Project: Lebanon Extension Project
Firm Commitment: 0
Project: Zone Three Capacity Expansion (East-to-West Expansion Project)
Firm Commitment: 50,000 Dth/d
Project: Northern Supply Access
Firm Commitment: 54,000 MMbtu/d
Project: Rover Pipeline LLC
Firm Commitment: 150 Mmcf/d
Project: MIDSHIP Project
Firm Commitment: 300 Mmcf/d
Project: Leach Xpress
Firm Commitment: 100 Mmcf/d
COST: 133.8 $MM
NEW YORK, May 15, 2020 /PRNewswire/ -- Rosen Law Firm, a global investor rights law firm, reminds purchasers of the securities of Gulfport Energy Corporation (NASDAQ: GPOR) between May 3, 2019, and February 27, 2020, inclusive (the "Class Period"), of the important May 18, 2020 lead plaintiff deadline in the securities class action. The lawsuit seeks to recover damages for Gulfport investors under the federal securities laws.
To join the Gulfport class action, go to http://www.rosenlegal.com/cases-register-1816.html or call Phillip Kim, Esq. toll-free at 866-767-3653 or email pkim@rosenlegal.com or cases@rosenlegal.com for information on the class action.
NO CLASS HAS YET BEEN CERTIFIED IN THE ABOVE ACTION. UNTIL A CLASS IS CERTIFIED, YOU ARE NOT REPRESENTED BY COUNSEL UNLESS YOU RETAIN ONE. YOU MAY RETAIN COUNSEL OF YOUR CHOICE. YOU MAY ALSO REMAIN AN ABSENT CLASS MEMBER AND DO NOTHING AT THIS POINT. AN INVESTOR'S ABILITY TO SHARE IN ANY POTENTIAL FUTURE RECOVERY IS NOT DEPENDENT UPON SERVING AS LEAD PLAINTIFF.
According to the lawsuit, defendants throughout the Class Period made false and/or misleading statements and/or failed to disclose that: (1) a material weakness existed in Gulfport's internal control over financial reporting; (2) accordingly, Gulfport's disclosure controls and procedures were ineffective; (3) Gulfport's financial statements contained multiple misstatements; and (4) as a result, the Company's public statements were materially false and misleading at all relevant times. When the true details entered the market, the lawsuit claims that investors suffered damages.
A class action lawsuit has already been filed. If you wish to serve as lead plaintiff, you must move the Court no later than May 18, 2020. A lead plaintiff is a representative party acting on behalf of other class members in directing the litigation. If you wish to join the litigation, go to http://www.rosenlegal.com/cases-register-1816.html or to discuss your rights or interests regarding this class action, please contact Phillip Kim, Esq. of Rosen Law Firm toll free at 866-767-3653 or via e-mail at pkim@rosenlegal.com or cases@rosenlegal.com.
Follow us for updates on LinkedIn: https://www.linkedin.com/company/the-rosen-law-firm, on Twitter: https://twitter.com/rosen_firm or on Facebook: https://www.facebook.com/rosenlawfirm/.
Rosen Law Firm represents investors throughout the globe, concentrating its practice in securities class actions and shareholder derivative litigation. Rosen Law Firm was Ranked No. 1 by ISS Securities Class Action Services for number of securities class action settlements in 2017. The firm has been ranked in the top 3 each year since 2013. Rosen Law Firm has secured hundreds of millions of dollars for investors. Attorney Advertising. Prior results do not guarantee a similar outcome.
Contact Information:
Laurence Rosen, Esq.
Phillip Kim, Esq.
The Rosen Law Firm, P.A.
275 Madison Avenue, 40th Floor
New York, NY 10016
Tel: (212) 686-1060
Toll Free: (866) 767-3653
Fax: (212) 202-3827
lrosen@rosenlegal.com
pkim@rosenlegal.com
cases@rosenlegal.com
www.rosenlegal.com
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SOURCE Rosen Law Firm, P.A.
NEW YORK, March 25, 2020 /PRNewswire/ -- Kaplan Fox & Kilsheimer LLP (www.kaplanfox.com) is investigating claims on behalf of investors of Gulfport Energy Corporation ("Gulfport" or the "Company") (NASDAQ: GPOR). A complaint has been filed against the Company on behalf of investors that purchased Gulfport securities between May 3, 2019 and February 27, 2020, inclusive (the "Class Period").
On February 27, 2020, after the market closed, Gulfport disclosed that its previously issued financial statements for the three and nine months ended September 30, 2019 "should no longer be relied upon due to material misstatements."
Gulfport further disclosed to investors that "the Company has reassessed its conclusions regarding its disclosure controls and procedures as of September 30, 2019 in light of the misstatements," and, "[a]s a result, the Company has determined that a material weakness in internal control over financial reporting existed as of September 30, 2019, and therefore the Company has concluded that its disclosure controls and procedures as of September 30, 2019 were not effective."
Following this news, Gulfport's stock price fell $0.08 per share, approximately 9%, to close at $0.82 per share on February 28, 2020.
If you are a member of the proposed Class, you may move the court no later than May 18, 2020 to serve as a lead plaintiff for the purported class. You need not seek to become a lead plaintiff in order to share in any possible recovery. If you would like to discuss the complaint or our investigation, please contact us by emailing pmayer@kaplanfox.com or by calling 646-315-9003.
This press release may be considered Attorney Advertising in some jurisdictions under the applicable law and ethical rules.
Kaplan Fox & Kilsheimer LLP, with offices in New York, San Francisco, Los Angeles, Chicago and New Jersey, has many years of experience in prosecuting investor class actions. For more information about Kaplan Fox & Kilsheimer LLP, you may visit our website at www.kaplanfox.com. If you have any questions about this Notice, your rights, or your interests, please contact:
Donald R. Hall
KAPLAN FOX & KILSHEIMER LLP
850 Third Avenue, 14th Floor
New York, New York 10022
(646) 315-9003
E-mail: dhall@kaplanfox.com
Laurence D. King
KAPLAN FOX & KILSHEIMER LLP
1999 Harrison Street, Suite 1560
Oakland, California 94612
(415) 772-4704
E-mail: lking@kaplanfox.com
View original content:http://www.prnewswire.com/news-releases/investor-alert-kaplan-fox-announces-investigation-of-gulfport-energy-corporation-301030073.html
SOURCE Kaplan Fox & Kilsheimer LLP
OKLAHOMA CITY, Dec. 19, 2019 /PRNewswire/ -- Bison, Oklahoma's largest water infrastructure, logistics and solutions provider, today announced that it has entered into definitive agreements to acquire Gulfport Energy Corporation's (NASDAQ: GPOR) water infrastructure in the SCOOP for an upfront payment and other contingent consideration based on the timing, pace and magnitude of Gulfport's future development program and water production levels. Simultaneously, the parties entered into 15-year agreements whereby Bison will exclusively manage all of Gulfport's water gathering, recycling, storage, reuse, disposal, transportation, logistics and sourcing within a dedicated area across Grady, Garvin and Stephens counties. The acquired assets include the 15-year agreements, a multi-line water gathering and delivery system, 2.3 million barrels of storage capacity, 40,000 barrels per day of recycling capacity, 55,000 barrels per day of freshwater supply capacity, associated real property and a pending saltwater disposal permit.
