Coterra Energy - 10-Q quarterly report FY2016 Q3

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the quarterly period ended September 30, 2016

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)



DELAWARE		04-3072771
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

Three Memorial City Plaza

840 Gessner Road, Suite 1400, Houston, Texas 77024

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer ý		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

As of October 24, 2016, there were 465,149,507 shares of Common Stock, Par Value $.10 Per Share, outstanding.

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CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS



		Page
Part I. Financial Information

Item 1.	Financial Statements

Condensed Consolidated Balance Sheet (Unaudited) at September 30, 2016 and December 31, 2015		3

Condensed Consolidated Statement of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2016 and 2015		4

Condensed Consolidated Statement of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2016 and 2015		5

Notes to the Condensed Consolidated Financial Statements		6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27

Item 4.	Controls and Procedures	29

Part II. Other Information

Item 1.	Legal Proceedings	29

Item 1A.	Risk Factors	29

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30

Item 6.	Exhibits	30

Signatures		31

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)



(In thousands, except share amounts)	September 30, 2016			December 31, 2015
ASSETS
Current assets
Cash and cash equivalents	$	501,193		$	514
Accounts receivable, net	121,301			120,229
Income taxes receivable	15,558			4,323
Inventories	13,487			17,049
Other current assets	4,106			2,671
Total current assets	655,645			144,786
Properties and equipment, net (Successful efforts method)	4,722,598			4,976,879
Equity method investments	127,901			103,517
Other assets	25,777			27,856
	$	5,531,921		$	5,253,038

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	160,142		$	160,407
Current portion of long-term debt	—			20,000
Accrued liabilities	18,199			24,923
Interest payable	12,604			30,222
Derivative instruments	5,818			—
Total current liabilities	196,763			235,552
Long-term debt, net	1,520,190			1,996,139
Deferred income taxes	749,976			807,236
Asset retirement obligations	134,701			143,606
Postretirement benefits	37,623			35,293
Other liabilities	29,418			26,024
Total liabilities	2,668,671			3,243,850

Commitments and contingencies

Stockholders' equity
Common stock:
Authorized — 960,000,000 shares of $0.10 par value in 2016 and 2015, respectively
Issued — 475,041,453 shares and 423,768,593 shares in 2016 and 2015, respectively	47,504			42,377
Additional paid-in capital	1,722,129			721,997
Retained earnings	1,400,765			1,552,014
Accumulated other comprehensive income (loss)	(313		)	(365		)
Less treasury stock, at cost:
9,892,680 shares in 2016 and 2015, respectively	(306,835		)	(306,835		)
Total stockholders' equity	2,863,250			2,009,188
	$	5,531,921		$	5,253,038

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands, except per share amounts)	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	19,776			11,102			68,399			53,611
	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	)
Diluted	$	(0.02	)	$	(0.04	)	$	(0.27	)	$	(0.01	)

Weighted-average common shares outstanding
Basic	465,149			413,846			454,060			413,636
Diluted	465,149			413,846			454,060			413,636

Dividends per common share	$	0.02		$	0.02		$	0.06		$	0.06

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)



	Nine Months Ended September 30,
(In thousands)	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(124,364	)	$	(2,767	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	448,910			472,335
Deferred income tax expense (benefit)	(59,413		)	8,226
(Gain) loss on sale of assets	768			(3,814		)
Exploratory dry hole cost	18			184
(Gain) loss on derivative instruments	1,286			(44,668		)
Net cash received (paid) in settlement of derivative instruments	3,204			133,827
Earnings on equity method investments	(208		)	(4,581		)
Amortization of debt issuance costs	3,888			3,395
Stock-based compensation and other	23,051			11,622
Changes in assets and liabilities:
Accounts receivable, net	(1,135		)	112,712
Income taxes	(11,235		)	(10,158		)
Inventories	2,860			(4,256		)
Other current assets	(917		)	(2,106		)
Accounts payable and accrued liabilities	(17,230		)	(66,350		)
Interest payable	(17,618		)	(17,082		)
Other assets and liabilities	784			(1,565		)
Net cash provided by operating activities	252,649			584,954

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(245,033		)	(819,839		)
Acquisitions	—			(16,312		)
Proceeds from sale of assets	49,068			7,380
Investment in equity method investments	(24,176		)	(20,798		)
Net cash used in investing activities	(220,141		)	(849,569		)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	90,000			790,000
Repayments of debt	(587,000		)	(505,000		)
Sale of common stock, net	995,279			—
Dividends paid	(26,885		)	(24,812		)
Capitalized debt issuance costs	(3,223		)	(7,838		)
Other	—			84
Net cash provided by financing activities	468,171			252,434

Net increase (decrease) in cash and cash equivalents	500,679			(12,181		)
Cash and cash equivalents, beginning of period	514			20,954
Cash and cash equivalents, end of period	$	501,193		$	8,773

Supplemental non-cash investing transactions:
Change in accrued capital costs	$	17,072		$	(159,102	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. Financial Statement Presentation

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2015 (Form 10-K) filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported stockholder's equity, net income (loss) or cash flows.

Recently Adopted Accounting Pronouncements

Debt Issuance Costs. In March 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. The update provides authoritative guidance for debt issuance costs related to line-of-credit arrangements, noting the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance is effective for interim and annual periods beginning after December 15, 2015.

Effective January 1, 2016, the Company adopted ASU No. 2015-03 as a change in accounting principle. The Condensed Consolidated Balance Sheet as of December 31, 2015 has been retrospectively adjusted to reflect the adoption of this guidance, resulting in a decrease of $8.9 million in both other assets and long term debt related to the debt issuance costs on our senior notes. There was no impact to the Company’s Condensed Consolidated Statement of Operations or Statement of Cash Flows.

Recently Issued Accounting Pronouncements

Stock-based Compensation. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, as an amendment to Accounting Standards Codification (ASC) Topic 718. The areas for simplification in this update involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, forfeitures, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is permitted. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method.

The Company expects to adopt this guidance effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits is expected to result in a cumulative-effect adjustment of between $45.0 million and $50.0 million (net of tax), which would increase retained earnings and decrease net deferred tax liabilities by the same amount as of the beginning of 2017. The remaining provisions of this amendment are not expected to have a material effect on the Company's financial position, results of operations or cash flows.

