8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report (date of earliest event reported): February 24, 2017

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	1-10447	04-3072771
(State or other jurisdiction	(Commission File Number)	(I.R.S. Employer
of incorporation)		Identification No.)

Three Memorial City Plaza
840 Gessner Road, Suite 1400
Houston, Texas	77024
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:  (281) 589-4600

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)

Item 2.02 Results of Operations and Financial Condition.

On February 24, 2017, we issued a press release with respect to our 2016 fourth quarter and full year earnings. The press release is furnished as Exhibit 99.1 to this Current Report. The press release contains certain measures (discussed below) which may be deemed “non-GAAP financial measures” as defined in Item 10 of Regulation S-K of the Securities Exchange Act of 1934, as amended. In each case, the most directly comparable GAAP financial measure and information reconciling the GAAP and non-GAAP measures is also included in the press release.

Exhibit 99.1 shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

From time to time management discloses Discretionary Cash Flow, EBITDAX, Net Income Excluding Selected Items, Earnings per Share Excluding Selected Items, Net Debt calculations and ratios and Pre-tax Present Value of Future Net Cash Flows, discounted at 10% annual rate. These non-GAAP financial measures, to the extent included in Exhibit 99.1, are reconciled to the most comparable GAAP financial measures in Exhibit 99.1.

Discretionary Cash Flow is defined as net income plus non-cash charges and exploratory dry hole cost. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionary Cash Flow is presented based on management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income.

EBITDAX is defined as net income plus interest expense, income taxes expense, depreciation, depletion and amortization (including property impairments), exploration expense, gains and losses resulting from the sale of assets, non-cash gains and losses on derivative instruments, and stock-based compensation expense and other. EBITDAX is presented based on management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. EBITDAX is not a measure of financial performance under GAAP and should not be considered as alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

Net Income Excluding Selected Items and Earnings per Share Excluding Selected Items are presented based on management’s belief that these non-GAAP measures enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a beneficial comparison to similarly adjusted measurements of prior periods. Net Income and Earnings per Share Excluding Selected Items is not a measure of financial performance under GAAP and should not be considered as an alternative to net income and earnings per share, as defined by GAAP.

The total debt to total capitalization ratio is calculated by dividing total debt by the sum of total debt and total stockholders’ equity.  This ratio is a measurement which is presented in our annual and interim filings and management believes this ratio is useful to investors in determining the Company’s leverage. Net Debt and the Net Debt to Total Capitalization ratio are non-GAAP measures which have been presented in Exhibit 99.1. Net Debt is calculated by subtracting cash and cash equivalents from total debt. Management believes that these measurements are also useful to investors since the Company has the ability to and may decide to use a portion of its cash and cash equivalents to retire debt. Additionally, as the Company may incur additional expenditures without increasing debt, it is appropriate to apply cash and cash equivalents to debt in calculating the Net Debt to Total Capitalization ratio.

Pre-tax Present Value of Future Net Cash Flows, discounted at 10% annual rate is defined as Standardized Measure of Discounted Future Net Cash Flows plus Future Income Tax Expenses, discounted at 10% annual rate. Year-end pre-tax PV-10 value is presented based on management’s belief this non-GAAP measure is useful information to investors and creditors when comparing pre-tax PV-10 values as a basis for comparison of our relative size and value of reserves as compared with other companies. Pre-tax Present Value of Future Net Cash Flows, discounted at 10% annual rate is not a measure under GAAP and should not be considered as alternative to Standardized Measure of Discounted Future Net Cash Flows, as defined by GAAP.

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Item 9.01 Financial Statements and Exhibits.

(d) Exhibits 

99.1 Press release issued by Cabot Oil & Gas Corporation dated February 24, 2017

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. 