North Whipple, CEO of Bison, commented: "Today's announcement is another major milestone for our company, which has grown exponentially throughout the year and now serves over 12 E&P customers dedicated to our infrastructure under long-term agreements. In addition to serving Gulfport's development for the next 15 years, these assets will allow us to bring new recycling and reuse solutions to our customers throughout the SCOOP. We are proud to have been selected among the many other bidders in this highly competitive process and believe it is a testament to our proven track record of responsibly managing water infrastructure of any size, scale and scope across Oklahoma."
For more information regarding the company, visit our website at www.BisonOK.com or email us at Media@BisonOK.com.
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SOURCE Bison
NEW YORK, Dec. 6, 2018 /PRNewswire/ -- S&P MidCap 400 constituent Gulfport Energy Corp. (NASD: GPOR) will replace Oclaro Inc. (NASD: OCLR) in the S&P SmallCap 600, and Yelp Inc. (NYSE: YELP) will replace Gulfport Energy in the S&P MidCap 400 effective prior to the open of trading on Wednesday, December 12. S&P MidCap 400 constituent Lumentum Holdings Inc. (NASD: LITE) is acquiring Oclaro in a deal expected to be completed soon pending final conditions. Gulfport Energy has a market capitalization more representative of the small-cap market space.
Yelp operates a platform that connects people with local businesses. Headquartered in San Francisco, CA, the company will be added to the S&P MidCap 400 GICS (Global Industry Classification Standard) Interactive Media & Services Sub-Industry index.
Gulfport Energy engages in the acquisition, exploration and production of natural gas, crude oil, and natural gas liquids. Headquartered in Oklahoma City, OK, the company will be added to the S&P SmallCap 600 GICS Oil & Gas Exploration & Production Sub-Industry index.
Following is a summary of the changes:
S&P MIDCAP 400 INDEX – DECEMBER 12, 2018 | |||
COMPANY | GICS ECONOMIC SECTOR | GICS SUB-INDUSTRY | |
ADDED | Yelp | Communication Services | Interactive Media & |
DELETED | Gulfport Energy | Energy | Oil & Gas Exploration & |
S&P SMALLCAP 600 INDEX – DECEMBER 12, 2018 | |||
COMPANY | GICS ECONOMIC SECTOR | GICS SUB-INDUSTRY | |
ADDED | Gulfport Energy | Energy | Oil & Gas Exploration & |
DELETED | Oclaro | Information Technology | Communications |
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S&P Dow Jones Indices is a division of S&P Global (NYSE: SPGI), which provides essential intelligence for individuals, companies, and governments to make decisions with confidence. For more information, visit www.spdji.com.
FOR MORE INFORMATION:
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SOURCE S&P Dow Jones Indices
CANONSBURG, Pa., Feb. 24, 2016 /PRNewswire/ -- Rice Energy Inc. (NYSE: RICE) ("Rice Energy") today announced its 2016 capital budget and guidance. Estimated capital investments and financial guidance include:
Commenting on the 2016 capital budget and guidance, Daniel J. Rice IV, Chief Executive Officer, said, "We believe that our 2016 capital budget highlights the resiliency of our assets and appropriately reflects the challenging time for our industry. Our capital budget has been established with a goal of generating healthy returns while maintaining a strong balance sheet throughout the year. We believe the combination of our 30% return wells at strip pricing, healthy balance sheet, disciplined hedging approach, and our right-sized firm transportation portfolio to favorable markets allows us to economically develop our E&P assets in a manner that drives value in both our E&P and midstream operations."
Further commenting on the 2016 capital budget and guidance, Grayson T. Lisenby, Chief Financial Officer, said, "As evidenced by our recently announced $375 million RMH preferred equity investment by EIG, the significant embedded value of our midstream assets continues to provide a meaningful financing lever despite the headwinds faced today. This equity investment positions us to maintain a healthy balance sheet in 2016 with the proceeds along with expected cash flow fully funding our 2016 E&P budget. Building off the momentum we created in 2015, our capital budget is front half of 2016 weighted, and we expect to exit 2016 with E&P leverage at approximately 3.0 times and an undrawn revolver. We've further protected our balance sheet and returns with 87% of our production hedged at $3.26 per MMbtu."
1. |
Pro forma for the $375 million preferred equity transaction that closed on February 22, 2016. |
2016 Capital Budget
We plan to allocate our capital investments according to the table below:
2016 Capital Budget ($ in millions) |
||
E&P |
||
Operated Marcellus |
$ |
285 |
Operated Ohio Utica |
$ |
175 |
Non-operated Ohio Utica |
$ |
100 |
Total Drilling & Completion |
$ |
560 |
Land(1) |
$ |
80 |
Total E&P |
$ |
640 |
Midstream |
||
Rice Midstream Holdings LLC |
$ |
155 |
Rice Midstream Partners LP |
$ |
150 |
Total Midstream |
$ |
305 |
1. |
Excluding acquisitions. |
Exploration and Production
Drilling and completion capital is expected to total $560 million in 2016, a 10% reduction as compared to 2015. On our Marcellus acreage in southwestern Pennsylvania, we plan to spud 25 net Marcellus wells and turn to sales 27 net wells with an average lateral length of 7,700 feet. We expect our Marcellus well costs to average $1,100 per lateral foot in 2016, which is a 7% reduction as compared to 2015 costs. On our operated Utica acreage in Belmont County, Ohio we plan to spud 12 net Utica wells and place into sales 13 net wells with an average lateral length of 9,300 feet. We expect our operated Utica well costs to average $1,450 per lateral foot in 2016, which is a 12% reduction as compared to 2015 costs. In addition, we expect to participate as a non-operator in the drilling of 5 net Utica wells and the completion of 14 net Utica wells with an average lateral length of 8,200 feet, all of which are located in Belmont County and operated by Gulfport Energy Corporation (NASDAQ: GPOR). Due to improved drilling efficiencies gained in 2015, we released one horizontal rig in January and are currently operating one Marcellus horizontal rig and one Ohio Utica horizontal rig.
We have budgeted $80 million for land in 2016, primarily to secure strategic leaseholds within our core development areas in Washington and Greene Counties, Pennsylvania, and Belmont County, Ohio.
Midstream
In 2016, we plan to invest $155 million to further develop our 100%-owned Belmont County gathering system and to fund our portion of capital requirements of our recently announced midstream joint venture Strike Force Midstream LLC with Gulfport Energy. Separately, RMP will invest $150 million for the continued buildout of its gathering and compression systems in Pennsylvania and fresh water systems in Pennsylvania and Ohio.
2016 Financial and Operational Guidance
Our 2016 net production is expected to average between 700 – 740 MMcfe/d for the year, a 27% – 34% increase over 2015.
