Attached files
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| 8-K - 8-K - CABOT OIL & GAS CORP | cog093020168k.htm |
Exhibit 99.1
October 28, 2016 | FOR MORE INFORMATION CONTACT | |
Matt Kerin (281) 589-4642 | ||
Cabot Oil & Gas Corporation Announces Third Quarter 2016 Financial and Operating Results
HOUSTON, October 28, 2016/PRNewswire/ -- Cabot Oil & Gas Corporation (NYSE: COG) (“Cabot” or the “Company”) today reported financial and operating results for the third quarter of 2016. Highlights for the quarter include:
• | Equivalent production growth of six percent relative to the prior-year comparable quarter, driven by a nine percent growth in natural gas production; |
• | Positive free cash flow (cash flow from operating activities less capital expenditures) for the third quarter and year-to-date; |
• | Cash operating expenses per unit improved by 13 percent relative to the prior-year comparable quarter; |
• | Approximately $2.2 billion of liquidity and only $1.0 billion of net debt as of quarter-end |
“The volatility in commodity prices continues to challenge our industry and has driven us to be more efficient,” said Dan O. Dinges, Chairman, President and Chief Executive Officer. “We have been successful at creating a free cash flow positive investment program that still generates growth, while simultaneously driving down our cost structure and our resulting breakeven levels.” Dinges added, “While our impatience with the regulatory pipeline approval process is very real, it has not impacted our focus on prudently managing this business for the long-term as evidenced by our results this quarter.”
Third Quarter 2016 Financial Results
Equivalent production in the third quarter of 2016 was 150.8 billion cubic feet equivalent (Bcfe), consisting of 144.4 billion cubic feet (Bcf) of natural gas, 941.4 thousand barrels (Mbbls) of crude oil and condensate, and 129.6 Mbbls of natural gas liquids (NGLs). The Company estimates that downstream maintenance projects and unscheduled upstream gathering downtime negatively impacted natural gas production for the quarter by approximately 3.2 Bcf, or 35 million cubic feet (Mmcf) per day.
Cash flow from operating activities in the third quarter of 2016 was $105.4 million, compared to $146.4 million in the third quarter of 2015. Discretionary cash flow in the third quarter of 2016 was $128.4 million, compared to $150.4 million in the third quarter of 2015. Net loss in the third quarter of 2016 was $10.3 million, or $0.02 per share, compared to net loss of $15.5 million, or $0.04 per share, in the third quarter of 2015. Excluding the effect of selected items (detailed in the table below), net loss in the third quarter of 2016 was $16.7 million, or $0.04 per share, compared to net loss of $2.2 million, or $0.01 per share, in the third quarter of 2015. EBITDAX in the third quarter of 2016 was $138.8 million, compared to $167.6 million in the third
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quarter of 2015. See the supplemental tables at the end of this press release for a reconciliation of non-GAAP measures including discretionary cash flow, net income (loss) excluding selected items, EBITDAX and net debt to adjusted capitalization ratio.
Natural gas price realizations, including the impact of derivatives, were $1.75 per thousand cubic feet (Mcf) in the third quarter of 2016, down 13 percent compared to the third quarter of 2015. Excluding the impact of derivatives, natural gas price realizations for the quarter implied a $1.01 discount to NYMEX settlement prices compared to a $1.09 discount to NYMEX settlement prices in the third quarter of 2015. Oil price realizations, including the impact of derivatives, were $40.13 per barrel (Bbl), down eight percent compared to the third quarter of 2015. NGL price realizations were $12.64 per Bbl, up 25 percent compared to the third quarter of 2015.
Operating expenses (including financing) decreased to $2.14 per thousand cubic feet equivalent (Mcfe) in the third quarter of 2016, a nine percent improvement compared to $2.35 per Mcfe in the third quarter of 2015. Cash operating expenses (excluding depreciation, depletion and amortization; stock-based compensation; exploratory dry hole cost; and amortization of debt issuance costs) decreased to $1.17 per Mcfe in the third quarter of 2016, a 13 percent improvement compared to $1.34 per Mcfe in the third quarter of 2015.
Cabot drilled 11 net wells and completed 23 net wells during the third quarter of 2016, incurring a total of $99.5 million in capital expenditures associated with activity during this period.