		CABOT OIL & GAS CORPORATION
		By:	/S/ TODD M. ROEMER
			Todd M. Roemer
			Vice President and Controller
Date:	February 24, 2017

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EXHIBIT INDEX

99.1        —            Press release issued by Cabot Oil & Gas Corporation dated February 24, 2017

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EX-99.1

Exhibit 99.1

February 24, 2017	FOR MORE INFORMATION CONTACT
	Matt Kerin (281) 589-4642

Cabot Oil & Gas Corporation Announces Fourth Quarter and Full-Year 2016 Results,

Reports Five Percent Proved Reserves Growth to 8.6 Tcfe, Provides Marcellus EUR Update

HOUSTON, February 24, 2017/PRNewswire/ -- Cabot Oil & Gas Corporation (NYSE: COG) (“Cabot” or the “Company”) today reported financial and operating results for the fourth quarter and full-year ended December 31, 2016.

Highlights

• Equivalent production growth of four percent year-over-year

• Proved reserves growth of five percent year-over-year including proved developed reserves growth of 16 percent

• Total company all-sources finding and development costs of $0.37 per thousand cubic feet equivalent (Mcfe) and Marcellus-only all-sources finding and development costs of $0.26 per thousand cubic feet (Mcf)

• Generated positive free cash flow (cash flow from operating activities less capital expenditures) for the full-year

• Improved operating expenses per unit by eight percent and cash operating expenses per unit by 11 percent year-over-year

• Reduced outstanding debt by $497 million and ended the year with approximately $2.2 billion of liquidity

• Increased Marcellus estimated ultimate recovery (EUR) per 1,000 feet of lateral to 4.4 billion cubic feet (Bcf)

“Our 2016 performance demonstrates Cabot’s ability to deliver strong operational and financial results despite lower commodity prices for the majority of the year,” said Dan O. Dinges, Chairman, President and Chief Executive Officer. “The Company delivered production and reserves growth while spending within operating cash flow during a year in which we realized record-low natural gas prices, highlighting Cabot’s world-class asset base and the consistent execution

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by our employees.” Dinges added, “Based on our current outlook for 2017, we anticipate another year of production and reserves growth while generating positive free cash flow.”

Full-Year 2016 Financial Results

Equivalent production was 627.1 billion cubic feet equivalent (Bcfe) in 2016, consisting of 600.4 Bcf of natural gas, 4,013.1 thousand barrels (Mbbls) of crude oil and condensate, and 441.2 Mbbls of natural gas liquids (NGLs).

Cash flow from operations was $392.4 million in 2016, compared to $740.7 million in 2015. Discretionary cash flow in 2016 was $460.7 million, compared to $699.1 million in 2015. Net loss in 2016 was $417.1 million, or $0.91 per share, compared to net loss of $113.9 million, or $0.28 per share, in 2015. Net loss for the year included the impact of a non-cash, after-tax impairment charge of $274.7 million associated with our oil and gas properties and related pipeline assets in West Virginia and Virginia. Excluding the effect of this impairment and other selected items (detailed in the table below), net loss was $97.4 million, or $0.21 per share, in 2016, compared to net income of $55.4 million, or $0.13 per share, in 2015. EBITDAX in 2016 was $554.4 million, compared to $815.2 million in 2015. Significant reductions in realized prices for both natural gas and oil were the primary drivers for the lower results during the year, partially offset by higher equivalent production and lower overall expenses. 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 $1.70 per Mcf in 2016, down 21 percent compared to 2015. Excluding the impact of derivatives, natural gas price realizations for 2016 implied a $0.76 discount to NYMEX settlement prices. Oil price realizations, including the impact of derivatives, were $37.30 per barrel (Bbl), down 18 percent compared to 2015. NGL price realizations were $11.74 per Bbl, down seven percent compared to 2015.

Operating expenses (including financing) decreased to $2.17 per Mcfe in 2016, an improvement of eight percent from $2.37 per Mcfe in 2015. Cash operating expenses (excluding depreciation, depletion and amortization; stock-based compensation; exploratory dry hole cost; and amortization of debt issuance costs) decreased to $1.16 per Mcfe in 2016, an 11 percent improvement over 2015.

Cabot drilled 40 gross (38.0 net) wells and completed 76 gross (76.0 net) wells in 2016 and exited the year with 51 gross (45.2 net) drilled and uncompleted wells, of which 29 gross (26.2 net) were in the Marcellus Shale and 22 gross (19.0 net) were in the Eagle Ford Shale.