Our 2016 guidance is based on the key assumptions in the table below:
Net Wells | ||||||||||||
Spud |
Online |
|||||||||||
Operated Marcellus |
25 |
27 |
||||||||||
Operated Ohio Utica |
12 |
13 |
||||||||||
Non-operated Ohio Utica |
5 |
14 |
||||||||||
Total Net Wells |
42 |
54 |
||||||||||
Lateral Length (ft.) of Wells Turned Online |
||||||||||||
Operated Marcellus |
7,700 | |||||||||||
Operated Ohio Utica |
9,300 | |||||||||||
Non-operated Ohio Utica |
8,200 | |||||||||||
Total Net Production (MMcfe/d) |
700 – 740 | |||||||||||
% Natural gas |
100% | |||||||||||
% Operated |
85% | |||||||||||
% Marcellus |
65% | |||||||||||
Pricing: |
||||||||||||
FT Fuel & Variable (Deduction) ($/Mcfe) |
$ |
(0.14) |
- |
$ |
(0.16) | |||||||
Heat Content (Btu/Scf) |
||||||||||||
Marcellus |
1050 | |||||||||||
Utica |
1080 | |||||||||||
Cash Operating Costs ($/Mcfe) |
||||||||||||
Lease Operating Expense |
$ |
0.22 |
- |
$ |
0.25 | |||||||
Gathering and Compression |
$ |
0.45 |
- |
$ |
0.50 | |||||||
Firm Transportation |
$ |
0.35 |
- |
$ |
0.40 | |||||||
Production Taxes and Impact Fees |
$ |
0.04 |
- |
$ |
0.06 | |||||||
Total Cash Operating Costs |
$ |
1.06 |
- |
$ |
1.21 | |||||||
Cash G&A ($ in millions) | ||||||||||||
E&P |
$ |
85 |
- |
$ |
90 | |||||||
Midstream |
$ |
25 |
- |
$ |
28 | |||||||
Total Cash G&A |
$ |
110 |
- |
$ |
118 | |||||||
Midstream Adjusted EBITDA(1) ($ in millions) |
||||||||||||
Rice Midstream Holdings LLC |
$ |
40 |
- |
$ |
45 | |||||||
Rice Midstream Partners LP |
$ |
110 |
- |
$ |
120 | |||||||
Total Midstream Adjusted EBITDA |
$ |
150 |
- |
$ |
165 | |||||||
1. |
Please see "Supplemental Non-GAAP Financial Measure" for a description of Adjusted EBITDA. |
About Rice Energy
Rice Energy Inc. is an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. For more information, please visit our website at www.riceenergy.com.
Forward Looking Statements
This release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than historical facts included in this release, that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as future capital expenditures (including the amount and nature thereof), projected operational results, projected Adjusted EBITDA, production growth, the timing and number of well completions, the timing of completion and nature of midstream projects, business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although we believe that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
We caution you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development expenditures. Information concerning these and other factors can be found in our filings with the Securities and Exchange Commission, including our Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this news release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by us will be realized, or even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.
Supplemental Non-GAAP Financial Measure
(Unaudited)
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as securities analysts, investors and lenders. We define Adjusted EBITDA as net income (loss) before interest expense, income tax benefit, depreciation and amortization, stock compensation expense and incentive unit expense. Adjusted EBITDA is not a measure of net income as determined by GAAP.
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SOURCE Rice Energy Inc.
CANONSBURG, Pa., Feb. 24, 2016 /PRNewswire/ -- Rice Energy Inc. (NYSE: RICE) ("Rice Energy") today reported fourth quarter and full-year 2015 financial and operational results. Highlights to date include:
Commenting on the results, Daniel J. Rice IV, Chief Executive Officer, said, "Our 2015 accomplishments highlight our unique asset quality, differentiated technical approach and our financial strength. Our core position within the most productive and economic windows of the Marcellus and Utica Shales provides a solid foundation that is supported by a balanced firm transportation portfolio and systematic hedging strategy to continue economically growing our business including expanding our world-class midstream assets. Our strategy continues to be focused on protecting the balance sheet while generating the highest return on investments to drive long-term value creation for our shareholders."
1. |
Please see "Supplemental Non-GAAP Financial Measure" for a description of Adjusted EBITDAX, PV-10, and Further Adjusted EBITDAX. |
2. |
Adjusted realized price includes our firm transportation sales, net, and the impact of hedging. |
3. |
Excludes Rice Midstream Partners LP. |
4. |
Pro forma for the $375 million preferred equity investment that closed February 22, 2016. |
Three Months Ended |
Year Ended | |||||||
2015 Consolidated Results |
December 31, 2015 |
December 31, 2015 | ||||||
Total production (MMcfe) |
57,399 |
201,328 |
||||||
Total production (MMcfe/d) |
624 |
552 |
||||||
% Gas |
100 |
% |
99 |
% | ||||
% Operated |
94 |
% |
93 |
% | ||||
% Marcellus |
72 |
% |
74 |
% | ||||
Average realized prices per Mcf: |
||||||||
Natural gas price before effects of hedges |
$ |
2.05 |
$ |
2.21 |
||||
Natural gas price after effects of hedges(1) |
$ |
3.39 |
$ |
3.18 |
||||
Adjusted realized price |
$ |
3.39 |
$ |
3.19 |
||||
Average oil and NGL price per Bbl |
$ |
23.64 |
$ |
21.79 |
||||
Average costs per Mcfe: |
||||||||
Lease operating |
$ |
0.16 |
$ |
0.22 |
||||
Gathering, compression and transportation |
$ |
0.51 |
$ |
0.42 |
||||
Production taxes and impact fees |
$ |
0.04 |
$ |
0.04 |
||||
General and administrative(2) |
$ |
0.43 |
$ |
0.43 |
||||
Depreciation, depletion and amortization |
$ |
1.65 |
$ |
1.60 |
||||
Adjusted EBITDAX (in thousands) |
$ |
132,153 |
$ |
431,510 |
||||
Total midstream throughput (MDth/d) |
1,026 |
894 |
||||||
% Third-party |
25 |
% |
22 |
% |
Fourth Quarter 2015 Financial Results
During the fourth quarter, our net daily production averaged 624 MMcfe/d (100% natural gas), a 57% increase relative to fourth quarter 2014 production. This quarterly production growth was primarily driven by improved well performance and wells online ahead of schedule.
Fourth quarter average realized natural gas price, before the effect of hedges, was $2.05 per Mcf. After giving effect to hedges, our average natural gas price was $3.39 per Mcf. Approximately 91% of our fourth quarter production received favorable Gulf Coast, TCO and Midwest pricing, as compared to 76% of third quarter 2015 production, due to increasing premium market exposure through our firm transportation portfolio. Our average basis differential for the quarter was ($0.14) per MMBtu, while TETCO M2 and Dominion South averaged ($0.93) and ($0.92) per MMBtu, respectively, below NYMEX Henry Hub for the quarter.
Per unit cash production costs (lease operating; gathering, compression and transportation; and production taxes and impact fees) were $0.71 per Mcfe. Adjusted EBITDAX for the quarter was $132.2 million. We reported adjusted net income(3) of $22.0 million, or $0.16 per share, after excluding unrealized gains on derivative contracts and other non-recurring income and expense items.
1. |
The effect of hedges includes realized gains and losses on commodity derivative transactions. |
2. |
Excludes equity compensation expense of $0.08 per Mcfe for the three and twelve months ended December 31, 2015. |
3. |
Please see "Supplemental Non-GAAP Financial Measure" for a description of Adjusted Net Income. |
Full Year 2015 Financial Results
Net production averaged 552 MMcfe/d, a 101% increase as compared to pro forma 2014. Our 2015 average realized natural gas price, before the effect of hedges, was $2.21 per Mcf. After giving effect to hedges, our average natural gas price was $3.18 per Mcf. The average adjusted realized price was $3.19 per Mcf. Per unit cash production costs were $0.68 per Mcfe. Adjusted EBITDAX during 2015 was $431.5 million. We reported adjusted net income of $0.8 million, or $0.01 per share.
During 2015, we invested $625 million to drill and complete Marcellus and Utica wells and invested $115 million in land activity. Additionally, we invested $248 million for our retained midstream assets.