Year-To-Date 2016 Financial Results
Equivalent production for the nine-month period ended September 30, 2016 was 463.0 Bcfe, consisting of 441.8 Bcf of natural gas, 3,190.4 Mbbls of crude oil and condensate, and 334.6 Mbbls of NGLs.
For the nine-month period ended September 30, 2016, cash flow from operating activities was $252.6 million, compared to $585.0 million for the nine-month period ended September 30, 2015. Discretionary cash flow was $297.1 million for the nine-month period ended September 30, 2016, compared to $573.8 million for the nine-month period ended September 30, 2015. For the nine-month period ended September 30, 2016, net loss was $124.4 million, or $0.27 per share, compared to net loss of $2.8 million, or $0.01 per share, for the nine-month period ended September 30, 2015. Excluding the effect of selected items, net loss was $102.3 million, or $0.23 per share, compared to net income of $62.5 million, or $0.15 per share, for the nine-month period ended September 30, 2015. EBITDAX for the nine-month period ended September 30, 2016 was $367.0 million, compared to $651.0 million for the nine-month period ended September 30, 2015.
Natural gas price realizations, including the impact of derivatives, were $1.62 per Mcf for the nine-month period ended September 30, 2016, down 27 percent compared to the nine-month period ended September 30, 2015. Oil price realizations, including the impact of derivatives, were $35.85 per Bbl, down 25 percent compared to the nine-month period ended September 30, 2015. NGL price realizations were $11.08 per Bbl, down 14 percent compared to the nine-month period ended September 30, 2015.
Operating expenses (including financing) decreased to $2.21 per Mcfe for the nine-month period ended September 30, 2016, an eight percent improvement compared to $2.40 per Mcfe for the nine-month period ended September 30, 2015. Cash operating expenses (excluding depreciation, depletion and amortization; stock-based compensation; exploratory dry hole cost; and amortization of debt issuance costs) decreased to $1.18 per Mcfe for the nine-month period ended September 30, 2016, a 10 percent improvement compared to $1.31 per Mcfe in the nine-month period ended September 30, 2015.
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Cabot drilled 28 net wells and completed 55 net wells during the nine-month period ended September 30, 2016, incurring a total of $262.1 million in capital expenditures associated with activity during this period.
Financial Position and Liquidity
As of September 30, 2016, Cabot had total debt of $1.5 billion and cash on hand of $501.2 million. The Company’s net debt to adjusted capitalization ratio and net debt to trailing twelve months EBITDAX ratio were 26.2 percent and 1.9x, respectively, compared to 50.1 percent and 2.5x as of December 31, 2015.
Total commitments under the Company’s revolving credit facility remain unchanged at $1.8 billion, with approximately $1.7 billion currently available to the Company. The Company currently has no debt outstanding under the credit facility, resulting in approximately $2.2 billion of liquidity.
Fourth Quarter and Full-Year 2016 Guidance
Cabot has provided fourth quarter net production guidance of 1,650 to 1,725 Mmcf per day for natural gas; 8,500 to 9,000 Bbls per day for crude oil and condensate; and 1,000 to 1,050 Bbls per day for NGLs.
Based on the fourth quarter production guidance, the Company has adjusted its full-year 2016 equivalent production growth guidance range to 3 to 4 percent. Additionally, Cabot is increasing its 2016 capital budget guidance by $35 million to $380 million. This increase reflects the drilling and completion of an additional 8 net wells during the fourth quarter and the implementation of Cabot’s fourth-generation completion design across its entire Marcellus Shale program beginning in the fourth quarter. "We have seen tremendous success from our fourth-generation completion pilot tests as these wells have significantly outperformed the third-generation wells drilled on the same pad site," highlighted Dinges. "As a result, we plan to utilize this new completion design moving forward given the material uplift in economics we have realized."