Fourth Quarter 2016 Financial Results

Equivalent production in the fourth quarter of 2016 was 164.2 Bcfe, consisting of 158.6 Bcf of natural gas, 822.7 Mbbls of crude oil and condensate, and 106.5 Mbbls of NGLs. Equivalent production increased nine percent sequentially compared to the third quarter of 2016 and was in line with the high-end of the Company’s guidance range for the quarter.

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Cash flow from operations in the fourth quarter of 2016 was $139.7 million, compared to $155.8 million in the fourth quarter of 2015. Discretionary cash flow in the fourth quarter of 2016 was $163.6 million, compared to $125.3 million in the fourth quarter of 2015. Net loss in the fourth quarter of 2016 was $292.8 million, or $0.63 per share, compared to a net loss of $111.1 million, or $0.27 per share, in the fourth quarter of 2015. Excluding the effect of the impairment and other selected items (detailed in the table below), net income was $5.1 million, or $0.01 per share, compared to net loss of $6.4 million, or $0.02 per share, for the fourth quarter of 2015. EBITDAX for the fourth quarter of 2016 was $187.4 million, compared to $164.2 million for the fourth quarter of 2015.

Natural gas price realizations, including the impact of derivatives, were $1.94 per Mcf both in the fourth quarter of 2016 and the fourth quarter of 2015. Excluding the impact of derivatives, natural gas price realizations for the quarter were $1.96 per Mcf, representing a $1.02 discount to NYMEX settlement prices. Oil price realizations, including the impact of derivatives, were $42.94 per Bbl, up 14 percent compared to the fourth quarter of 2015. NGL price realizations were $13.84 per Bbl, up 18 percent compared to the fourth quarter of 2015. “Fourth quarter natural gas and crude oil price realizations excluding the impact of derivatives posted a sequential increase of 9 percent and 11 percent, respectively, when compared to the third quarter, highlighting the improving commodity price backdrop,” commented Dinges.

Operating expenses (including financing) decreased to $2.05 per Mcfe in the fourth quarter of 2016, an 11 percent improvement compared to $2.30 per Mcfe in the fourth 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 $1.11 per Mcfe in the fourth quarter of 2016, a 12 percent improvement over the fourth quarter of 2015.

Cabot drilled 12 gross (10.0 net) wells and completed 25 gross (25.0 net) wells in the fourth quarter of 2016.

Year-End 2016 Financial Position and Liquidity

As of December 31, 2016, Cabot had total debt of $1.5 billion and cash on hand of $498.5 million. The Company's net debt to adjusted capitalization ratio and net debt to trailing twelve months EBITDAX ratio were 28.5 percent and 1.8x, respectively, compared to 50.1 percent and 2.5x as of December 31, 2015.

Total commitments under the Company’s 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.

Year-End 2016 Proved Reserves

Cabot reported year-end proved reserves of 8.6 trillion cubic feet equivalent (Tcfe), an increase of five percent over year-end 2015. Specific highlights from the Company’s year-end reserve report include:

• Total company all-sources finding and development costs of $0.37 per Mcfe

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• Marcellus-only all-sources finding and development costs of $0.26 per Mcf

• Total company all-sources reserve replacement of 168 percent

• Marcellus-only all-sources reserve replacement of 183 percent

“Despite our lowest level of capital spending since 2004, Cabot grew proved reserves and proved developed reserves by five percent and 16 percent, respectively, at record-low finding and development costs,” explained Dinges. “We expect a return to double-digit reserve growth in 2017 as the Company increases its capital spending in anticipation of new takeaway capacity out of the Marcellus Shale.”

The table below reconciles the components driving the 2016 reserve increase:

Proved Reserves Reconciliation (in Bcfe)
Balance at December 31, 2015	8,190
Revisions of prior estimates	370
Extensions, discoveries and other additions	684
Sales	(41	)
Production	(627	)
Balance at December 31, 2016	8,576

As of December 31, 2016, 97 percent of Cabot’s year-end proved reserves were natural gas and 93 percent were located in the Marcellus Shale. Approximately 66 percent of the year-end proved reserves were classified as proved developed and 34 percent were classified as proved undeveloped (PUD), including six percent of drilled and uncompleted PUDs.