Financial Position and Liquidity
As of December 31, 2015, our pro forma(1) liquidity position, excluding RMP, was $1.4 billion, consisting of $1.1 billion of upstream liquidity and $300 million of RMH liquidity.
Pro forma for the preferred equity transaction, our net debt to Further Adjusted EBITDAX(2) was 2.1 times for full year 2015 and 1.7 times for the fourth quarter 2015 annualized.
1. |
Pro forma for the $375 million preferred equity transaction that closed on February 22, 2016. |
2. |
Please see "Supplemental Non-GAAP Financial Measure" for a description of Further Adjusted EBITDAX. |
Operational Results
Marcellus Shale
Marcellus net production averaged 446 MMcfe/d during the fourth quarter, a 9% increase from the prior quarter and a 33% increase relative to fourth quarter 2014.
During the fourth quarter, we turned to sales 6 gross (6 net) horizontal Marcellus wells with an average lateral length of 7,499 feet at an average development cost of $1,192 per lateral foot.
In 2015, we placed online 42 gross (37 net) horizontal Marcellus wells. We exited 2015 with 120 net operated horizontal Marcellus wells producing into sales. As of December 31, 2015, our Marcellus leasehold position in Washington and Greene Counties, Pennsylvania, consisted of approximately 92,000 net acres and 487 undeveloped drilling locations.
In January 2016, we turned 5 gross (5 net) horizontal Marcellus wells to sales with an average lateral length of 6,600 feet.
The following table provides operational data through December 31, 2015, for our operated Marcellus wells.
Periodic Flow Rates (MMcfe/d) |
|||||||||||||||
Period |
Gross Operated Wells Turned Into Sales |
Average Lateral Length (Feet) |
0-90 |
91-180 |
181-360 |
361-720 |
D&C ($/Foot) | ||||||||
2010-2011 |
6 |
3,279 |
5.7 |
6.0 |
4.4 |
2.7 |
$ |
2,342 | |||||||
2012 |
9 |
5,731 |
9.2 |
10.0 |
6.8 |
4.1 |
$ |
1,583 | |||||||
2013 |
22 |
6,320 |
11.2 |
10.6 |
7.6 |
4.6 |
$ |
1,439 | |||||||
2014(1) |
41 |
7,272 |
10.6 |
9.2 |
6.3 |
N/A |
$ |
1,237 | |||||||
2015 |
42 |
7,298 |
9.4 |
8.3 |
N/A |
N/A |
$ |
1,181 | |||||||
Total(2) |
120 |
6,792 |
10.0 |
9.2 |
6.6 |
4.1 |
$ |
1,336 |
1. |
Excludes 7 acquired producing wells. |
2. |
With the exception of wells turned into sales, totals represent averages weighted by number of wells. |
Utica Shale
Utica net production averaged 174 MMcfe/d for the fourth quarter, a 196% increase relative to fourth quarter 2014.
In 2015, we placed online 14 gross (10 net) horizontal Utica wells, including one Pennsylvania Utica well. We exited the year with 17 gross (12 net) operated Utica wells producing into sales. At year-end 2015, we had a non-operated working interest in 36 gross (7 net) producing horizontal Ohio Utica wells.
As of December 31, 2015, our Ohio Utica leasehold position consisted of approximately 56,000 net acres and 215 undeveloped drilling locations. Our Pennsylvania Utica leasehold position in Washington and Greene Counties, consisted of approximately 49,000 net acres and 105 undeveloped drilling locations.
The following table provides operational data through December 31, 2015, for our operated Ohio Utica wells.
Periodic Flow Rates (MMcf/d) |
|||||||||||||||
Period |
Gross Operated Wells Turned Into Sales |
Average Lateral Length (Feet) |
0-90 |
91-180 |
181-360 |
361-720 |
D&C($/Foot) | ||||||||
2014 |
3 |
8,238 |
14.3 |
15.3 |
16.2 |
N/A |
$ |
2,457 | |||||||
2015 |
13 |
9,759 |
15.5 |
14.3 |
N/A |
N/A |
$ |
1,653 | |||||||
Total(1) |
16 |
9,474 |
15.3 |
14.5 |
16.2 |
N/A |
$ |
1,802 |
1. |
With the exception of wells turned into sales, totals represent averages weighted by number of wells. |
Midstream Segment
For the fourth quarter, average daily throughput was 1,026 MDth/d, a 74% increase relative to fourth quarter 2014, with 25% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $38.8 million for the quarter. Operation and maintenance expenses totaled $6.0 million, and operating income was $17.6 million.
For the year ended December 31, 2015, average daily throughput was 894 MDth/d, with 22% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $141.8 million. Operation and maintenance expenses totaled $17.0 million, and operating income was $75.7 million.
Rice Midstream Partners LP (NYSE: RMP)("RMP" or the "Partnership")
Average daily throughput for the fourth quarter was 703 MDth/d, a 36% increase relative to fourth quarter 2014, with 18% attributable to third-party volumes. Water services volumes totaled 202 million gallons, with 58% attributable to third-party volumes. The Partnership reported net income attributable to limited partners of $12.5 million, or $0.18 per limited partner unit.
As of December 31, 2015, RMP had $307 million of undrawn capacity on its revolving credit facility and $8 million of cash on hand, resulting in $315 million of total liquidity.
On January 22, 2016, RMP declared its quarterly distribution of $0.1965 per unit for the fourth quarter 2015, an increase of $0.003 per unit relative to third quarter 2015. The distribution was payable on February 11, 2016 to unitholders of record as of February 2, 2016.
Subsequent to year-end, Rice renegotiated its third party gas gathering agreement for acreage acquired from Chesapeake Appalachia, L.L.C. in August 2014 to increase the acreage dedication from Rice to RMP by 19,000 gross acres to approximately 93,000 gross acres. RMP will gather all production above the first 40 MDth/d, as well as pursue additional third party gathering and water opportunities surrounding this dedication.
Rice Midstream Holdings LLC
Average daily throughput for the fourth quarter of 2015 was 323 MDth/d, a 336% increase relative to fourth quarter 2014, with 40% attributable to third-party volumes. For the year ended December 31, 2015, average daily throughput was 247 MDth/d, with 38% attributable to third-party volumes.
On February 1, 2016, our wholly-owned subsidiary, Strike Force Holdings LLC, and a subsidiary of Gulfport Energy Corporation (NASDAQ: GPOR) completed the formation of its previously announced Utica Shale midstream JV, Strike Force Midstream LLC ("Strike Force"). RMH owns 75% of Strike Force and will act as the operator, and GPOR owns the remaining 25% and dedicated approximately 75,000 leasehold acres. Strike Force will develop natural gas gathering assets to support GPOR's dry gas Utica Shale development in eastern Belmont County and Monroe County, Ohio and will pursue additional third party opportunities within approximately 319,000 acres in the AMI. Strike Force will be supported by long-term, fee-based service agreements with GPOR. Construction of the assets is underway and phase one was completed ahead of schedule, allowing GPOR to commence first flow on a lateral that connected two existing dry gas gathering systems.
2015 Proved Reserves
Proved reserves increased by 30% from year-end 2014 to over 1.7 Tcfe at December 31, 2015. The Marcellus Shale accounted for approximately 75% of our total proved reserves and the Utica Shale accounted for the substantial remainder. Our year-end 2015 proved reserves were 99.8% natural gas with an 8-year estimated reserve life, based on 2015 production. As of December 31, 2015, approximately 15% of our 1,369 total net identified drilling locations were classified as proved.