Full-Year 2017 Guidance and Preliminary 2018 Outlook
The Company has initiated its 2017 production growth guidance range at 5 to 10 percent. This production growth range is based on an exploration and production (E&P) capital budget of $575 million. In addition, Cabot anticipates approximately $50 million of contributions to its equity method investments in the Atlantic Sunrise and Constitution pipelines, resulting in total 2017 program spending of $625 million. Drilling, completion and facility capital will account for approximately 93 percent of the E&P budget, with approximately 79 percent allocated to the Marcellus Shale and 21 percent allocated to the Eagle Ford Shale. The Company expects to drill approximately 70 net wells (including 55 net wells in the Marcellus Shale and 15 net wells in the Eagle Ford Shale) and complete approximately 75 net wells (including 50 net wells in the Marcellus Shale and 25 net wells in the Eagle Ford Shale). The average lateral length for the 2017 drilling program in the Marcellus Shale is expected to be 8,000 feet and will utilize the fourth-generation completion design, resulting in 53 completed stages per well. The average lateral length for the 2017 drilling program in the Eagle Ford Shale is expected to be 9,000 feet with 36 completed stages per well. Approximately $225 million of the drilling, completion and facility capital is the maintenance capital required to hold Cabot’s anticipated 2016 exit production rate flat throughout 2017, which would result in full-year production growth near the low-end of the production growth guidance range, while allowing the Company to meet all obligatory leasehold commitments. The remainder of the drilling, completion and facility capital will be used to fund incremental growth in 2017 and position the Company for production growth of 15 to 25 percent in 2018. This preliminary outlook for 2018 is predicated on Cabot’s current
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expected in-service dates for its new takeaway capacity, which are referenced in the supplemental materials posted to the Company’s website this morning, including a mid-2018 in-service date for Atlantic Sunrise.
Conference Call Webcast and Supplemental Earnings Materials
A conference call is scheduled for Friday, October 28, 2016, at 9:30 a.m. Eastern Time to discuss third quarter 2016 financial and operating results as well as fourth quarter 2016 and full-year 2017 guidance. A supplemental presentation is also available in the Investor Relations section of the Company's website at www.cabotog.com. To access the live audio webcast, please visit the Investor Relations section of the Company's website. A replay of the call will also be available on the Company's website.
Cabot Oil & Gas Corporation, headquartered in Houston, Texas, is a leading independent natural gas producer with its entire resource base located in the continental United States. For additional information, visit the Company's website at www.cabotog.com.
This press release includes forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict”, “may”, “should”, “could”, “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (SEC) filings. See “Risk Factors” in Item 1A of the Form 10-K and subsequent public filings for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company does not undertake any obligation to correct or update any forward-looking statement, whether as the result of new information, future events or otherwise, except as required by applicable law.
FOR MORE INFORMATION CONTACT
Matt Kerin (281) 589-4642
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OPERATING DATA
Quarter Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
PRODUCTION VOLUMES | |||||||||||||||
Natural gas (Bcf) | 144.4 | 133.0 | 441.8 | 423.2 | |||||||||||
Crude oil and condensate (Mbbl) | 941.4 | 1,350.0 | 3,190.4 | 4,225.5 | |||||||||||
Natural gas liquids (NGLs) (Mbbl) | 129.6 | 162.9 | 334.6 | 493.0 | |||||||||||