Total costs incurred during 2016 were $389.8 million, which included $359.5 million for development costs, $27.6 million for exploration costs, and $2.7 million for unproved property acquisition costs.

The SEC prices used for reporting Cabot's year-end 2016 proved reserves, which have been adjusted for basis and quality differentials, were $1.74 per Mcf for natural gas and $37.54 per Bbl for crude oil, representing a 4 percent and 20 percent year-over-year decrease, respectively. Assuming the SEC prices, the pre-tax present value of future net cash flows discounted at 10% ("pre-tax PV-10") of the year-end 2016 proved reserves was $2.6 billion. Assuming future strip benchmark pricing as of December 31, 2016 for the first five years and held flat thereafter, adjusted for basis and quality differentials, the pre-tax PV-10 value was $5.2 billion, representing a 100 percent increase over the corresponding SEC pre-tax PV-10.

Marcellus Shale Estimated Ultimate Recovery (EUR) Update

Based on Cabot’s year-end reserve bookings for 21 producing Lower Marcellus wells that were completed with the Company’s fourth generation completion design, Cabot has increased its guidance for Lower Marcellus EUR per 1,000 feet of lateral from 3.8 Bcf to 4.4 Bcf. “The EURs for our fourth generation wells further highlight the peer-leading productivity from our Marcellus assets in the core of the dry gas window in Northeast Pennsylvania,” stated Dinges.

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“Based on our current well design and current commodity prices, we believe our project-level economics in the Marcellus are unrivaled across North American resource plays; however, we continue to test new initiatives to further enhance our economics.”

2017 Derivative Position Update

For 2017, the Company has 51.7 Bcf of natural gas swaps at a weighted-average price of $3.23 per Mcf and 35.5 Bcf of natural gas collars at a weighted-average floor and ceiling price of $3.09 per Mcf and $3.43 per Mcf, respectively. Additionally, Cabot currently has 36 percent of its 2017 natural gas volumes under fixed-price physical contracts at a weighted-average price of $2.29 per Mcf.

The Company also has 1,825 Mbbls of crude oil collars at a weighted-average floor and ceiling price of $50.00 per Bbl and $56.39 per Bbl, respectively.

First Quarter and Full-Year 2017 Guidance Update

Cabot has provided first quarter 2017 net production guidance of 1,780 to 1,820 million cubic feet (Mmcf) per day for natural gas; 10,000 to 10,500 Bbls per day for crude oil and condensate; and 1,200 to 1,250 Bbls per day for NGLs.

The Company has reiterated its 2017 production growth guidance range of 5 to 10 percent and initiated crude oil production growth guidance of 15 percent, which represents a substantial increase from the zero percent oil growth contained in the preliminary 2017 budget issued in October 2016. Based on the expectation for higher operating cash flow due to an improvement in the commodity price outlook, the Company is increasing its exploration and production (E&P) capital budget from $575 million to $650 million. This incremental capital will fund additional drilling and completion activity, primarily in the Eagle Ford. “Cabot has seen a significant improvement in project-level returns in our Eagle Ford asset due to increased productivity from enhanced completions, continued cost reductions, and higher crude oil prices,” said Dinges. “Accordingly, we plan to allocate additional capital to this asset to grow exit-to-exit crude oil volumes by 50 percent in 2017.” Dinges added, “Even with this modest increase in capital for 2017, we are forecasting approximately $250 million of positive free cash flow for the year based on recent strip prices.”

Drilling, completion and facility capital will account for approximately 94 percent of the E&P budget, with approximately 67 percent allocated to the Marcellus Shale and 33 percent allocated to the Eagle Ford Shale. The Company expects to drill an additional 20 net wells (15 in the Eagle Ford and 5 in the Marcellus) for total of 90 net wells drilled in 2017. The Company plans to complete an additional 15 net wells (14 in the Eagle Ford and 1 in the Marcellus) for a total of 90 net wells completed in 2017. In addition, Cabot anticipates approximately $70 million of contributions to its equity pipeline investments resulting in total 2017 program spending of $720 million. The capital associated with the equity pipeline investments assumes a more favorable outlook on the construction timing for Atlantic Sunrise and assumes minimal capital for Constitution Pipeline in 2017; however, the amount of pipeline investments will ultimately be dependent on the regulatory approval processes and the corresponding impact on the timing of construction activities.

