 25, 2016 | |
Dial in: |
855-291-6799 | |
Intl. dial in: |
315-625-3058 | |
Pass code: |
96302633 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 | |
Intl. replay: |
800-585-8367 | |
Pass code: |
96302633 |
Continental plans to publish a fourth quarter and full-year 2015 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 25, 2016.
Upcoming Conferences
Members of Continental's management team will be participating in the following upcoming investment conferences:
March 22, 2016 - Scotia Howard Weil 44th Annual Energy Conference, New Orleans
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2014, and once filed, for the year ended December 31, 2015, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Senior Analyst, Investor Relations |
|
405-774-5814 |
|
Continental Resources, Inc. and Subsidiaries Consolidated Statements of Income (Loss) | |||||||
Three months ended December 31, |
Year ended December 31, | ||||||
2015 |
2014 |
2015 |
2014 | ||||
Revenues: |
In thousands, except per share data | ||||||
Crude oil and natural gas sales |
$ 551,380 |
$ 902,323 |
$ 2,552,531 |
$ 4,203,022 | |||
Gain on derivative instruments, net |
16,540 |
387,958 |
91,085 |
559,759 | |||
Crude oil and natural gas service operations |
7,560 |
7,419 |
36,551 |
38,837 | |||
Total revenues |
575,480 |
1,297,700 |
2,680,167 |
4,801,618 | |||
Operating costs and expenses: |
|||||||
Production expenses |
80,185 |
93,691 |
348,897 |
352,472 | |||
Production taxes and other expenses |
43,048 |
77,034 |
200,637 |
349,760 | |||
Exploration expenses |
4,732 |
20,535 |
19,413 |
50,067 | |||
Crude oil and natural gas service operations |
2,292 |
3,481 |
17,337 |
21,871 | |||
Depreciation, depletion, amortization and accretion |
460,778 |
395,260 |
1,749,056 |
1,358,669 | |||
Property impairments |
81,001 |
393,803 |
402,131 |
616,888 | |||
General and administrative expenses |
46,478 |
50,220 |
189,846 |
184,655 | |||
Gain on sale of assets, net |
(218) |
(1,552) |
(23,149) |
(600) | |||
Total operating costs and expenses |
718,296 |
1,032,472 |
2,904,168 |
2,933,782 | |||
Income (loss) from operations |
(142,816) |
265,228 |
(224,001) |
1,867,836 | |||
Other income (expense): |
|||||||
Interest expense |
(80,175) |
(74,200) |
(313,079) |
(283,928) | |||
Loss on extinguishment of debt |
- |
- |
- |
(24,517) | |||
Other |
520 |
702 |
1,995 |
2,647 | |||
(79,655) |
(73,498) |
(311,084) |
(305,798) | ||||
Income (loss) before income taxes |
(222,471) |
191,730 |
(535,085) |
1,562,038 | |||
Provision (benefit) for income taxes |
(82,794) |
77,682 |
(181,417) |
584,697 | |||
Net income (loss) |
$ (139,677) |
$ 114,048 |
$ (353,668) |
$ 977,341 | |||
Basic net income (loss) per share |
$ (0.38) |
$ 0.31 |
$ (0.96) |
$ 2.65 | |||
Diluted net income (loss) per share |
$ (0.38) |
$ 0.31 |
$ (0.96) |
$ 2.64 |
Continental Resources, Inc. and Subsidiaries Consolidated Balance Sheets | |||||
December 31, 2015 |
December 31, 2014 | ||||
Assets |
In thousands | ||||
Current assets |
$ |
822,339 |
$ |
1,389,601 | |
Net property and equipment (1) |
14,063,328 |
13,635,852 | |||
Other noncurrent assets(2) |
34,141 |
50,580 | |||
Total assets |
$ |
14,919,808 |
$ |
15,076,033 | |
Liabilities and shareholders' equity |
|||||
Current liabilities (3) |
$ |
923,028 |
$ |
1,806,664 | |
Long-term debt, net of current portion (2) |
7,115,644 |
5,926,800 | |||
Other noncurrent liabilities (3) |
2,212,236 |
2,374,725 | |||
Total shareholders' equity |
4,668,900 |
4,967,844 | |||