Equivalent production (Bcfe) | 150.8 | 142.1 | 463.0 | 451.5 | |||||||||||
AVERAGE SALES PRICE | |||||||||||||||
Natural gas, including hedges ($/Mcf) | $ | 1.75 | $ | 2.02 | $ | 1.62 | $ | 2.23 | |||||||
Natural gas, excluding hedges ($/Mcf) | $ | 1.80 | $ | 1.68 | $ | 1.61 | $ | 1.91 | |||||||
Crude oil and condensate, including hedges ($/Bbl) | $ | 40.13 | $ | 43.71 | $ | 35.85 | $ | 48.00 | |||||||
Crude oil and condensate, excluding hedges ($/Bbl) | $ | 40.13 | $ | 43.71 | $ | 35.92 | $ | 48.00 | |||||||
NGL ($/Bbl) | $ | 12.64 | $ | 10.11 | $ | 11.08 | $ | 12.87 | |||||||
AVERAGE UNIT COSTS ($/Mcfe) | |||||||||||||||
Direct operations | $ | 0.16 | $ | 0.25 | $ | 0.17 | $ | 0.24 | |||||||
Transportation and gathering | 0.70 | 0.72 | 0.70 | 0.71 | |||||||||||
Taxes other than income | 0.06 | 0.08 | 0.05 | 0.08 | |||||||||||
Exploration | 0.02 | 0.03 | 0.03 | 0.04 | |||||||||||
Depreciation, depletion and amortization | 0.92 | 1.02 | 0.97 | 1.05 | |||||||||||
General and administrative (excluding stock-based compensation) | 0.10 | 0.10 | 0.10 | 0.09 | |||||||||||
Stock-based compensation | 0.03 | (0.02 | ) | 0.05 | 0.03 | ||||||||||
Interest expense | 0.14 | 0.17 | 0.15 | 0.16 | |||||||||||
$ | 2.14 | $ | 2.35 | $ | 2.21 | $ | 2.40 | ||||||||
WELLS DRILLED | |||||||||||||||
Gross | 11 | 27 | 28 | 114 | |||||||||||
Net | 11 | 27 | 28 | 105 | |||||||||||
Gross success rate | 100 | % | 100 | % | 100 | % | 100 | % | |||||||
WELLS COMPLETED | |||||||||||||||
Gross | 23 | 21 | 55 | 96 | |||||||||||
Net | 23 | 18 | 55 | 90 | |||||||||||
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CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
Quarter Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
OPERATING REVENUES | |||||||||||||||
Natural gas | $ | 260,200 | $ | 222,963 | $ | 711,010 | $ | 807,960 | |||||||
Crude oil and condensate | 37,777 | 59,014 | 114,610 | 202,804 | |||||||||||
Gain (loss) on derivative instruments | 6,904 | 17,364 | (1,286 | ) | 44,668 | ||||||||||
Brokered natural gas | 3,641 | 4,010 | 9,417 | 12,650 | |||||||||||
Other | 1,907 | 1,945 | 5,435 | 8,277 | |||||||||||
310,429 | 305,296 | 839,186 | 1,076,359 | ||||||||||||
OPERATING EXPENSES | |||||||||||||||
Direct operations | 24,626 | 34,818 | 77,139 | 106,947 | |||||||||||
Transportation and gathering | 105,671 | 102,121 | 322,883 | 321,652 | |||||||||||
Brokered natural gas | 2,939 | 3,020 | 7,526 | 9,643 | |||||||||||
Taxes other than income | 8,771 | 11,407 | 23,737 | 34,298 | |||||||||||
Exploration | 2,988 | 4,930 | 13,109 | 18,960 | |||||||||||
Depreciation, depletion and amortization | 139,490 | 144,326 | 448,910 | 472,335 | |||||||||||
General and administrative (excluding stock-based compensation) | 14,667 | 14,015 | 45,383 | 41,989 | |||||||||||
Stock-based compensation(1) | 5,109 | (2,913 | ) | 23,016 | 11,622 | ||||||||||
304,261 | 311,724 | 961,703 | 1,017,446 | ||||||||||||
Earnings (loss) on equity method investments | (1,727 | ) | 1,648 | 208 | 4,581 | ||||||||||
Gain (loss) on sale of assets | (1,245 | ) | 3,756 | (768 | ) | 3,814 | |||||||||
INCOME (LOSS) FROM OPERATIONS | 3,196 | (1,024 | ) | (123,077 | ) | 67,308 | |||||||||
Loss on debt extinguishment | — | — | 4,709 | — | |||||||||||
Interest expense | 21,483 | 24,510 | 67,821 | 72,244 | |||||||||||
Income (loss) before income taxes | (18,287 | ) | (25,534 | ) | (195,607 | ) | (4,936 | ) | |||||||
Income tax expense (benefit) | (8,027 | ) | (10,020 | ) | (71,243 | ) | (2,169 | ) | |||||||
NET INCOME (LOSS) | $ | (10,260 | ) | $ | (15,514 | ) | $ | (124,364 | ) | $ | (2,767 | ) | |||
Earnings (loss) per share - Basic | $ | (0.02 | ) | $ | (0.04 | ) | $ | (0.27 | ) | $ | (0.01 | ) | |||
Weighted-average common shares outstanding | 465,149 | 413,846 | 454,060 | 413,636 | |||||||||||
(1) Includes the impact of the Company’s performance share awards, restricted stock, stock appreciation rights and expense associated with the Supplemental Employee Incentive Plan.