Estimated Proved Reserves as of December 31, 2015 | |||||||||||||||||
SEC Pricing |
Strip Pricing(1) |
||||||||||||||||
$2.59/MMBtu |
|||||||||||||||||
Net Reserves (Bcfe) |
PV-10 (in millions) |
Net Reserves (Bcfe) |
PV-10 (in millions) |
Net Locations | |||||||||||||
Proved developed reserves |
1,015 |
$ |
802 |
1,053 |
$ |
935 |
156 |
||||||||||
Proved undeveloped reserves |
685 |
85 |
698 |
246 |
54 |
||||||||||||
Hedge value |
408 |
265 |
|||||||||||||||
Total proved reserves |
1,700 |
$ |
1,295 |
1,751 |
$ |
1,446 |
210 |
||||||||||
Un-booked locations(2) |
1,159 |
||||||||||||||||
Total Estimated Locations |
1,369 |
||||||||||||||||
Percent developed locations |
11 |
% |
1. |
Strip pricing: 2016 - $2.45; 2017 - $2.78; 2018 - $2.90; 2019 - $3.01. |
2. |
Represents management's calculation of net locations not included in total proved reserves net locations. |
Proved Developed Reserves
Proved developed reserves increased by 57% from year-end 2014 to approximately 1.0 Tcfe, as of December 31, 2015. Approximately 60% of our total proved reserves were classified as proved developed, as compared to 49% at year-end 2014. There were 156 net wells categorized as proved developed at year-end 2015, consisting of 143 net producing wells and 13 net non-producing wells.
Proved Undeveloped Reserves
Proved undeveloped reserves increased by 3% from year-end 2014 to approximately 685 Bcfe, as of December 31, 2015. There were 54 net locations categorized as proved undeveloped at year-end 2015, including 15 net Utica locations. Based on 2015 well cost assumptions, our 685 Bcfe of proved undeveloped reserves will require an estimated $517 million of future development capital over the next five years, which results in an estimated average development cost of $0.75 per Mcfe for our proved undeveloped reserves.
Proved Reserves PV-10
Using NYMEX strip pricing, the pre-tax present value discounted at 10% (pre-tax PV-10) for our year-end 2015 total proved reserves was $1.4 billion, including $265 million of hedge value. Our pre-tax PV-10 value of our proved developed reserves was $935 million.
Using SEC pricing, the pre-tax PV-10 of our year-end 2015 total proved reserves was $1.3 billion, including $408 million of hedge value. Our pre-tax PV-10 value of our proved developed reserves was $802 million. Our estimated proved reserves and PV-10 value were determined using an SEC Henry Hub spot price of $2.59 per MMBtu, which is based on the 12-month unweighted arithmetic average of the first day of the month price for each month in the January through December 2015 period and is not indicative of current forward prices.
Commodity Hedge Position
As depicted in the table below, we have 662 BBtu/d hedged in 2016 at a weighted average floor price of $3.26 MMBtu. Our 2016 hedges cover 87% of our 2016 production (based on the midpoint of guidance). Additionally, for the first quarter of 2016 we have 556 BBtu/d hedged at a weighted average floor price of $3.30 per MMBtu. For 2017 we have 563 BBtu/d hedged at a weighted average floor price of $3.14 MMBtu. Our 2017 hedges are expected to cover more than half of our 2017 production. Please see the "Derivatives Information" table at the end of this press release for more detailed information about our derivatives positions.
Total Fixed Price Derivatives |
2016 |
2017 |
2018 |
2019 | ||||||||
Volume Hedged Excl. Calls (BBtu/d) |
662 |
563 |
285 |
150 |
||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
3.26 |
$ |
3.14 |
$ |
3.16 |
$ |
3.11 |
Firm Transportation and Realized Gas Pricing
In 2016, we anticipate that approximately 70% of our production will be transported to premium gas markets outside of Appalachia. The following tables provide basis exposure as a percentage of our production and average differentials to NYMEX for actual results through December 31, 2015 and estimated results for the first quarter of 2016 and full year 2016 and 2017.
Basis Exposure | ||||||||
Actual |
Estimated | |||||||
4Q15 |
1Q16 |
FY 2016 |
FY 2017 | |||||
Gulf Coast |
47% |
46% |
46% |
51% | ||||
TCO |
18% |
14% |
9% |
7% | ||||
Midwest/Dawn |
26% |
18% |
14% |
9% | ||||
DTI / M2 / M3 |
9% |
22% |
31% |
33% |
Realized Price | |||||||||||||||
Actual |
Estimated(1) | ||||||||||||||
4Q15 |
1Q16 |
FY 2016 |
FY 2017 | ||||||||||||
NYMEX Henry Hub price ($/MMBtu) |
$ |
2.23 |
$ |
2.08 |
$ |
2.16 |
$ |
2.58 |
|||||||
Average basis impact ($/MMBtu) |
(0.14) |
(0.28) |
(0.35) |
(0.32) |
|||||||||||
Firm transportation fuel & variables ($/MMBtu) |
(0.15) |
(0.14) |
(0.12) |
(0.13) |
|||||||||||
Btu uplift (MMBtu/Mcf) |
0.11 |
0.10 |
0.11 |
0.14 |
|||||||||||
Pre-hedge realized price ($/Mcf) |
2.05 |
1.76 |
1.80 |
2.27 |
|||||||||||
Realized hedging gain (loss) ($/Mcf) |
1.34 |
1.03 |
0.96 |
0.34 |
|||||||||||
Post-hedge realized price ($/Mcf) |
3.39 |
2.79 |
2.76 |
2.61 |
1. |
NYMEX price as of 2/18/16. |
Conference Call
Rice Energy will host a conference call on February 25, 2016 at 9:30 a.m. Eastern time (8:30 a.m. Central time) to discuss fourth quarter and full year 2015 financial and operating results. To listen to a live audio webcast of the conference call, please visit Rice Energy's website at www.riceenergy.com. A replay of the conference call will be available for two weeks and can also be accessed from our homepage.
Please visit www.riceenergy.com to view a presentation containing fourth quarter and full year 2015 information.
About Rice Energy
Rice Energy Inc. is an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. For more information, please visit our website at www.riceenergy.com.
Forward Looking Statements
This release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than historical facts included or incorporate herein that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as future capital expenditures (including the amount and nature thereof), projected operational results, production growth, basis exposure, hedging, the timing and number of well completions, forecasted gathering volumes, revenues, adjusted EBITDA, distribution growth, distributable cash flow, private placement by the Partnership, the midstream JV, the timing of completion and nature of midstream projects, business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although we believe that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
We caution you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price volatility; the availability of capital on an economic basis; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; legislative and regulatory changes adversely affecting the industry; transportation capacity constraints and interruptions; the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development expenditures. Furthermore, the acquisition of the water services business by the Partnership, the concurrent private placement by the Partnership and related transactions may not be completed as described or at all. Information concerning these and other factors can be found in our filings with the Securities and Exchange Commission, including our Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this news release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by us will be realized, or even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.