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For further disclosure on Cabot's natural gas pricing exposure by index and updated cost guidance, please see the current Guidance slide in the Investor Relations section of the Company's website.

Conference Call Webcast and Supplemental Earnings Materials

A conference call is scheduled for Friday, February 24, 2017, at 9:30 a.m. Eastern Time to discuss fourth quarter and full-year 2016 financial and operating results. 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 December 31,				Twelve Months Ended December 31,
	2016		2015		2016		2015
PRODUCTION VOLUMES
Natural gas (Bcf)	158.6		142.8		600.4		566.0
Crude oil and condensate (Mbbl)	822.7		1,203.2		4,013.1		5,428.7
Natural gas liquids (NGLs) (Mbbl)	106.5		174.7		441.2		667.7
Equivalent production (Bcfe)	164.2		151.0		627.1		602.5
AVERAGE SALES PRICE
Natural gas, including hedges ($/Mcf)	$	1.94	$	1.94	$	1.70	$	2.15
Natural gas, excluding hedges ($/Mcf)	$	1.96	$	1.52	$	1.70	$	1.81
Crude oil and condensate, including hedges ($/Bbl)	$	42.94	$	37.74	$	37.30	$	45.72
Crude oil and condensate, excluding hedges ($/Bbl)	$	44.36	$	37.74	$	37.65	$	45.72
NGL ($/Bbl)	$	13.84	$	11.69	$	11.74	$	12.56
AVERAGE UNIT COSTS ($/Mcfe)
Direct operations	$	0.14	$	0.22	$	0.16	$	0.23
Transportation and gathering	0.69		0.70		0.70		0.71
Taxes other than income	0.03		0.06		0.05		0.07
Exploration	0.09		0.06		0.04		0.05
Depreciation, depletion and amortization	0.86		0.99		0.94		1.03
General and administrative (excluding stock-based compensation)	0.10		0.10		0.10		0.10
Stock-based compensation	0.02		0.01		0.04		0.02
Interest expense	0.12		0.16		0.14		0.16
	$	2.05	$	2.30	$	2.17	$	2.37
WELLS DRILLED(1)
Gross	12		26		40		138
Net	10.0		25.2		38.0		130.5
WELLS COMPLETED(1)
Gross	25		17		76		107
Net	25.0		13.3		76.0		98.9

(1)     Wells drilled represents wells drilled to total depth during the period. Wells completed includes wells completed during the period, regardless of when they were drilled.

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CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

	Quarter Ended December 31,						Twelve Months Ended December 31,
(In thousands, except per share amounts)	2016			2015			2016			2015
OPERATING REVENUES
Natural gas	$	311,580		$	217,084		$	1,022,590		$	1,025,044
Crude oil and condensate	36,496			45,407			151,106			248,211
Gain (loss) on derivative instruments	(37,664		)	12,018			(38,950		)	56,686
Brokered natural gas	4,152			3,733			13,569			16,383
Other	1,927			2,550			7,362			10,826
	316,491			280,792			1,155,677			1,357,150
OPERATING EXPENSES
Direct operations	23,557			33,867			100,696			140,814
Transportation and gathering	113,659			105,936			436,542			427,588
Brokered natural gas	3,259			2,949			10,785			12,592
Taxes other than income	5,486			8,511			29,223			42,809
Exploration	14,553			8,500			27,662			27,460
Depreciation, depletion and amortization	141,218			149,876			590,128			622,211
Impairment of oil and gas properties and other assets(1)	435,619			114,875			435,619			114,875
General and administrative (excluding stock-based compensation)	15,891			13,777			61,274			55,764
Stock-based compensation(2)	2,952			2,058			25,968			13,680
	756,194			440,349			1,717,897			1,457,793
Earnings (loss) on equity method investments	(2,685		)	1,834			(2,477		)	6,415
Gain (loss) on sale of assets	(1,089		)	52			(1,857		)	3,866
LOSS FROM OPERATIONS	(443,477		)	(157,671		)	(566,554		)	(90,362		)
Loss on debt extinguishment	—			—			4,709			—
Interest expense	20,515			24,666			88,336			96,911
Loss before income taxes	(463,992		)	(182,337		)	(659,599		)	(187,273		)
Income tax benefit	(171,232		)	(71,213		)	(242,475		)	(73,382		)
NET LOSS	$	(292,760	)	$	(111,124	)	$	(417,124	)	$	(113,891	)
Loss per share - Basic	$	(0.63	)	$	(0.27	)	$	(0.91	)	$	(0.28	)
Weighted-average common shares outstanding	465,150			413,875			456,847			413,696