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CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In thousands)
September 30, 2016 | December 31, 2015 | ||||||
ASSETS | |||||||
Current assets | $ | 655,645 | $ | 144,786 | |||
Properties and equipment, net (Successful efforts method) | 4,722,598 | 4,976,879 | |||||
Other assets | 153,678 | 131,373 | |||||
$ | 5,531,921 | $ | 5,253,038 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current liabilities | $ | 196,763 | $ | 235,552 | |||
Long-term debt, net (excluding current maturities) | 1,520,190 | 1,996,139 | |||||
Deferred income taxes | 749,976 | 807,236 | |||||
Other liabilities | 201,742 | 204,923 | |||||
Stockholders' equity | 2,863,250 | 2,009,188 | |||||
$ | 5,531,921 | $ | 5,253,038 | ||||
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In thousands)
Quarter Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||
Net income (loss) | $ | (10,260 | ) | $ | (15,514 | ) | $ | (124,364 | ) | $ | (2,767 | ) | |||
Deferred income tax expense (benefit) | 4,880 | 1,066 | (59,413 | ) | 8,226 | ||||||||||
(Gain) loss on sale of assets | 1,245 | (3,756 | ) | 768 | (3,814 | ) | |||||||||
Exploratory dry hole cost | — | 6 | 18 | 184 | |||||||||||
(Gain) loss on derivative instruments | (6,904 | ) | (17,364 | ) | 1,286 | (44,668 | ) | ||||||||
Net cash received (paid) in settlement of derivative instruments | (8,101 | ) | 45,097 | 3,204 | 133,827 | ||||||||||
Income charges not requiring cash | 147,502 | 140,823 | 475,641 | 482,771 | |||||||||||
Changes in assets and liabilities | (22,957 | ) | (3,996 | ) | (44,491 | ) | 11,195 | ||||||||
Net cash provided by operating activities | 105,405 | 146,362 | 252,649 | 584,954 | |||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||||||
Capital expenditures | (85,634 | ) | (174,747 | ) | (245,033 | ) | (819,839 | ) | |||||||
Acquisitions | — | (12 | ) | — | (16,312 | ) | |||||||||
Proceeds from sale of assets | (760 | ) | 4,378 | 49,068 | 7,380 | ||||||||||
Investment in equity method investments | (6,005 | ) | (10,684 | ) | (24,176 | ) | (20,798 | ) | |||||||
Net cash used in investing activities | (92,399 | ) | (181,065 | ) | (220,141 | ) | (849,569 | ) | |||||||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||||||
Net borrowings (repayments) of debt | (20,000 | ) | 42,000 | (497,000 | ) | 285,000 | |||||||||
Sale of common stock, net | — | — | 995,279 | — | |||||||||||
Dividends paid | (9,303 | ) | (8,275 | ) | (26,885 | ) | (24,812 | ) | |||||||
Stock-based compensation tax benefit | — | (5,486 | ) | — | — | ||||||||||
Capitalized debt issuance costs | — | — | (3,223 | ) | (7,838 | ) | |||||||||
Other | — | 5 | — | 84 | |||||||||||
Net cash provided by (used in) financing activities | (29,303 | ) | 28,244 | 468,171 | 252,434 | ||||||||||
Net increase (decrease) in cash and cash equivalents | $ | (16,297 | ) | $ | (6,459 | ) | $ | 500,679 | $ | (12,181 | ) | ||||
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Selected Item Review and Reconciliation of Net Income and Earnings Per Share
(In thousands, except per share amounts)
Quarter Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
As reported - net income (loss) | $ | (10,260 | ) | $ | (15,514 | ) | $ | (124,364 | ) | $ | (2,767 | ) | |||
Reversal of selected items: | |||||||||||||||
(Gain) loss on sale of assets | 1,245 | (3,756 | ) | 768 | (3,814 | ) | |||||||||
(Gain) loss on derivative instruments (1) | (15,005 | ) | 27,733 | 4,490 | 89,159 | ||||||||||
Loss on debt extinguishment | — | — | 4,709 | — | |||||||||||
Drilling rig termination fees | (1,532 | ) | — | 1,655 | 5,095 | ||||||||||
Stock-based compensation expense | 5,109 | (2,913 | ) | 23,016 | 11,622 | ||||||||||
Tax effect on selected items | 3,696 | (7,725 | ) | (12,572 | ) | (36,841 | ) | ||||||||
Net income (loss) excluding selected items | $ | (16,747 | ) | $ | (2,175 | ) | $ | (102,298 | ) | $ | 62,454 | ||||
As reported - earnings (loss) per share | $ | (0.02 | ) | $ | (0.04 | ) | $ | (0.27 | ) | $ | (0.01 | ) | |||
Per share impact of selected items | (0.02 | ) | 0.03 | 0.04 | 0.16 | ||||||||||
Earnings (loss) per share excluding selected items | $ | (0.04 | ) | $ | (0.01 | ) | $ | (0.23 | ) | $ | 0.15 | ||||
Weighted-average common shares outstanding | 465,149 | 413,846 | 454,060 | 413,636 | |||||||||||
(1) This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.