Rice Energy Inc. | ||||||||||||||||
Three Months Ended |
Year Ended | |||||||||||||||
December 31, |
December 31, | |||||||||||||||
(in thousands, except share data) |
2015 |
2014 |
2015 |
2014 | ||||||||||||
Operating revenues: |
||||||||||||||||
Natural gas, oil and natural gas liquids (NGL) sales |
$ |
118,568 |
$ |
112,385 |
$ |
446,515 |
$ |
359,201 |
||||||||
Firm transportation sales, net |
98 |
14,386 |
3,450 |
26,237 |
||||||||||||
Gathering, compression and water services |
14,424 |
2,627 |
49,179 |
5,504 |
||||||||||||
Other revenue |
2,997 |
— |
2,997 |
— |
||||||||||||
Total operating revenues |
136,087 |
129,398 |
502,141 |
390,942 |
||||||||||||
Operating expenses: |
||||||||||||||||
Lease operating |
9,350 |
8,565 |
44,356 |
24,971 |
||||||||||||
Gathering, compression and transportation |
29,197 |
13,154 |
84,707 |
35,618 |
||||||||||||
Production taxes and impact fees |
2,507 |
2,024 |
7,609 |
4,647 |
||||||||||||
Exploration |
1,212 |
2,436 |
3,137 |
4,018 |
||||||||||||
Midstream operation and maintenance |
6,024 |
1,043 |
16,988 |
4,607 |
||||||||||||
Incentive unit (income) expense |
(9,773) |
4,266 |
36,097 |
105,961 |
||||||||||||
Stock compensation expense |
4,847 |
2,279 |
16,528 |
5,553 |
||||||||||||
Impairment of gas properties |
18,250 |
— |
18,250 |
— |
||||||||||||
Impairment of goodwill |
294,908 |
— |
294,908 |
— |
||||||||||||
General and administrative |
24,607 |
19,284 |
86,510 |
56,017 |
||||||||||||
Depreciation, depletion and amortization |
94,787 |
64,358 |
322,784 |
156,270 |
||||||||||||
Acquisition expense |
1,111 |
92 |
1,235 |
2,339 |
||||||||||||
Amortization of intangible assets |
408 |
408 |
1,632 |
1,156 |
||||||||||||
Gain from sale of interest in gas properties |
— |
— |
(953) |
— |
||||||||||||
Other expense |
2,896 |
207 |
6,520 |
207 |
||||||||||||
Total operating expenses |
480,331 |
118,116 |
940,308 |
401,364 |
||||||||||||
Operating (loss) income |
(344,244) |
11,282 |
(438,167) |
(10,422) |
||||||||||||
Interest expense |
(24,009) |
(11,454) |
(87,446) |
(50,191) |
||||||||||||
Gain on purchase of Marcellus joint venture |
— |
— |
— |
203,579 |
||||||||||||
Other income |
167 |
713 |
1,108 |
893 |
||||||||||||
Gain on derivative instruments |
89,019 |
181,120 |
273,748 |
186,477 |
||||||||||||
Amortization of deferred financing costs |
(1,403) |
(766) |
(5,124) |
(2,495) |
||||||||||||
Loss on extinguishment of debt |
— |
(3,720) |
— |
(7,654) |
||||||||||||
Write-off of deferred financing costs |
— |
— |
— |
(6,896) |
||||||||||||
Equity in (loss) income of joint ventures |
— |
— |
— |
(2,656) |
||||||||||||
(Loss) income before income taxes |
(280,470) |
177,175 |
(255,881) |
310,635 |
||||||||||||
Income tax benefit (expense) |
6,217 |
(72,813) |
(12,118) |
(91,600) |
||||||||||||
Net (loss) income |
(274,253) |
104,362 |
(267,999) |
219,035 |
||||||||||||
Less: Net income attributable to non-controlling interests |
(6,504) |
(581) |
(23,337) |
(581) |
||||||||||||
Net (loss) income attributable to Rice Energy Inc. |
$ |
(280,757) |
$ |
103,781 |
$ |
(291,336) |
$ |
218,454 |
||||||||
Weighted average number of shares of common stock - basic |
136,384,591 |
136,280,766 |
136,344,076 |
128,151,171 |
||||||||||||
Weighted average number of shares of common stock - diluted |
136,384,591 |
136,352,435 |
136,344,076 |
128,225,155 |
||||||||||||
(Loss) earnings per share—basic |
$ |
(2.06) |
$ |
0.76 |
$ |
(2.14) |
$ |
1.70 |
||||||||
(Loss) earnings per share—diluted |
$ |
(2.06) |
$ |
0.76 |
$ |
(2.14) |
$ |
1.70 |
Rice Energy Inc. | ||||||||||||||||
Exploration and Production Segment | ||||||||||||||||
Three Months Ended |
Year Ended | |||||||||||||||
December 31, |
December 31, | |||||||||||||||
(in thousands, except volumes) |
2015 |
2014 |
2015 |
2014 | ||||||||||||
Operating volumes: |
||||||||||||||||
Natural gas production (MMcf) |
57,201 |
36,076 |
199,831 |
97,172 |
||||||||||||
Oil and NGL production (MBbls) |
33 |
91 |
249 |
94 |
||||||||||||
Total production (MMcfe) |
57,399 |
36,621 |
201,328 |
97,737 |
||||||||||||
Operating revenues: |
||||||||||||||||
Natural gas, oil and NGL sales |
$ |
118,568 |
$ |
112,385 |
$ |
446,515 |
$ |
359,201 |
||||||||
Firm transportation sales, net |
98 |
14,386 |
3,450 |
26,237 |
||||||||||||
Other revenue |
2,997 |
— |
2,997 |
— |
||||||||||||
Total operating revenues |
121,663 |
126,771 |
452,962 |
385,438 |
||||||||||||
Operating expenses: |
||||||||||||||||
Lease operating |
9,350 |
8,565 |
44,356 |
24,971 |
||||||||||||
Gathering, compression and transportation |
47,994 |
14,748 |
150,015 |
37,414 |
||||||||||||
Production taxes and impact fees |
2,507 |
2,024 |
7,609 |
4,647 |
||||||||||||
Exploration |
1,212 |
2,437 |
3,137 |
4,018 |
||||||||||||
Incentive unit (income) expense |
(10,056) |
(4,012) |
33,873 |
86,020 |
||||||||||||
Stock compensation expense |
3,140 |
1,661 |
11,029 |
4,532 |
||||||||||||
Impairment of gas properties |
18,250 |
— |
18,250 |
— |
||||||||||||
Impairment of goodwill |
294,908 |
— |
294,908 |
— |
||||||||||||
General and administrative |
19,680 |
12,357 |
67,563 |
41,697 |
||||||||||||
Depreciation, depletion and amortization |
91,529 |
62,584 |
308,194 |
151,900 |
||||||||||||
Gain from sale of interest in gas properties |
— |
— |
(953) |
— |
||||||||||||
Other expense |
3,049 |
— |
6,028 |
— |
||||||||||||
Acquisition expense |
108 |
58 |
108 |
820 |
||||||||||||
Total operating expenses |
481,671 |
100,422 |
944,117 |
356,019 |
||||||||||||
Operating (loss) income |
$ |
(360,008) |
$ |
26,349 |
$ |
(491,155) |
$ |
29,419 |
||||||||
Average costs per Mcfe: |
||||||||||||||||
Lease operating |
$ |
0.16 |
$ |
0.23 |
$ |
0.22 |
$ |
0.26 |
||||||||
Gathering and compression |
0.42 |
— |
0.38 |
— |
||||||||||||
Transportation |
0.42 |
0.40 |
0.36 |
0.38 |
||||||||||||
Production taxes and impact fees |
0.04 |
0.06 |
0.04 |
0.05 |
||||||||||||
Exploration |
0.02 |
0.07 |
0.02 |
0.04 |
||||||||||||
General and administrative |
0.34 |
0.34 |
0.34 |
0.43 |
||||||||||||
Depreciation, depletion and amortization |
1.59 |
1.71 |
1.53 |
1.55 |
Midstream Segment | ||||||||||||||||
Three Months Ended |
Year Ended | |||||||||||||||
December 31, |
December 31, | |||||||||||||||
(in thousands, except volumes) |
2015 |
2014 |
2015 |
2014 | ||||||||||||
Operating volumes: |
||||||||||||||||