Total liabilities and shareholders' equity |
$ |
14,919,808 |
$ |
15,076,033 |
(1) |
Balance is net of accumulated depreciation, depletion and amortization of $6.45 billion and $4.65 billion as of December 31, 2015 and December 31, 2014, respectively. |
(2) |
Balances at December 31, 2014 have been retroactively adjusted to reflect the Company's June 2015 adoption of Accounting Standards Update 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which resulted in the reclassification of $69.0 million of unamortized debt issuance costs at December 31, 2014 from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion". |
(3) |
Balances at December 31, 2014 have been retroactively adjusted to reflect the Company's December 2015 adoption of Accounting Standards Update 2015-17, Balance Sheet Classification of Deferred Taxes, which resulted in the reclassification of $145.3 million of deferred tax liabilities at December 31, 2014 from "Current liabilities" to "Other noncurrent liabilities". |
Continental Resources, Inc. and Subsidiaries Consolidated Statements of Cash Flows | ||||||||||||
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2015 |
2014 |
2015 |
2014 | ||||||||
Net income (loss) |
$ |
(139,677) |
$ |
114,048 |
$ |
(353,668) |
$ |
977,341 | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
Non-cash expenses |
477,006 |
995,960 |
1,982,147 |
2,505,053 | ||||||||
Changes in assets and liabilities |
104,280 |
(32,144) |
228,622 |
(126,679) | ||||||||
Net cash provided by operating activities |
441,609 |
1,077,864 |
1,857,101 |
3,355,715 | ||||||||
Net cash used in investing activities |
(448,548) |
(1,361,139) |
(3,046,247) |
(4,587,399) | ||||||||
Net cash provided by financing activities |
3,492 |
155,498 |
1,187,189 |
1,227,715 | ||||||||
Effect of exchange rate changes on cash |
(2,045) |
(132) |
(10,961) |
(132) | ||||||||
Net change in cash and cash equivalents |
(5,492) |
(127,909) |
(12,918) |
(4,101) | ||||||||
Cash and cash equivalents at beginning of period |
16,955 |
152,290 |
24,381 |
28,482 | ||||||||
Cash and cash equivalents at end of period |
$ |
11,463 |
$ |
24,381 |
$ |
11,463 |
$ |
24,381 |
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income (loss) and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2015 |
2014 |
2015 |
2014 | ||||||||
Net income (loss) |
$ |
(139,677) |
$ |
114,048 |
$ |
(353,668) |
$ |
977,341 | ||||
Interest expense |
80,175 |
74,200 |
313,079 |
283,928 | ||||||||
Provision (benefit) for income taxes |
(82,794) |
77,682 |
(181,417) |
584,697 | ||||||||
Depreciation, depletion, amortization and accretion |
460,778 |
395,260 |
1,749,056 |
1,358,669 | ||||||||
Property impairments |
81,001 |
393,803 |
402,131 |
616,888 | ||||||||
Exploration expenses |
4,732 |
20,535 |
19,413 |
50,067 | ||||||||
Impact from derivative instruments: |
||||||||||||
Total gain on derivatives, net |
(16,540) |
(387,958) |
(91,085) |
(559,759) | ||||||||
Total cash received on derivatives, net |
21,019 |
482,567 |
69,553 |
385,350 | ||||||||
Non-cash (gain) loss on derivatives, net |
4,479 |
94,609 |
(21,532) |
(174,409) | ||||||||
Non-cash equity compensation |
11,545 |
14,934 |
51,834 |
54,353 | ||||||||
Loss on extinguishment of debt |
- |
- |
- |
24,517 | ||||||||
EBITDAX |
$ |
420,239 |
$ |
1,185,071 |
$ |
1,978,896 |
$ |
3,776,051 | ||||
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended December 31, |
Year ended December 31, | |||||||||||
In thousands |
2015 |
2014 |