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Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, as a new Topic, ASC Topic 842. The new lease guidance supersedes Topic 840. The core principle of the guidance is that a company should recognize the assets and liabilities that arise from leases. This ASU does not apply to leases to explore for or use minerals, oil, natural gas and similar nonregenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. The guidance is effective for interim and annual periods beginning after December 15, 2018. This ASU can be adopted using a modified retrospective approach. The Company expects to adopt this standard effective January 1, 2019 and is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, ASC Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption.

Additionally, in March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvements and practical expedients, which addresses narrow-scope improvements to the guidance on collectibility, non-cash consideration, and completed contracts at transition. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operations or cash flows.

Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted, provided that all of the amendments are adopted in the same period. This guidance must be adopted using a retrospective transition method. The Company is currently evaluating the effect that adopting this guidance will have on its cash flows.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:



(In thousands)	September 30, 2016			December 31, 2015
Proved oil and gas properties	$	7,669,157		$	8,821,146
Unproved oil and gas properties	287,007			390,434
Gathering and pipeline systems	189,393			243,672
Land, building and other equipment	81,537			117,848
	8,227,094			9,573,100
Accumulated depreciation, depletion and amortization	(3,504,496		)	(4,596,221		)
	$	4,722,598		$	4,976,879

At September 30, 2016, the Company did not have any projects that had exploratory well costs capitalized for a period of greater than one year after drilling.

In February 2016, the Company completed the divestiture of certain proved and unproved oil and gas properties in east Texas for approximately $56.4 million and recognized a $0.5 million gain on sale of assets. The purchase price included a $6.3 million deposit that was received in the fourth quarter of 2015.

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3. Equity Method Investments

The Company holds a 25% equity interest in Constitution Pipeline Company, LLC (Constitution) and a 20% equity interest in Meade Pipeline Co LLC (Meade). Activity related to these equity method investments is as follows:



	Constitution				Meade						Total
	Nine Months Ended September 30,				Nine Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2016		2015		2016			2015			2016		2015
Balance at beginning of period	$	90,345	$	64,269	$	13,172		$	3,760		$	103,517	$	68,029
Contributions	8,325		13,500		15,851			7,298			24,176		20,798
Earnings (loss) on equity method investments	211		4,608		(3		)	(27		)	208		4,581
Balance at end of period	$	98,881	$	82,377	$	29,020		$	11,031		$	127,901	$	93,408

During 2016, the Company expects to contribute approximately $30.0 million to its equity method investments. For further information regarding the Company’s equity method investments, refer to Note 4 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Constitution

The following table represents summarized financial information for Constitution as derived from the respective unaudited financial statements of Constitution for the nine months ended September 30, 2016 and 2015, respectively:



	Nine Months Ended September 30, 2016
(In thousands)	2016			2015
Revenues	$	—		$	—
Income (loss) from continuing operations	$	(10,974	)	$	19,366
Net income (loss)	$	(10,974	)	$	19,366

The Company records the activity for its equity method investments on a one month lag; however, the above summarized financial information represents Constitution's operations for the nine months ended September 30, 2016 and 2015, respectively.

On April 22, 2016, Constitution announced that the New York State Department of Environmental Conservation (NYSDEC) denied Constitution's application for a section 401 Water Quality Certification (Certification) for the New York State portion of its proposed 124-mile route. During second quarter of 2016, Constitution filed legal actions in the U.S Court of Appeals for the Second Circuit and the U.S District Court for the Northern District of New York challenging the legality and appropriateness of the NYSDEC’s decision. Both courts have granted Constitution's motions to expedite the schedules for the legal actions.

Constitution stated that it remains committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC’s decision. In light of the denial of the Certification and ongoing litigation, Constitution has revised its target in-service date to the second half of 2018, assuming that the challenge process is satisfactorily and promptly concluded.

In light of the NYSDEC’s denial and resulting litigation, the Company evaluated its investment in Constitution for other-than-temporary impairment (OTTI) and as of September 30, 2016, does not believe there is an indication of an OTTI. The Company’s evaluation considered various factors, including but not limited to prior Federal Energy Regulatory Commission approval and the related economic viability of the project, legal actions filed by Constitution and the expected duration of the legal proceedings, which are at very early stages, and the other members’ commitment to the project. To the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is no longer viable or elects to not go forward as legal and regulatory actions progress, the Company will reevaluate the facts and circumstances relative to its conclusions with respect to OTTI. In the event that facts and circumstances change, the Company may be required to recognize an impairment charge up to its investment value at such time, net of any cash and working capital held by Constitution. The Company will continue to monitor the carrying value of its investment as required.

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At this time, the Company remains committed to funding the project in an amount in proportion to its ownership interest for the development and construction of the new pipeline. The Company's total contributions for this project are expected to be approximately $240.0 million. As of September 30, 2016, the Company has made contributions of approximately $87.9 million since inception of the project.

Meade

In October 2016, Meade revised its expected in-service date to mid-2018; however, this estimate is contingent on the timely issuance of remaining outstanding permits.

4. Debt and Credit Agreements

The Company’s debt and credit agreements consisted of the following:



(In thousands)	September 30, 2016			December 31, 2015
7.33% weighted-average senior notes	$	—		$	20,000
6.51% weighted-average senior notes	361,000			425,000
9.78% senior notes	67,000			67,000
5.58% weighted-average senior notes	175,000			175,000
3.65% weighted-average senior notes	925,000			925,000
Revolving credit facility	—			413,000
	1,528,000			2,025,000
Unamortized debt issuance costs	(7,810		)	(8,861		)
Total debt, net⁽¹⁾	$	1,520,190		$	2,016,139

(1) Includes $20.0 million of current portion of long-term debt at December 31, 2015.

The borrowing base under the terms of the Company's revolving credit facility is redetermined annually in April. In addition, either the Company or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. Effective April 19, 2016, the Company’s borrowing base was reduced from $3.4 billion to $3.2 billion. The maximum credit amount under the revolving credit facility remained unchanged at $1.8 billion; however, the available commitments were reduced to $1.6 billion at the time of the redetermination.