Gathering volumes (MDth/d): |
1,027 |
592 |
894 |
402 |
||||||||||||
Compression volumes (MDth/d): |
295 |
— |
115 |
— |
||||||||||||
Water services volumes (MMgal): |
202 |
— |
777 |
— |
||||||||||||
Operating revenues: |
||||||||||||||||
Gathering revenues |
$ |
29,498 |
$ |
4,589 |
$ |
101,822 |
$ |
7,300 |
||||||||
Compression revenues |
1,158 |
(368) |
2,753 |
— |
||||||||||||
Water services revenues |
8,141 |
— |
37,248 |
— |
||||||||||||
Total operating revenues |
38,797 |
4,221 |
141,823 |
7,300 |
||||||||||||
Operating expenses: |
||||||||||||||||
Midstream operation and maintenance |
6,024 |
1,043 |
16,988 |
4,607 |
||||||||||||
Incentive unit expense |
284 |
8,278 |
2,224 |
19,941 |
||||||||||||
Stock compensation expense |
1,707 |
618 |
5,499 |
1,021 |
||||||||||||
General and administrative |
4,926 |
6,927 |
18,947 |
14,320 |
||||||||||||
Depreciation, depletion and amortization |
6,844 |
1,773 |
19,185 |
4,370 |
||||||||||||
Amortization of intangible assets |
408 |
408 |
1,632 |
1,156 |
||||||||||||
Acquisition costs |
1,127 |
35 |
1,127 |
1,519 |
||||||||||||
Other expense |
(152) |
207 |
492 |
207 |
||||||||||||
Total operating expenses |
21,168 |
19,289 |
66,094 |
47,141 |
||||||||||||
Operating income (loss) |
$ |
17,629 |
$ |
(15,068) |
$ |
75,729 |
$ |
(39,841) |
Rice Energy Inc.
Supplemental Non-GAAP Financial Measure
(Unaudited)
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before non-controlling interest; interest expense; income taxes; depreciation, depletion and amortization; amortization of deferred financing costs; amortization of intangible assets; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash stock compensation expense; non-cash incentive unit expense; exploration expenses; and other non-recurring items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.
Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted 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. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted 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 Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.
The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).
Three Months Ended |
Year Ended | ||||||
(in thousands) |
December 31, 2015 |
December 31, 2015 | |||||
Adjusted EBITDAX reconciliation to net income (loss): |
|||||||
Net loss |
$ |
(274,253) |
$ |
(267,999) |
|||
Interest expense |
24,009 |
87,446 |
|||||
Depreciation, depletion and amortization |
94,787 |
322,784 |
|||||
Impairment of gas properties |
18,250 |
18,250 |
|||||
Impairment of goodwill |
294,908 |
294,908 |
|||||
Amortization of deferred financing costs |
1,403 |
5,124 |
|||||
Amortization of intangible assets |
408 |
1,632 |
|||||
Gain on derivative instruments(1) |
(89,019) |
(273,748) |
|||||
Net cash receipts on settled derivative instruments(1) |
76,228 |
193,908 |
|||||
Acquisition expense |
1,111 |
1,235 |
|||||
Non-cash stock compensation expense |
4,847 |
16,528 |
|||||
Non-cash incentive unit (income) expense |
(9,773) |
36,097 |
|||||
Income tax (benefit) expense |
(6,217) |
12,118 |
|||||
Gain from sale of interest in gas properties |
— |
(953) |
|||||
Exploration expense |
1,212 |
3,137 |
|||||
Other expense |
756 |
4,380 |
|||||
Non-controlling interest |
(6,504) |
(23,337) |
|||||
Adjusted EBITDAX |
$ |
132,153 |
$ |
431,510 |
1. |
The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDAX on a cash basis during the period the derivatives settled. |
The following table presents a reconciliation of the non-GAAP financial measure of Further Adjusted EBITDAX to Adjusted EBITDAX.
Three Months Ended |
Year Ended | ||||||
(in thousands) |
December 31, 2015 |
December 31, 2015 | |||||
Further Adjusted EBITDAX reconciliation: |
|||||||
Adjusted EBITDAX |
$ |
132,153 |
$ |
431,510 |
|||
Non-controlling interest(1) |
6,504 |
23,337 |
|||||
Water revenue adjustment(2) |
5,577 |
27,336 |
|||||
Further Adjusted EBITDAX |
$ |
144,234 |
$ |
482,183 |
|||
Net Debt(1) |
$ |
988,649 |
|||||
Net Debt / LTM EBITDAX |
2.1 |
||||||
Net Debt / LQA EBITDAX |
1.7 |
1. |
Add back non-controlling interest to Adjusted EBITDAX to calculate leverage metrics. |
2. |
Add back RMP water distribution revenue from RICE's working interest share of the water fees that was eliminated in the Rice consolidation. |
Rice Energy Inc.
Supplemental Non-GAAP Financial Measure
(Unaudited)
Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted net income (loss) as net income (loss) before derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments incentive unit expense and other non-recurring items. Adjusted net income (loss) is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.
We believe that many investors use adjusted net income in making investment decisions and in evaluating our operational trends and our performance relative to other oil and gas producing companies.
The following table presents a reconciliation of the non-GAAP financial measure of adjusted net income (loss) to the GAAP financial measure of net income (loss).
Three Months Ended December 31, 2015 |
Year Ended December 31, 2015 | ||||||
(in thousands) |
|||||||
Reconciliation to net income (loss) attributable to Rice Energy Inc: |
|||||||
Net loss attributable to Rice Energy Inc. |
$ |
(280,757) |
$ |
(291,336) |
|||
Impairment of gas properties, net of tax |
43,792 |
12,675 |
|||||
Impairment of goodwill |
294,908 |
294,908 |
|||||
Gain on derivative instruments, net of tax(1) |
(213,609) |
(190,118) |
|||||
Net cash receipts on settled derivative instruments, net of tax(1) |
182,917 |
134,669 |
|||||
Incentive unit (income) expense |
(9,773) |
36,097 |
|||||
Other expense, net of tax |
1,815 |
3,042 |
|||||
Acquisition expense, net of tax |
2,666 |
858 |
|||||
Adjusted net income (loss) attributable to Rice Energy Inc. |
$ |
21,959 |
$ |
795 |
1. |
The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within adjusted net income on a cash basis during the period the derivatives settled. |
Rice Energy Inc.
Supplemental Non-GAAP Financial Measure
(Unaudited)
PV-10 is a supplemental non-GAAP financial measure and generally differs from standardized measure, the mist directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 reflects the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our natural gas properties.