(1) Includes the impairment of oil and gas properties and the related pipeline assets in West Virginia and Virginia in the fourth quarter of 2016. Also includes the impairment of oil and gas properties in the fourth quarter of 2015 in south Texas, east Texas and Louisiana.

(2) 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)	December 31, 2016		December 31, 2015
ASSETS
Current assets	$	715,881	$	144,786
Properties and equipment, net (Successful efforts method)	4,250,125		4,976,879
Other assets	156,563		131,373
	$	5,122,569	$	5,253,038
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities	$	257,812	$	235,552
Long-term debt, net (excluding current maturities)	1,520,530		1,996,139
Deferred income taxes	579,447		807,236
Other liabilities	197,113		204,923
Stockholders’ equity	2,567,667		2,009,188
	$	5,122,569	$	5,253,038

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CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

	Quarter Ended December 31,						Twelve Months Ended December 31,
(In thousands)	2016			2015			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(292,760	)	$	(111,124	)	$	(417,124	)	$	(113,891	)
Deferred income tax benefit	(171,294		)	(81,194		)	(230,707		)	(72,968		)
Impairment of oil and gas properties and other assets	435,619			114,875			435,619			114,875
(Gain) loss on sale of assets	1,089			(52		)	1,857			(3,866		)
Exploratory dry hole cost	10,102			3,268			10,120			3,452
(Gain) loss on derivative instruments	37,664			(12,018		)	38,950			(56,686		)
Net cash received (paid) in settlement of derivative instruments	(4,886		)	60,462			(1,682		)	194,289
Income charges not requiring cash	148,029			151,124			623,670			633,895
Changes in assets and liabilities	(23,835		)	30,442			(68,326		)	41,637
Net cash provided by operating activities	139,728			155,783			392,377			740,737
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(130,120		)	(135,763		)	(375,153		)	(955,602		)
Acquisitions	—			—			—			(16,312		)
Proceeds from sale of assets	1,351			273			50,419			7,653
Investment in equity method investments	(4,308		)	(8,275		)	(28,484		)	(29,073		)
Net cash used in investing activities	(133,077		)	(143,765		)	(353,218		)	(993,334		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) of debt	—			(12,000		)	(497,000		)	273,000
Sale of common stock, net	—			—			995,279			—
Dividends paid	(9,302		)	(8,278		)	(36,187		)	(33,090		)
Capitalized debt issuance costs	—			—			(3,223		)	(7,838		)
Other	—			1			—			85
Net cash provided by (used in) financing activities	(9,302		)	(20,277		)	458,869			232,157
Net increase (decrease) in cash and cash equivalents	$	(2,651	)	$	(8,259	)	$	498,028		$	(20,440	)

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Selected Item Review and Reconciliation of Net Income and Earnings Per Share

	Quarter Ended December 31,						Twelve Months Ended December 31,
(In thousands, except per share amounts)	2016			2015			2016			2015
As reported - net loss	$	(292,760	)	$	(111,124	)	$	(417,124	)	$	(113,891	)
Reversal of selected items:
Impairment of oil and gas properties and other assets	435,619			114,875			435,619			114,875
(Gain) loss on sale of assets	1,089			(52		)	1,857			(3,866		)
(Gain) loss on derivative instruments(1)	32,778			48,444			37,268			137,603
Loss on debt extinguishment	—			—			4,709			—
Drilling rig termination fees	—			—			1,655			5,084
Stock-based compensation expense	2,952			2,058			25,968			13,680
Tax effect on selected items	(174,567		)	(60,646		)	(187,366		)	(98,081		)
Net income (loss) excluding selected items	$	5,111		$	(6,445	)	$	(97,414	)	$	55,404
As reported - loss per share	$	(0.63	)	$	(0.27	)	$	(0.91	)	$	(0.28	)
Per share impact of selected items	0.64			0.25			0.70			0.41
Earnings (loss) per share excluding selected items	$	0.01		$	(0.02	)	$	(0.21	)	$	0.13
Weighted-average common shares outstanding	465,150			413,875			456,847			413,696