In May 2016, the Company repurchased $64.0 million principal amount of its 6.51% weighted-average senior notes for approximately $68.3 million. A $4.7 million extinguishment loss was recognized in the second quarter of 2016 associated with the premium paid and the write-off of a portion of the associated deferred financing costs due to early repayment. As a result of the repurchase of these senior notes, the available commitments under the revolving credit facility increased to $1.7 billion and remained at that level as of September 30, 2016.

At September 30, 2016, the Company was in compliance with all restrictive financial covenants for both its revolving credit facility and senior notes. As of September 30, 2016, based on the Company's asset coverage and leverage ratios, there were no interest rate adjustments required for the Company's senior notes.

At September 30, 2016, the Company had no borrowings outstanding under its revolving credit facility and had unused commitments of $1.7 billion. There were no borrowings under the revolving credit facility during the second and third quarters of 2016. The Company’s weighted-average effective interest rate for the revolving credit facility for the three months ended September 30, 2015 was approximately 2.1% and for the nine months ended September 30, 2016 and 2015 was approximately 2.3% and 2.2%, respectively.

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5. Derivative Instruments and Hedging Activities

As of September 30, 2016, the Company had the following outstanding commodity derivatives:



				Collars									Basis Swaps
				Floor				Ceiling			Swaps		Basis Swaps
Type of Contract	Volume		Contract Period	Range		Weighted-Average		Range	Weighted-Average		Weighted-Average		Weighted-Average
Natural gas	7.5	Bcf	Oct. 2016								$	2.51
Natural gas	35.5	Bcf	Jan. 2017 - Dec. 2017								$	3.12
Natural gas	35.5	Bcf	Jan. 2017 - Dec. 2017	$	—	$	3.09	$3.42-$3.45	$	3.43
Natural gas	17.7	Bcf	Jan. 2018 - Dec. 2019										$	0.42
Crude oil	0.5	Mmbbl	Oct. 2016 - Dec. 2016	$	—	$	38.00	$47.10-$47.50	$	47.28

In the table above, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet



		Derivative Assets				Derivative Liabilities
(In thousands)	Balance Sheet Location	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Commodity contracts	Other current assets	$	518	$	—	$	—	$	—
Commodity contracts	Other assets (non-current)	1,144		—		—		—
Commodity contracts	Derivative instruments (current)	—		—		5,818		—
Commodity contracts	Other liabilities (non-current)	—		—		335		—
		$	1,662	$	—	$	6,153	$	—

Offsetting of Derivative Assets and Liabilities in the Condensed Consolidated Balance Sheet



(In thousands)	September 30, 2016			December 31, 2015
Derivative assets
Gross amounts of recognized assets	$	2,668		$	—
Gross amounts offset in the statement of financial position	(1,006		)	—
Net amounts of assets presented in the statement of financial position	1,662			—
Gross amounts of financial instruments not offset in the statement of financial position	—			—
Net amount	$	1,662		$	—
Derivative liabilities
Gross amounts of recognized liabilities	$	7,159		$	—
Gross amounts offset in the statement of financial position	(1,006		)	—
Net amounts of liabilities presented in the statement of financial position	6,153			—
Gross amounts of financial instruments not offset in the statement of financial position	—			—
Net amount	$	6,153		$	—

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Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2016			2015			2016			2015
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	(8,101	)	$	45,097		$	3,204		$	133,827
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	15,005			(27,733		)	(4,490		)	(89,159		)
	$	6,904		$	17,364		$	(1,286	)	$	44,668

6. Fair Value Measurements

The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. For further information regarding the fair value hierarchy, refer to Note 1 of the Notes to the Consolidated Financial Statements in the Form 10-K.

Financial Assets and Liabilities

The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis:



(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Balance at September 30, 2016
Assets
Deferred compensation plan	$	12,297	$	—		$	—	$	12,297
Derivative instruments	—		(233		)	1,895		1,662
Total assets	$	12,297	$	(233	)	$	1,895	$	13,959
Liabilities
Deferred compensation plan	$	25,088	$	—		$	—	$	25,088
Derivative instruments	—		4,722			1,431		6,153
Total liabilities	$	25,088	$	4,722		$	1,431	$	31,241



(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at December 31, 2015
Assets
Deferred compensation plan	$	12,921	$	—	$	—	$	12,921
Total assets	$	12,921	$	—	$	—	$	12,921
Liabilities
Deferred compensation plan	$	22,371	$	—	$	—	$	22,371
Total liabilities	$	22,371	$	—	$	—	$	22,371

The Company’s investments associated with its deferred compensation plan consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available.

The derivative instruments were measured based on quotes from the Company’s counterparties. Such quotes have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, basis differentials, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. Estimates are verified using relevant NYMEX futures contracts and/or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with which it has derivative transactions, while non-performance risk of the Company is evaluated

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using a market credit spread provided by the Company’s bank. The Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.

The most significant unobservable inputs relative to the Company’s Level 3 derivative contracts are basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:



	Nine Months Ended September 30,
(In thousands)	2016		2015
Balance at beginning of period	$	—	$	85,958
Total gain (loss) included in earnings	381		23,867
Settlement (gain) loss	83		(77,532		)
Transfers in and/or out of level 3	—		—
Balance at end of period	$	464	$	32,293

Change in unrealized gain (loss) relating to assets and liabilities still held at the end of the period	$	464	$	(53,665	)

There were no transfers between Level 1 and Level 2 fair value measurements for the nine months ended September 30, 2016 and 2015.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments, at fair value on a nonrecurring basis. As none of the Company’s non-financial assets and liabilities were measured at fair value as of September 30, 2016 and December 31, 2015, additional disclosures were not required.

The estimated fair value of the Company’s asset retirement obligation at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Fair Value of Other Financial Instruments

The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amount reported in the Condensed Consolidated Balance Sheet for cash and cash equivalents approximates fair value due to the short-term maturities of these instruments. Cash and cash equivalents are classified as Level 1 in the fair value hierarchy and the remaining financial instruments are classified as Level 2.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all senior notes and the revolving credit facility is based on interest rates currently available to the Company. The Company’s debt is valued using an income approach and classified as Level 3 in the fair value hierarchy.