2015 |
2014 | ||||||||
Net cash provided by operating activities |
$ |
441,609 |
$ |
1,077,864 |
$ |
1,857,101 |
$ |
3,355,715 | ||||
Current income tax provision (benefit) |
2 |
(2,258) |
24 |
20 | ||||||||
Interest expense |
80,175 |
74,200 |
313,079 |
283,928 | ||||||||
Exploration expenses, excluding dry hole costs |
4,535 |
5,998 |
11,032 |
26,388 | ||||||||
Gain on sale of assets, net |
218 |
1,552 |
23,149 |
600 | ||||||||
Excess tax benefit from stock-based compensation |
- |
- |
13,177 |
- | ||||||||
Other, net |
(2,020) |
(4,429) |
(10,044) |
(17,279) | ||||||||
Changes in assets and liabilities |
(104,280) |
32,144 |
(228,622) |
126,679 | ||||||||
EBITDAX |
$ |
420,239 |
$ |
1,185,071 |
$ |
1,978,896 |
$ |
3,776,051 |
Adjusted earnings and adjusted earnings per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following tables reconcile earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Three Months Ended December 31, | ||||||||||
2015 |
2014 | |||||||||
In thousands, except per share data |
After-Tax $ |
Diluted EPS |
After-Tax $ |
Diluted EPS | ||||||
Net income (loss) (GAAP) |
$(139,677) |
$ (0.38) |
$ 114,048 |
$ 0.31 | ||||||
Adjustments, net of tax: |
||||||||||
Non-cash loss on derivatives, net |
2,777 |
0.01 |
59,603 |
0.16 | ||||||
Property impairments |
50,391 |
0.14 |
248,096 |
0.67 | ||||||
Gain on sale of assets, net |
(135) |
- |
(977) |
- | ||||||
Adjusted net income (loss) (Non-GAAP) |
$ (86,644) |
$ (0.23) |
$ 420,770 |
$ 1.14 | ||||||
Weighted average diluted shares outstanding |
369,662 |
370,545 |
||||||||
Adjusted diluted net income (loss) per share (Non-GAAP) |
$ (0.23) |
$ 1.14 |
||||||||
Year Ended December 31, | ||||||||||
2015 |
2014 | |||||||||
In thousands, except per share data |
After-Tax $ |
Diluted EPS |
After-Tax $ |
Diluted EPS | ||||||
Net income (loss) (GAAP) |
$(353,668) |
$ (0.96) |
$ 977,341 |
$ 2.64 | ||||||
Adjustments, net of tax: |
||||||||||
Non-cash gain on derivatives, net |
(13,350) |
(0.03) |
(109,878) |
(0.30) | ||||||
Property impairments |
265,842 |
0.72 |
388,640 |
1.05 | ||||||
Gain on sale of assets, net |
(14,349) |
(0.04) |
(378) |
- | ||||||
Loss on extinguishment of debt |
- |
- |
15,446 |
0.04 | ||||||
Adjusted net income (loss) (Non-GAAP) |
$(115,525) |
$ (0.31) |
$1,271,171 |
$ 3.43 | ||||||
Weighted average diluted shares outstanding |
369,540 |
370,758 |
||||||||
Adjusted diluted net income (loss) per share (Non-GAAP) |
$ (0.31) |
$ 3.43 |
Continental Resources, Inc. 2016 Guidance As of February 24, 2016 | ||
2016 | ||
Full year average production |
200,000 Boe per day | |
Capital expenditures (non-acquisition) |
$920 million | |
Operating Expenses: |
||
Production expense per Boe |
$4.25 to $4.75 | |
Production tax (% of oil & gas revenue) |
6.75% to 7.25% | |
G&A expense per Boe |
$1.25 to $1.75 | |
Non-cash equity compensation per Boe |
$0.65 to $0.85 | |
DD&A per Boe |
$20.00 to $22.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($7.00) to ($9.00) | |
Henry Hub natural gas (per Mcf) |
$0.00 to ($0.65) | |
Income tax rate |
38% | |
Deferred taxes |
90% to 95% |
SOURCE Continental Resources
OKLAHOMA CITY, Feb. 10, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced proved reserves of 1.23 billion barrels of oil equivalent (Boe) at December 31, 2015, compared with year-end 2014 proved reserves of 1.35 billion Boe. Year-end 2015 proved reserves were 57% crude oil, 87% operated by the Company, and 43% proved developed producing (PDP).