The following table presents a reconciliation of the non-GAAP financial measure of PV-10 to the standardized measure of discounted future net cash flows:
Year Ended |
Year Ended | ||||||
(in millions) |
|||||||
Reconciliation to PV-10 |
|||||||
Standardized measure of discounted future net cash flows |
$ |
886 |
$ |
1,308 |
|||
Discounted future net cash flows for income taxes |
— |
436 |
|||||
Discounted future net cash flows before income taxes (PV-10) |
$ |
886 |
$ |
1,744 |
Rice Energy Inc. | ||||||||||||||||||||
The table below provides data associated with our derivatives as of February 23, 2016 for the periods indicated: | ||||||||||||||||||||
All-In Fixed Price Derivatives |
2016 |
2017 |
2018 |
2019 |
2020 | |||||||||||||||
NYMEX Natural Gas Swaps: |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
581 |
288 |
5 |
20 |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
3.32 |
$ |
3.27 |
$ |
3.60 |
$ |
3.23 |
$ |
— |
||||||||||
NYMEX Natural Gas Collars: |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
50 |
220 |
280 |
130 |
— |
|||||||||||||||
Weighted Average Floor Price ($/MMBtu) |
$ |
2.91 |
$ |
3.13 |
$ |
3.16 |
$ |
3.09 |
$ |
— |
||||||||||
Weighted Average Collar Price ($/MMBtu) |
$ |
3.60 |
$ |
3.61 |
$ |
3.62 |
$ |
3.60 |
$ |
— |
||||||||||
NYMEX Natural Gas Calls: |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
— |
50 |
70 |
70 |
65 |
|||||||||||||||
Weighted Average Price ($/MMBtu) |
$ |
— |
$ |
3.60 |
$ |
3.50 |
$ |
3.50 |
$ |
3.44 |
||||||||||
NYMEX Natural Deferred Puts: |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
— |
55 |
— |
— |
— |
|||||||||||||||
Weighted Avg. Net Floor Price ($/MMBtu) |
$ |
— |
$ |
2.50 |
$ |
— |
$ |
— |
$ |
— |
||||||||||
NYMEX Volume Excl. Calls (BBtu/d) |
631 |
563 |
285 |
150 |
— |
|||||||||||||||
NYMEX Volume Incl. Calls (BBtu/d) |
631 |
613 |
355 |
220 |
65 |
|||||||||||||||
Swap, Collar & Put Floor ($/MMBtu) |
$ |
3.29 |
$ |
3.14 |
$ |
3.16 |
$ |
3.11 |
$ |
— |
||||||||||
Dominion Natural Gas Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
31 |
— |
— |
— |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
2.62 |
$ |
— |
$ |
— |
$ |
— |
$ |
— |
||||||||||
Total Fixed Price Derivatives |
||||||||||||||||||||
Volume Hedged Excl. Calls (BBtu/d) |
662 |
563 |
285 |
150 |
— |
|||||||||||||||
Volume Hedged Incl. Calls (BBtu/d) |
662 |
613 |
355 |
220 |
65 |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
3.26 |
$ |
3.14 |
$ |
3.16 |
$ |
3.11 |
$ |
— |
||||||||||
Basis Contract Derivatives |
||||||||||||||||||||
TCO Basis Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
44 |
27 |
19 |
10 |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.32) |
$ |
(0.33) |
$ |
(0.40) |
$ |
(0.38) |
$ |
— |
||||||||||
Dominion Basis Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
76 |
98 |
165 |
150 |
68 |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(1.01) |
$ |
(0.89) |
$ |
(0.67) |
$ |
(0.63) |
$ |
(0.64) |
||||||||||
M2 Basis Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
61 |
65 |
— |
— |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(1.03) |
$ |
(1.01) |
$ |
— |
$ |
— |
$ |
— |
||||||||||
MichCon Basis Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
24 |
4 |
4 |
20 |
20 |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.01) |
$ |
(0.04) |
$ |
(0.04) |
$ |
(0.12) |
$ |
(0.12) |
||||||||||
ELA Basis Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
110 |
80 |
40 |
10 |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.10) |
$ |
(0.09) |
$ |
(0.08) |
$ |
(0.10) |
$ |
— |
||||||||||
Chicago Basis Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
40 |
10 |
10 |
— |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.05) |
$ |
(0.16) |
$ |
(0.19) |
$ |
— |
$ |
— |
||||||||||
ANR SE Basis Swaps |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
35 |
— |
— |
— |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.10) |
$ |
— |
$ |
— |
$ |
— |
$ |
— |
||||||||||
Physical Triggered Basis |
||||||||||||||||||||
Appalachian Fixed Basis (Physical) |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
21 |
— |
— |
— |
20 |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.79) |
$ |
— |
$ |
— |
$ |
— |
$ |
(0.65) |
||||||||||
MichCon Fixed Basis (Physical) |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
10 |
10 |
8 |
— |
— |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
0.05 |
$ |
0.05 |
$ |
0.05 |
$ |
— |
$ |
— |
||||||||||
Gulf Coast Fixed Basis (Physical) |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
100 |
100 |
100 |
92 |
42 |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.17) |
$ |
(0.17) |
$ |
(0.17) |
$ |
(0.16) |
$ |
(0.15) |
||||||||||
Total Basis Swaps (Financial + Physical) |
||||||||||||||||||||
Volume Hedged (BBtu/d) |
521 |
394 |
346 |
282 |
150 |
|||||||||||||||
Weighted Average Swap Price ($/MMBtu) |
$ |
(0.39) |
$ |
(0.47) |
$ |
(0.40) |
$ |
(0.41) |
$ |
(0.44) |
The table below provides supplemental balance sheet data as of December 31, 2015. | |||
Supplemental Balance Sheet data (in thousands) |
December 31, 2015 | ||
Cash and cash equivalents |
$ |
151,901 |
|
Long-term debt |
|||
6.25% Senior Notes Due April 2022 |
$ |
900,000 |
|
7.25% Senior Notes Due May 2023 |
397,222 |
||
Senior Secured Revolving Credit Facility |
— |
||
Midstream Holdings Revolving Credit Facility |
17,000 |
||
RMP Revolving Credit Facility |
143,000 |
||
Total long-term debt |
$ |
1,457,222 |
|
Net debt |
$ |
1,305,321 |
The table below outlines our firm transportation capacity by pipeline. | |||||
Project |
Pipeline |
Start Date |
Volume (Dth/d) |
Term |
Market |
TEAM South |
TETCO |
Sept-14 |
270,000 |
38 Yrs |
Gulf Coast |
Westside Expansion |
TCO |
Nov-14 |
125,000 |
10 Yrs |
TCO/Gulf Coast |
Rockies Express Reversal |
REX |
Aug-15 |
175,000 |
20 Yrs |
Midwest/Gulf Coast |
Union Town to Gas City |
TETCO |
Sept-15 |
86,500 |
10 Yrs |
Midwest/Gulf Coast |
OPEN |
TETCO |
Sept-15 |
50,000 |
20 Yrs |
Gulf Coast |
ET Rover |
Rover |
Nov-17 |
100,000 |
15 Yrs |
Canada |
Access South |
TETCO |
Nov-17 |
320,000 |
25 Yrs |
Gulf Coast |
Logo - http://photos.prnewswire.com/prnh/20140123/DA51701LOGO
SOURCE Rice Energy Inc.
May River Oil Sands Project (subscriber access)
Status: (subscriber access)
Parent Entities:
Grizzly Oil Sands ULC
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