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The carrying amount and fair value of debt is as follows:



	September 30, 2016				December 31, 2015
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount			Estimated Fair Value
Debt, net	$	1,520,190	$	1,507,258	$	2,016,139		$	1,839,530
Current maturities	—		—		(20,000		)	(20,378		)
Long-term debt, excluding current maturities	$	1,520,190	$	1,507,258	$	1,996,139		$	1,819,152

7. Asset Retirement Obligations

Activity related to the Company’s asset retirement obligations is as follows:



(In thousands)	Nine Months Ended September 30, 2016
Balance at beginning of period	$	145,606
Liabilities incurred	2,861
Liabilities settled	(708		)
Liabilities divested	(16,353		)
Accretion expense	5,295
Balance at end of period	$	136,701

8. Commitments and Contingencies

Contractual Obligations

The Company has various contractual obligations in the normal course of its operations. There have been no material changes to the Company’s contractual obligations described under “Transportation and Gathering Agreements,” “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 9 in the Notes to Consolidated Financial Statements included in the Form 10-K.

Legal Matters

The Company is a defendant in various legal proceedings arising in the normal course of business. All known liabilities are accrued when management determines they are probable based on its best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company’s financial position, results of operations or cash flows.

Contingency Reserves

When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters in which reserves have been established. The Company believes that any such amount above the amounts accrued would not be material to the Condensed Consolidated Financial Statements. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

9. Capital Stock

On February 22, 2016, the Company entered into an underwriting agreement, pursuant to which the Company sold an aggregate of 44,000,000 shares of common stock at a price to the Company of $19.675 per share. On February 26, 2016, the Company received $865.7 million in net proceeds, after deducting underwriting discounts and commissions. On March 2, 2016, the Company sold an additional 6,600,000 shares of common stock as a result of the exercise of the underwriters’ option to purchase additional shares and received $129.9 million in net proceeds. These net proceeds were used for general corporate purposes, including repaying indebtedness under the Company’s revolving credit facility and certain of our senior notes and funding a portion of our capital program.

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10. Stock-based Compensation

General

From time to time the Company grants certain stock-based compensation awards, including restricted stock awards, restricted stock units and performance share awards. Stock-based compensation expense (benefit) associated with these awards was $5.1 million and $(2.9) million in the third quarter of 2016 and 2015, respectively, and $23.0 million and $11.6 million during the first nine months of 2016 and 2015, respectively. Stock-based compensation expense is included in general and administrative expense in the Condensed Consolidated Statement of Operations.

During the first nine months of 2016, the Company recorded a tax shortfall of $2.1 million, resulting in a reduction of the Company's windfall tax benefit that is recorded in additional paid in capital in the Condensed Consolidated Balance Sheet. There was no tax benefit recognized from stock-based compensation during the first nine months of 2015. The tax shortfall is a result of book compensation cost for employee stock-based compensation exceeding the federal and state tax deductions for certain awards that vested during the period. The Company is able to recognize a tax benefit only to the extent it reduces the Company’s income taxes payable.

Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of stock-based compensation awards and the applicable award terms.

Restricted Stock Units

During the first nine months of 2016, 67,000 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date value of $20.55 per unit. The fair value of these units is measured based on the closing stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are issued when the director ceases to be a director of the Company.

Performance Share Awards

The performance period for the awards granted in 2016 commenced on January 1, 2016 and ends on December 31, 2018. The Company used an annual forfeiture rate assumption ranging from 0% to 6% for purposes of recognizing stock-based compensation expense for its performance share awards.

Performance Share Awards Based on Internal Performance Metrics

The fair value of performance share award grants based on internal performance metrics is based on the closing stock price on the grant date. Each performance share award represents the right to receive up to 100% of the award in shares of common stock. Based on the Company’s probability assessment at September 30, 2016, it is considered probable that the criteria for all performance awards based on internal metrics awards will be met.

Employee Performance Share Awards. During the first nine months of 2016, 435,990 Employee Performance Share Awards were granted at a grant date value of $20.49 per share. The performance metrics are set by the Company’s compensation committee and are based on the Company’s average production, average finding costs and average reserve replacement over a three-year performance period.

Hybrid Performance Share Awards. During the first nine months of 2016, 271,938 Hybrid Performance Share Awards were granted at a grant date value of $20.49 per share. The 2016 awards vest 25% on each of the first and second anniversary dates and 50% on the third anniversary, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date, as set by the Company’s compensation committee. If the Company does not meet the performance metric for the applicable period, then the portion of the performance shares that would have been issued on that anniversary date will be forfeited.

Performance Share Awards Based on Market Conditions

These awards have both an equity and liability component, with the right to receive up to the first 100% of the award in shares of common stock and the right to receive up to an additional 100% of the value of the award in excess of the equity component in cash. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model.

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TSR Performance Share Awards. During the first nine months of 2016, 407,907 TSR Performance Share Awards were granted and are earned, or not earned, based on the comparative performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group over a three-year performance period.

The following assumptions were used to determine the grant date fair value of the equity component (February 17, 2016) and the period-end fair value of the liability component of the TSR Performance Share Awards:



	Grant Date			September 30, 2016
Fair value per performance share award	$	18.57		$5.26 - $9.14
Assumptions:
Stock price volatility	34.4		%	30.4% - 38.4%
Risk free rate of return	0.9		%	0.3% - 0.8%

11. Earnings per Common Share

Basic earnings per share (EPS) is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock appreciation rights were exercised and stock awards were vested at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that which are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

The following is a calculation of basic and diluted weighted-average shares outstanding:



	Three Months Ended September 30,		Nine Months Ended September 30,
(In thousands)	2016	2015	2016	2015
Weighted-average shares - basic	465,149	413,846	454,060	413,636
Dilution effect of stock appreciation rights and stock awards at end of period	—	—	—	—
Weighted-average shares - diluted	465,149	413,846	454,060	413,636

The following is a calculation of weighted-average shares excluded from diluted EPS due to the anti-dilutive effect:



	Three Months Ended September 30,		Nine Months Ended September 30,
(In thousands)	2016	2015	2016	2015
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect due to net loss	1,784	1,692	1,326	1,390
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method	—	—	1	3
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect	1,784	1,692	1,327	1,393

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12. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:



(In thousands)	September 30, 2016			December 31, 2015
Accounts receivable, net
Trade accounts	$	118,840		$	116,772
Joint interest accounts	1,618			2,013
Other accounts	1,986			2,557
	122,444			121,342
Allowance for doubtful accounts	(1,143		)	(1,113		)
	$	121,301		$	120,229

Inventories
Tubular goods and well equipment	$	10,962		$	14,685
Natural gas in storage	2,525			2,364
	$	13,487		$	17,049

Other current assets
Prepaid balances and other	$	3,588		$	2,671
Derivative instruments	518			—
	$	4,106		$	2,671

Other assets
Deferred compensation plan	$	12,297		$	12,921
Debt issuance costs	12,258			14,871
Derivative instruments	1,144			—
Other accounts	78			64
	$	25,777		$	27,856

Accounts payable
Trade accounts	$	26,439		$	30,038
Natural gas purchases	2,815			2,231
Royalty and other owners	70,631			75,106
Accrued capital costs	44,551			27,479
Taxes other than income	10,349			14,628
Other accounts	5,357			10,925
	$	160,142		$	160,407

Accrued liabilities
Employee benefits	$	8,040		$	13,870
Taxes other than income	5,910			5,073
Asset retirement obligations	2,000			2,000
Other accounts	2,249			3,980
	$	18,199		$	24,923

Other liabilities
Deferred compensation plan	$	25,088		$	22,371
Other accounts	4,330			3,653
	$	29,418		$	26,024

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following review of operations for the three and nine month periods ended September 30, 2016 and 2015 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Corporation Annual Report on Form 10-K for the year ended December 31, 2015 (Form 10-K).

OVERVIEW

Financial and Operating Overview

Financial and operating results for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 are as follows:


•	Equivalent production increased 11.5 Bcfe, or 3%, from 451.5 Bcfe, or 1,653.8 Mmcfe per day, in 2015 to 463.0 Bcfe, or 1,689.6 Mmcfe per day, in 2016.


•	Natural gas production increased 18.6 Bcf, or 4%, from 423.2 Bcf in 2015 to 441.8 Bcf in 2016, as a result of drilling and completion activities in Pennsylvania, partially offset by the divestiture of certain oil and gas properties in east Texas.


•	Crude oil/condensate/NGL production decreased 1.2 Mmbbls, or 25%, from 4.7 Mmbbls in 2015 to 3.5 Mmbbls in 2016, as result of a decrease in drilling activities in south Texas.


•	Average realized natural gas price was $1.62 per Mcf, 27% lower than the $2.23 per Mcf realized in the comparable period of the prior year.


•	Average realized crude oil price was $35.85 per Bbl, 25% lower than the $48.00 per Bbl realized in the comparable period of the prior year.


•	Drilled 28 gross wells (28.0 net) with a success rate of 100% compared to 114 gross wells (105.5 net) with a success rate of 100% for the comparable period of the prior year.


•	Total capital expenditures were $262.1 million compared to $676.9 million in the comparable period of the prior year.


•	Average rig count during 2016 was approximately 1.1 rigs in the Marcellus Shale and approximately 0.3 rigs in the Eagle Ford Shale, compared to an average rig count in the Marcellus Shale of approximately 3.7 rigs and approximately 2.1 rigs in the Eagle Ford Shale in 2015.


•	In the first quarter of 2016, we completed a public offering of our common stock and received net proceeds of $995.6 million, after deducting underwriting discounts and commissions.


•	In the first nine months of 2016, we received proceeds of $49.1 million primarily related to the divestiture of certain proved and unproved oil and gas properties in east Texas.


•	In the second quarter of 2016, we repurchased $64.0 million principal amount of our 6.51% weighted-average senior notes for approximately $68.3 million.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions and other factors. In addition, our realized prices are further impacted by our hedging activities. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. Location differentials have increased in certain regions, such as in the Appalachian region, resulting in further declines in natural gas prices. We expect natural gas and crude oil prices to remain volatile. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. For information about the impact of realized commodity prices on our natural gas and crude oil and condensate revenues, refer to “Results of Operations” below.

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We account for our derivative instruments on a mark-to-market basis with changes in fair value recognized in operating revenues in the Condensed Consolidated Statement of Operations. As a result of these mark-to-market adjustments associated with our derivative instruments, we will likely experience volatility in our earnings due to commodity price volatility. Refer to “Impact of Derivative Instruments on Operating Revenues” below and Note 5 to the Condensed Consolidated Financial Statements for more information.

Commodity prices have remained volatile but have improved during 2016 compared to the fourth quarter of 2015. In the event that commodity prices significantly decline, management would test the recoverability of the carrying value of its oil and gas properties and, if necessary, record an impairment charge. Following the $771.0 million and $114.9 million impairments recorded in the fourth quarter of 2014 and 2015, respectively, and the improvement in commodity prices since the fourth quarter of 2015, we do not believe that further impairment of our oil and gas properties is reasonably likely to occur in the near future; however, in the event that commodity prices significantly decline from current levels, additional impairments of our oil and gas properties may be required.

We believe that we are well-positioned to manage the challenges presented in the current commodity pricing environment, and that we can endure the current cyclical downturn in the oil and gas industry and the continued volatility in current and future commodity prices by:


•	Continuing to exercise discipline in our capital program by reducing our capital expenditures and number of wells drilled compared to the prior year.


•	Continuing to optimize our drilling, completion and operational efficiencies, resulting in lower operating costs per unit of production.

•

Continuing to manage our balance sheet, including the issuance of common stock in February 2016 which allowed us to pay down the outstanding balance under our revolving credit facility and certain of our senior notes, leaving us with sufficient availability under our revolving credit facility and existing cash balances to meet our capital requirements and maintain compliance with our debt covenants.


•	Continuing to manage price risk by strategically hedging our natural gas and crude oil production.