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
Harold Hamm, Chairman and Chief Executive Officer, commented, "The 9% year-over-year reduction in our proved reserves during 2015, compared with an approximately 50% reduction in crude oil prices, clearly validates the premier quality of Continental's inventory of assets."
Total production for full-year 2015 was 80.9 million barrels of oil equivalent (MMBoe), or 221,700 Boe per day, an increase of 27% compared to full-year 2014. Crude oil accounted for 66% of total 2015 production, or 53.5 million barrels of oil. Natural gas production for the year was 164.5 billion cubic feet.
Continental's year-end 2015 proved reserves had a net present value discounted at 10% (PV-10) of $8.0 billion. The Bakken play in North Dakota and Montana accounted for 663 MMBoe of Continental's year-end 2015 proved reserves, with a PV-10 value of $4.4 billion, or 56% of total proved reserves PV-10. The SCOOP Woodford and SCOOP Springer plays in Oklahoma accounted for 413 MMBoe of Continental's year-end 2015 proved reserves, with a PV-10 value of $2.5 billion, or 31% of total proved reserves PV-10. The Company completed its initial wells in the over-pressured window of the Oklahoma STACK play in the past year.
Proved reserves finding cost was an average $9.87 per Boe for 2015. Production reduced 2015 proved reserves by 81 MMBoe, while drilling activity added 253 MMBoe. The conversion through drilling activity of proved undeveloped assets (PUDs) moved 81 MMBoe from the PUD category to the PDP category.
PDP reserves increased 6% to 521 MMBoe at December 31, 2015, compared with year-end 2014. The Company had 1,860 gross (995 net) PUD locations at year-end 2015, with the Bakken accounting for 1,292 gross (705 net) PUD locations. Included in these PUD reserves are 179 gross operated (125 net) drilled but uncompleted wells (DUCs), representing 91 MMBoe in proved reserves. These DUCs have completion and equipping capital remaining to be invested to produce the additional PUD reserves.
The Company's 2015 price deck for calculating proved reserves, before adjustment for location and quality differentials, was $50.28 per barrel of crude oil and $2.58 per MMBtu for natural gas, compared to the 2014 price deck of $94.99 per barrel for oil and $4.35 per MMBtu for gas.
The Company's year-end 2015 proved reserves reflected a net 297 MMBoe in negative revisions for the year, the largest component of which involved price revisions of 251 MMBoe. The next largest component involved de-booked and expired PUDs of 98 MMBoe, primarily on Bakken acreage outside the Company's core leasehold in the play. Partially offsetting these and 46 MMBoe in other negative revisions were 98 MMBoe in positive adjustments for reduced lease operating expense and other factors.
Non-GAAP Financial Measure
The Company's PV-10 value, a non-GAAP financial measure, is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. The Company believes the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of the Company's proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company's crude oil and natural gas properties.
The Company has not provided a reconciliation of its PV-10 to Standardized Measure in this release because final income tax information for 2015 is not yet available. The Company will provide its customary reconciliation of PV-10 to Standardized Measure in its forthcoming Form 10-K for the year ended December 31, 2015 to be filed with the SEC.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2014, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: |
Warren Henry |
Kristin Thomas |
Vice President, Investor Relations and Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Senior Analyst, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Jan. 27, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") plans to announce fourth quarter and full-year 2015 earnings on Wednesday, February 24, 2016 following the close of trading on the New York Stock Exchange. The Company plans to host a conference call to discuss fourth quarter and full-year 2015 results on Thursday, February 25, 2016 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
Time and date: |
12 p.m. ET, Thursday, February 25, 2016 |
Dial-in: |
855-291-6799 |
Intl. dial-in: |
315-625-3058 |
Conference ID: |
96302633 |
A replay of the call will be available for 14 days on the Company's website or by dialing:
Replay number: |
855-859-2056 or 404-537-3406 |
Intl. replay |
800-585-8367 |
Conference ID: |
96302633 |
Continental plans to publish a fourth quarter and full-year 2015 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 25, 2016.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Investor Contacts: |
Media Contact: |
J. Warren Henry |
Kristin Thomas |
Vice President, Investor Relations & Research |
Vice President, Public Relations |
405-234-9127 |
405-234-9480 |
Alyson L. Gilbert |
|
Senior Analyst, Investor Relations |
|
405-774-5814 |
|
SOURCE Continental Resources
OKLAHOMA CITY, Jan. 26, 2016 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today announced a budget of $920 million in non-acquisition capital expenditures for 2016, a 66% reduction from 2015's $2.7 billion budget. The Company expects average production of approximately 200,000 barrels of oil equivalent (Boe) per day for 2016.
Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO
"Continental's 2016 budget confirms our intense focus on cash flow neutrality," said Harold Hamm, Chairman and Chief Executive Officer for the Company. "Strategically, we are dedicated to preserving the value of our premier assets and building operational efficiencies in preparation for crude oil prices to stabilize and start recovering later this year. Fortunately our lean organization and strong liquidity have us well-positioned to manage through this period until the recovery begins."
The Company currently estimates 2015 actual non-acquisition capital expenditures were approximately $2.5 billion, or approximately $200 million under budget for 2015. Continental expects average production for 2015 to be approximately 221,700 Boe per day, above previously revised guidance. The Company expects to report year-end 2015 total long term debt that is essentially flat with long-term debt at September 30, 2015, up only $7 million quarter over quarter. Continental plans to report full-year 2015 results on February 24, 2016, after the close of market trading.
2016 Guidance Detail
Looking to the current year, the Company expects first quarter 2016 production will be in a range of 210,000 and 220,000 Boe per day and expects to exit 2016 with fourth quarter production between 180,000 and 190,000 Boe per day, reflecting reduced drilling and a lower level of well completion activity. The Company's 2016 production mix is expected to average 60% crude oil and 40% natural gas. Full 2016 guidance is available at the conclusion of this press release.
Non-acquisition capital spending is expected to be approximately $300 million in first quarter 2016, down from an estimated $395 million in the fourth quarter of 2015. By fourth quarter 2016, capital expenditures are expected to decline to approximately $200 million.
The Company estimates its 2016 capital expenditures budget will be cash flow neutral at an average WTI price of $37 per barrel for the full year. At an average WTI price of $40, the Company estimates 2016 results would be cash flow positive in excess of $100 million.
"Our 2016 budget reflects the improved operating efficiencies and well performance we achieved over the past year," said Jack Stark, President and Chief Operating Officer. "These accomplishments are a testament to the quality of Continental's assets and operations, which continue to provide us strategic optionality to deal with the volatility in today's energy market."
Continental has the ability to further reduce discretionary capital expenditures in 2016 if necessary. "We will continue to focus our investments in our core operating areas and expect to realize further efficiency gains and cost reductions as we optimize our portfolio," said John Hart, Senior Vice President and Chief Financial Officer. "In terms of our budget, each $5 move in WTI prices impacts our full-year cash flow by $150 million to $200 million."
Continental has $1.9 billion in available borrowing capacity under its revolving credit facility. The Company's revolver is unsecured, and there are no terms in the facility that would mandate collateral or a borrowing base calculation coming back into place. The revolver's sole financial covenant is a debt to total capitalization ratio of no greater than 0.65, and as of December 31, 2015, the Company's debt to total capitalization ratio was 0.58, well under the limit. Under the terms of the credit agreement, this calculation of total capitalization specifically excludes any non-cash impairment charges after mid-2014.
2016 Capital Expenditures by Play
The Company expects to spend 35% of its 2016 capital expenditures in the North Dakota Bakken and 28% in the SCOOP play in Oklahoma. Other key investment areas will be the STACK play in Oklahoma, with 15% of capital expenditures, and the Northwest Cana Joint Development (JDA) area, with 7% of capital expenditures. The remaining 15% portion of the 2016 budget will target other capital expenditures such as routine leasing and renewals, work-overs, and facilities.