Discretionary Cash Flow Calculation and Reconciliation
(In thousands)
Quarter Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Net income (loss) | $ | (10,260 | ) | $ | (15,514 | ) | $ | (124,364 | ) | $ | (2,767 | ) | |||
Plus (less): | |||||||||||||||
Deferred income tax expense (benefit) | 4,880 | 1,066 | (59,413 | ) | 8,226 | ||||||||||
(Gain) loss on sale of assets | 1,245 | (3,756 | ) | 768 | (3,814 | ) | |||||||||
Exploratory dry hole cost | — | 6 | 18 | 184 | |||||||||||
(Gain) loss on derivative instruments | (6,904 | ) | (17,364 | ) | 1,286 | (44,668 | ) | ||||||||
Net cash received (paid) in settlement of derivative instruments | (8,101 | ) | 45,097 | 3,204 | 133,827 | ||||||||||
Income charges not requiring cash | 147,502 | 140,823 | 475,641 | 482,771 | |||||||||||
Discretionary cash flow | 128,362 | 150,358 | 297,140 | 573,759 | |||||||||||
Changes in assets and liabilities | (22,957 | ) | (3,996 | ) | (44,491 | ) | 11,195 | ||||||||
Net cash provided by operating activities | $ | 105,405 | $ | 146,362 | $ | 252,649 | $ | 584,954 | |||||||
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EBITDAX Calculation and Reconciliation
(In thousands)
Quarter Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Net income (loss) | $ | (10,260 | ) | $ | (15,514 | ) | $ | (124,364 | ) | $ | (2,767 | ) | |||
Plus (less): | |||||||||||||||
Loss on debt extinguishment | — | — | 4,709 | — | |||||||||||
Interest expense | 21,483 | 24,510 | 67,821 | 72,244 | |||||||||||
Income tax expense (benefit) | (8,027 | ) | (10,020 | ) | (71,243 | ) | (2,169 | ) | |||||||
Depreciation, depletion and amortization | 139,490 | 144,326 | 448,910 | 472,335 | |||||||||||
Exploration | 2,988 | 4,930 | 13,109 | 18,960 | |||||||||||
(Gain) loss on sale of assets | 1,245 | (3,756 | ) | 768 | (3,814 | ) | |||||||||
Non-cash (gain) loss on derivative instruments | (15,005 | ) | 27,733 | 4,490 | 89,159 | ||||||||||
(Earnings) loss on equity method investments | 1,727 | (1,648 | ) | (208 | ) | (4,581 | ) | ||||||||
Stock-based compensation | 5,109 | (2,913 | ) | 23,016 | 11,622 | ||||||||||
EBITDAX | $ | 138,750 | $ | 167,648 | $ | 367,008 | $ | 650,989 | |||||||
Net Debt Reconciliation
(In thousands)
September 30, 2016 | December 31, 2015 | ||||||
Current portion of long-term debt | $ | — | $ | 20,000 | |||
Long-term debt, net | 1,520,190 | 1,996,139 | |||||
Total debt | $ | 1,520,190 | $ | 2,016,139 | |||
Stockholders’ equity | 2,863,250 | 2,009,188 | |||||
Total capitalization | $ | 4,383,440 | $ | 4,025,327 | |||
Total debt | $ | 1,520,190 | $ | 2,016,139 | |||
Less: Cash and cash equivalents | (501,193 | ) | (514 | ) | |||
Net debt | $ | 1,018,997 | $ | 2,015,625 | |||
Net debt | $ | 1,018,997 | $ | 2,015,625 | |||
Stockholders’ equity | 2,863,250 | 2,009,188 | |||||
Total adjusted capitalization | $ | 3,882,247 | $ | 4,024,813 | |||
Total debt to total capitalization ratio | 34.7 | % | 50.1 | % | |||
Less: Impact of cash and cash equivalents | 8.5 | % | — | % | |||
Net debt to adjusted capitalization ratio | 26.2 | % | 50.1 | % | |||
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