Outlook

As a result of lower natural gas and crude oil prices expected in 2016, we reduced our budgeted capital expenditures compared to 2015. Our full year 2016 capital spending program includes approximately $380.0 million in capital expenditures related to our drilling and completion program and contributions of approximately $30.0 million to our equity method investments. All such expenditures are expected to be funded by existing cash, operating cash flow and if required, borrowings under our revolving credit facility.

In 2016, we plan to drill approximately 42 gross wells (40.0 net) compared to 142 gross wells (132.8 net) in 2015. In 2016, we plan to operate an average of approximately 1.4 rigs, a decrease from an average of approximately 5.4 rigs in 2015. We allocate our planned program for capital expenditures among our various operating areas based on market conditions, return expectations, availability of services and human resources. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital expenditures accordingly.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the nine months ended September 30, 2016 were from funds generated from the sale of common stock, the sale of natural gas and crude oil production and proceeds from the sale of assets. These cash flows were primarily used to fund our capital expenditures (including contributions to our equity method investments), repayment of indebtedness under our revolving credit facility and certain of our senior notes, interest payments and payment of dividends. See below for additional discussion and analysis of cash flow.

In the first quarter of 2016, we sold an aggregate of 50.6 million shares of common stock at a price of $19.675 per share and received $995.6 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used for general corporate purposes, including repaying indebtedness under our revolving credit facility and certain of our senior notes and funding a portion of our capital program.

The borrowing base under the terms of our revolving credit facility is redetermined annually in April. In addition, either we or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or

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divestitures of oil and gas properties. Effective April 19, 2016, our borrowing base was reduced from $3.4 billion to $3.2 billion. The maximum credit amount under the revolving credit facility remain unchanged at $1.8 billion; however, the available commitments were reduced to $1.6 billion at the time of redetermination. We do not believe these reductions will have a significant impact on our ability to service our debt and fund our drilling program and related operations.

In May 2016, we repurchased $64.0 million principal amount of our 6.51% weighted-average senior notes for approximately $68.3 million. A $4.7 million extinguishment loss was recognized in the second quarter of 2016 associated with the premium paid and the write-off of a portion of the associated deferred financing costs due to early repayment. As a result of the repurchase of these senior notes, the available commitments under the revolving credit facility increased to $1.7 billion and remained at that level as of September 30, 2016.

We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. We believe that, with the proceeds received from our equity offering in February 2016, internally generated cash flow and availability under our revolving credit facility, we have the capacity to finance our spending plans.

At September 30, 2016, we were in compliance with all restrictive financial covenants for both the revolving credit facility and senior notes. As of September 30, 2016, based on our asset coverage and leverage ratios, there were no interest rate adjustments required for our senior notes. See our Form 10-K for further discussion of our restrictive financial covenants.

Cash Flows

Our cash flows from operating activities, investing activities and financing activities are as follows:



	Nine Months Ended September 30,
(In thousands)	2016			2015
Cash flows provided by operating activities	$	252,649		$	584,954
Cash flows used in investing activities	(220,141		)	(849,569		)
Cash flows provided by financing activities	468,171			252,434
Net increase (decrease) in cash and cash equivalents	$	500,679		$	(12,181	)

Operating Activities. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been volatile, primarily as a result of supply and demand for natural gas and crude oil, pipeline infrastructure constraints and seasonal influences. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.

Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and the amount of borrowings and repayments under our revolving credit facility, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, the issuance of common stock and changes in the fair value of our commodity derivative activity. From time to time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. At September 30, 2016 and December 31, 2015, we had a working capital surplus (deficit) of $458.9 million and $(90.8) million, respectively. We believe we have adequate liquidity and availability under our revolving credit facility to meet our working capital requirements.

Net cash provided by operating activities in the first nine months of 2016 decreased by $332.3 million compared to the first nine months of 2015. This decrease was primarily due to unfavorable changes in working capital and other assets and liabilities and lower operating revenues, partially offset by lower operating expenses (excluding non-cash expenses). The decrease in operating revenues was primarily due to a decrease in realized natural gas and crude oil prices, partially offset by an increase in equivalent production. Average realized natural gas and crude oil prices decreased by 27% and 25%, respectively, for the first nine months of 2016 compared to the first nine months of 2015. Equivalent production increased by 3% for the first nine months of 2016 compared to the first nine months of 2015 due to higher natural gas production in the Marcellus Shale, partially offset by lower oil production in the Eagle Ford Shale.

See “Results of Operations” for additional information relative to commodity price, production and operating expense fluctuations. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.

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Investing Activities. Cash flows used in investing activities decreased by $629.4 million for the first nine months of 2016 compared to the first nine months of 2015. The decrease was due to $591.1 million lower capital expenditures, $41.7 million higher proceeds from the sale of assets, partially offset by $3.4 million higher capital contributions associated with our equity method investments.

Financing Activities. Cash flows provided by financing activities increased by $215.7 million for the first nine months of 2016 compared to the first nine months of 2015. This increase was primarily due to $995.3 million of net proceeds related to the issuance of common stock and lower capitalized debt issuance costs of $4.6 million related to the amendment of our revolving credit facility and senior notes in December 2015, partially offset by $782.0 million of higher net repayments of debt due to the repayment of the outstanding balance on our revolving credit facility and certain of our senior notes with the proceeds from the issuance of common stock and $2.1 million of higher dividend payments.

Capitalization

Information about our capitalization is as follows:



(Dollars in thousands)	September 30, 2016			December 31, 2015
Debt	$	1,520,190		$	2,016,139
Stockholders' equity	2,863,250			2,009,188
Total capitalization	$	4,383,440		$	4,025,327
Debt to total capitalization	35		%	50		%
Cash and cash equivalents	$	501,193		$	514

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash generated from operations, and if required, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year. In 2016, our budgeted capital expenditures are expected to slightly exceed cash flows from operations, requiring us to fund a portion of our capital expenditures through cash on hand, and if required, borrowings under our revolving credit facility.