Continental's 2016 capital expenditures budget anticipates an average of 19 operated drilling rigs for the year, with four in the North Dakota Bakken, five to six in SCOOP, five in Northwest Cana JDA, and four to five in STACK. Continental recently decreased its operated rig count from 23 to 19 by dropping four rigs in Bakken, and therefore the current deployment of operated rigs is in line with the expected averages for the 2016 budget.
In terms of wells, the Company expects to complete 71 net operated and non-operated wells in 2016, with 26 in Bakken, 25 in SCOOP, 11 in Northwest Cana JDA and nine in STACK.
Continental plans to defer completing most Bakken wells in 2016, which will increase the drilled but uncompleted ("DUC") inventory from 135 gross DUCs at year-end 2015 to 195 gross DUCs at year-end 2016. This is a high-graded inventory of DUCs, with an average estimated ultimate recovery (EUR) per well of 850,000 Boe.
In Oklahoma, Continental plans to deploy an average of 2.5 completion crews in 2016. The Company ended 2015 with approximately 35 gross DUCs in Oklahoma, and expects to end 2016 with approximately 50 gross DUCs, with an average EUR per well of 1.8 million Boe.
"This high quality DUC inventory represents a significant asset for the Company as prices recover," said Jack Stark.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and one of the largest producers in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK and Northwest Cana plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2016, the Company will celebrate 49 years of operations. For more information, please visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended December 31, 2014, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Investor Contact: |
Media Contact: | ||
J. Warren Henry |
Kristin Thomas | ||
Vice President, Investor Relations & Research |
Vice President, Public Relations | ||
405-234-9127 |
405-234-9480 | ||
Alyson L. Gilbert |
|||
Senior Analyst, Investor Relations |
|||
405-774-5814 |
|||
Continental Resources, Inc. 2016 Guidance As of January 26, 2016 | ||
2016 | ||
Full year average production |
200,000 Boe per day | |
Capital expenditures (non-acquisition) |
$920 million | |
Operating Expenses: |
||
Production expense per Boe |
$4.25 to $4.75 | |
Production tax (% of oil & gas revenue) |
6.75% to 7.25% | |
G&A expense per Boe |
$1.25 to $1.75 | |
Non-cash equity compensation per Boe |
$0.65 to $0.85 | |
DD&A per Boe |
$20.00 to $22.00 | |
Average Price Differentials: |
||
NYMEX WTI crude oil (per barrel of oil) |
($7.00) to ($9.00) | |
Henry Hub natural gas (per Mcf) |
$0.00 to ($0.65) | |
Income tax rate |
38% | |
Deferred taxes |
90% to 95% |
Continental Resources, Inc. | ||||||
2016 Non-Acquisition Capital Expenditures | ||||||
The following table provides the breakout of non-acquisition capital expenditures. | ||||||
($ in millions) |
SCOOP |
STACK |
NW Cana |
Bakken |
Leasehold |
Other |
CAPEX |
$260 |
$142 |
$62 |
$320 |
$78 |
$58 |
Continental Resources, Inc. | ||||
Year-End 2016 Targeted Average Completed Well Cost and | ||||
Operated & Non-operated Gross / Net Well Completions for 2016 | ||||
The following table provides the breakout of average targeted completed well costs per play and operated and non-operated gross / net well completions: | ||||
($ in millions) |
SCOOP(1) (1.5-mile lateral) |
STACK(2) (2-mile lateral) |
NW Cana (2-mile lateral) |
Bakken (2-mile lateral) |
Average Completed Well Cost |
$9.6 |
$10.0 |
$12.3 |
$6.7 |
Gross Completions |
113 |
15 |
28 |
127 |
Net Completions |
25 |
9 |
11 |
26 |
1) |
Targeted completed well cost for SCOOP Woodford wells. | |
2) |
Targeted completed well cost for volatile oil window in over-pressured STACK play. |
SOURCE Continental Resources
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