⁽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

	Quarter Ended December 31,						Twelve Months Ended December 31,
(In thousands)	2016			2015			2016			2015
Net loss	$	(292,760	)	$	(111,124	)	$	(417,124	)	$	(113,891	)
Plus (less):
Deferred income tax benefit	(171,294		)	(81,194		)	(230,707		)	(72,968		)
Impairment of oil and gas properties and other assets	435,619			114,875			435,619			114,875
(Gain) loss on sale of assets	1,089			(52		)	1,857			(3,866		)
Exploratory dry hole cost	10,102			3,268			10,120			3,452
(Gain) loss on derivative instruments	37,664			(12,018		)	38,950			(56,686		)
Net cash received (paid) in settlement of derivative instruments	(4,886		)	60,462			(1,682		)	194,289
Income charges not requiring cash	148,029			151,124			623,670			633,895
Discretionary cash flow	163,563			125,341			460,703			699,100
Changes in assets and liabilities	(23,835		)	30,442			(68,326		)	41,637
Net cash provided by operations	$	139,728		$	155,783		$	392,377		$	740,737

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EBITDAX Calculation and Reconciliation

	Quarter Ended December 31,						Twelve Months Ended December 31,
(In thousands)	2016			2015			2016			2015
Net loss	$	(292,760	)	$	(111,124	)	$	(417,124	)	$	(113,891	)
Plus (less):
Loss on debt extinguishment	—			—			4,709			—
Interest expense	20,515			24,666			88,336			96,911
Income tax benefit	(171,232		)	(71,213		)	(242,475		)	(73,382		)
Depreciation, depletion and amortization	141,218			149,876			590,128			622,211
Impairment of oil and gas properties and other assets	435,619			114,875			435,619			114,875
Exploration	14,553			8,500			27,662			27,460
(Gain) loss on sale of assets	1,089			(52		)	1,857			(3,866		)
Non-cash (gain) loss on derivative instruments	32,778			48,444			37,268			137,603
(Earnings) loss on equity method investments	2,685			(1,834		)	2,477			(6,415		)
Stock-based compensation	2,952			2,058			25,968			13,680
EBITDAX	$	187,417		$	164,196		$	554,425		$	815,186

Net Debt Reconciliation

(In thousands)	December 31, 2016			December 31, 2015
Current portion of long-term debt	$	—		$	20,000
Long-term debt, net	1,520,530			1,996,139
Total debt	$	1,520,530		$	2,016,139
Stockholders’ equity	2,567,667			2,009,188
Total capitalization	$	4,088,197		$	4,025,327
Total debt	$	1,520,530		$	2,016,139
Less: Cash and cash equivalents	(498,542		)	(514		)
Net debt	$	1,021,988		$	2,015,625
Net debt	$	1,021,988		$	2,015,625
Stockholders’ equity	2,567,667			2,009,188
Total adjusted capitalization	$	3,589,655		$	4,024,813
Total debt to total capitalization ratio	37.2		%	50.1		%
Less: Impact of cash and cash equivalents	8.7		%	—		%
Net debt to adjusted capitalization ratio	28.5		%	50.1		%

Pre-tax Present Value of Future Net Cash Flows Calculation and Reconciliation

(In thousands)	December 31, 2016		December 31, 2015
Standardized Measure of Discounted Future Net Cash Flows	$	2,234,767	$	2,858,832
Plus: Future Income Tax Expenses, discounted at 10% annual rate	380,276		—
Pre-tax Present Value of Future Net Cash Flows, discounted at 10% annual rate	$	2,615,043	$	2,858,832

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