The following table presents major components of our capital and exploration expenditures:



	Nine Months Ended September 30,
(In thousands)	2016		2015
Capital expenditures
Drilling and facilities	$	255,139	$	639,274
Leasehold acquisitions	1,687		16,430
Property acquisitions	—		16,312
Pipeline and gathering	1,009		1,807
Other	4,251		3,042
	262,086		676,865
Exploration expenditures	13,109		18,960
Total	$	275,195	$	695,825

For the full year of 2016, we plan to drill approximately 42 gross wells (40.0 net). In 2016, our drilling program includes approximately $380.0 million in total capital expenditures compared to $773.5 million in 2015. See “Financial and Operating Overview” for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital expenditures accordingly.

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Contractual Obligations

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Transportation and Gathering Agreements,” “Drilling Rig Commitments” and “Lease Commitments” as disclosed in Note 9 in the Notes to Consolidated Financial Statements and the obligations described under “Contractual Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our Condensed Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Form 10-K for further discussion of our critical accounting policies.

New Accounting Pronouncements

Refer to Note 1 to the Condensed Consolidated Financial Statements, “Financial Statement Presentation,” for a discussion of new accounting pronouncements that affect us.

Results of Operations

Third Quarters of 2016 and 2015 Compared

We reported a net loss in the third quarter of 2016 of $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. The decrease in net loss was primarily due to higher operating revenues and lower operating expenses and interest expense, partially offset by lower income tax benefit.

Revenue, Price and Volume Variances

Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.



	Three Months Ended September 30,				Variance
Revenue Variances (In thousands)	2016		2015		Amount			Percent
Natural gas	$	260,200	$	222,963	$	37,237		17	%
Crude oil and condensate	37,777		59,014		(21,237		)	(36	)%
Gain (loss) on derivative instruments	6,904		17,364		(10,460		)	(60	)%
Brokered natural gas	3,641		4,010		(369		)	(9	)%
Other	1,907		1,945		(38		)	(2	)%
	$	310,429	$	305,296	$	5,133		2	%



	Three Months Ended September 30,				Variance					Increase (Decrease) (In thousands)
	2016		2015		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	1.80	$	1.68	$	0.12		7	%	$	18,085
Crude oil and condensate	$	40.13	$	43.71	$	(3.58	)	(8	)%	(3,360		)
Total										$	14,725
Volume Variances
Natural gas (Bcf)	144.4		133.0		11.4			9	%	$	19,152
Crude oil and condensate (Mbbl)	941		1,350		(409		)	(30	)%	(17,877		)
Total										$	1,275

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Natural Gas Revenues

The increase in natural gas revenues of $37.2 million was due to higher production and natural gas prices. The increase in production was a result of our drilling and completion activities in Pennsylvania, partially offset by the divestiture of certain oil and gas properties in east Texas in February 2016.

Crude Oil and Condensate Revenues

The decrease in crude oil and condensate revenues of $21.2 million was due to lower production and crude oil prices. The decrease in production was a result of a decrease in drilling and completion activities in south Texas.

Impact of Derivative Instruments on Operating Revenues



	Three Months Ended September 30,
(In thousands)	2016			2015
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	(8,101	)	$	45,097
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	15,005			(27,733		)
	$	6,904		$	17,364

Brokered Natural Gas



	Three Months Ended September 30,				Variance					Price and Volume Variances (In thousands)
	2016		2015		Amount			Percent		Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	2.85	$	2.95	$	(0.10	)	(3	)%	$	(128	)
Volume brokered (Mmcf)	x	1,279	x	1,358	(79		)	(6	)%	(241		)
Brokered natural gas (In thousands)	$	3,641	$	4,010						$	(369	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.30	$	2.22	$	0.08		4	%	$	102
Volume brokered (Mmcf)	x	1,279	x	1,358	(79		)	(6	)%	(183		)
Brokered natural gas (In thousands)	$	2,939	$	3,020						$	(81	)

Brokered natural gas margin (In thousands)	$	702	$	990						$	(288	)

The $0.3 million decrease in brokered natural gas margin is a result of a decrease in sales price and an increase in purchase price. The decrease was also impacted by lower brokered volumes.

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Operating and Other Expenses



	Three Months Ended September 30,						Variance
(In thousands)	2016			2015			Amount			Percent
Operating and Other Expenses
Direct operations	$	24,626		$	34,818		$	(10,192	)	(29	)%
Transportation and gathering	105,671			102,121			3,550			3	%
Brokered natural gas	2,939			3,020			(81		)	(3	)%
Taxes other than income	8,771			11,407			(2,636		)	(23	)%
Exploration	2,988			4,930			(1,942		)	(39	)%
Depreciation, depletion and amortization	139,490			144,326			(4,836		)	(3	)%
General and administrative	19,776			11,102			8,674			78	%
	$	304,261		$	311,724		$	(7,463	)	(2	)%

Earnings (loss) on equity method investments	$	(1,727	)	$	1,648		$	(3,375	)	(205	)%
Gain (loss) on sale of assets	(1,245		)	3,756			(5,001		)	(133	)%
Interest expense	21,483			24,510			(3,027		)	(12	)%
Income tax expense (benefit)	(8,027		)	(10,020		)	(1,993		)	(20	)%

Total costs and expenses from operations decreased by $7.5 million, or 2%, in the third quarter of 2016 compared to the same period of 2015. The primary reasons for this fluctuation are as follows:


•	Direct operations decreased $10.2 million largely due to improved operational efficiencies, cost reductions from service providers and suppliers in 2016 compared to 2015 and the divestiture of certain oil and gas properties in east Texas in February 2016.


•	Transportation and gathering increased $3.6 million due to higher throughput as a result of higher Marcellus Shale production and the commencement of various transportation and gathering agreements in the Marcellus Shale throughout 2015.


•	Brokered natural gas decreased $0.1 million. See the preceding table titled “Brokered Natural Gas” for further analysis.


•	Taxes other than income decreased $2.6 million primarily due to $2.0 million lower ad valorem taxes as a result of lower property values primarily in south Texas and $1.3 million lower production taxes resulting from lower crude oil prices and production in south Texas. The remaining changes in taxes other than income were not individually significant.


•	Exploration decreased $1.9 million as a result of a $1.5 million reduction of estimated expenses associated with the release of certain drilling rig contracts in south Texas in the first quarter of 2016. During the third quarter of 2016, one of the rigs previously released was redeployed. The remaining changes in exploration expense were not individually significant.

•

Depreciation, depletion and amortization decreased $4.8 million, primarily due to lower amortization of unproved properties of $5.7 million in the third quarter of 2016 as a result of lower lease acquisition costs and lower amortization rates. Offsetting the decrease in amortization of unproved properties was a $1.3 million increase in DD&A, of which $7.8 million was due to higher equivalent production volumes partially offset by $6.5 million resulting from a lower DD&A rate of $0.85 per Mcfe for the third quarter of 2016 compared to $0.89 per Mcfe for the third quarter of 2015. The lower DD&A rate was primarily due to lower cost reserve additions and the impairment charge recorded in the fourth quarter of 2015 associated with higher DD&A rate fields.


•	General and administrative increased $8.7 million due to $8.0 million of higher stock-based compensation expense associated with certain of our market-based performance awards and $2.0 million higher professional services. The remaining changes in other general and administrative expenses were not individually significant.

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Gain (Loss) on Sale of Assets

An aggregate gain of $3.8 million was recognized in the third quarter of 2015 primarily due to the sale of certain of our oil and gas properties in east Texas. There were no individually significant gains or losses on the sale of assets recognized in the third quarter of 2016.

Interest Expense

Interest expense decreased $3.0 million due to lower interest charges of $2.1 million associated with the repayment of the outstanding borrowings under our revolving credit facility in March 2016, which remained undrawn through September 30, 2016. Interest expense also decreased $1.1 million as a result of the repurchase of a portion of our 6.51% weighted-average senior notes in May 2016. These decreases were offset by a $0.4 million increase in commitment fees as a result of an increase in the unused portion of the commitments under our revolving credit facility.

Income Tax Expense (Benefit)

Income tax benefit decreased $2.0 million primarily due to a lower pretax loss, partially offset by a higher effective tax rate. The effective tax rates for the third quarter of 2016 and 2015 were 43.9% and 39.2%, respectively. The increase in the effective tax rate is primarily due to an increase in the blended state statutory tax rate as a result of changes in our state apportionment factors in the states in which we operate.

First Nine Months of 2016 and 2015 Compared

We reported a net loss in the first nine months of 2016 of $124.4 million, or $0.27 per share, compared to net loss of $2.8 million, or $0.01 per share, in the first nine months of 2015. The increase in net loss was primarily due to lower operating revenues, partially offset by lower operating expenses and interest expense and a higher income tax benefit.

Revenue, Price and Volume Variances

Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.



	Nine Months Ended September 30,					Variance
Revenue Variances (In thousands)	2016			2015		Amount			Percent
Natural gas	$	711,010		$	807,960	$	(96,950	)	(12	)%
Crude oil and condensate	114,610			202,804		(88,194		)	(43	)%
Gain (loss) on derivative instruments	(1,286		)	44,668		(45,954		)	(103	)%
Brokered natural gas	9,417			12,650		(3,233		)	(26	)%
Other	5,435			8,277		(2,842		)	(34	)%
	$	839,186		$	1,076,359	$	(237,173	)	(22	)%

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	Nine Months Ended September 30,				Variance					Increase (Decrease) (In thousands)
	2016		2015		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	1.61	$	1.91	$	(0.30	)	(16	)%	$	(132,476	)
Crude oil and condensate	$	35.92	$	48.00	$	(12.08	)	(25	)%	(38,514		)
Total										$	(170,990	)
Volume Variances
Natural gas (Bcf)	441.8		423.2		18.6			4	%	$	35,526
Crude oil and condensate (Mbbl)	3,190		4,225		(1,035		)	(24	)%	(49,680		)
Total										$	(14,154	)

Natural Gas Revenues

The decrease in natural gas revenues of $97.0 million was due to lower natural gas prices, partially offset by higher production. The increase in production was a result of our drilling and completion activities in Pennsylvania, partially offset by the divestiture of certain oil and gas properties in east Texas in February 2016.

Crude Oil and Condensate Revenues

The decrease in crude oil and condensate revenues of $88.2 million was due to lower production and crude oil prices. The decrease in production was a result of a decrease in drilling and completion activities in south Texas.

Impact of Derivative Instruments on Operating Revenues



	Nine Months Ended September 30,
(In thousands)	2016			2015
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	3,204		$	133,827
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(4,490		)	(89,159		)
	$	(1,286	)	$	44,668

Brokered Natural Gas



	Nine Months Ended September 30,				Variance					Price and Volume Variances (In thousands)
	2016		2015		Amount			Percent		Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	2.38	$	3.03	$	(0.65	)	(21	)%	$	(2,570	)
Volume brokered (Mmcf)	x	3,954	x	4,176	(222		)	(5	)%	(663		)
Brokered natural gas (In thousands)	$	9,417	$	12,650						$	(3,233	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	1.90	$	2.31	$	(0.41	)	(18	)%	$	(1,621	)
Volume brokered (Mmcf)	x	3,954	x	4,176	(222		)	(5	)%	(496		)
Brokered natural gas (In thousands)	$	7,526	$	9,643						$	(2,117	)

Brokered natural gas margin (In thousands)	$	1,891	$	3,007						$	(1,116	)

The $1.1 million decrease in brokered natural gas margin is a result of a decrease in sales price that outpaced the decrease in purchase price and lower brokered volumes.

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Operating and Other Expenses



	Nine Months Ended September 30,						Variance
(In thousands)	2016			2015			Amount			Percent
Operating and Other Expenses
Direct operations	$	77,139		$	106,947		$	(29,808	)	(28	)%
Transportation and gathering	322,883			321,652			1,231			—	%
Brokered natural gas	7,526			9,643			(2,117		)	(22	)%
Taxes other than income	23,737			34,298			(10,561		)	(31	)%
Exploration	13,109			18,960			(5,851		)	(31	)%
Depreciation, depletion and amortization	448,910			472,335			(23,425		)	(5	)%
General and administrative	68,399			53,611			14,788			28	%
	$	961,703		$	1,017,446		$	(55,743	)	(5	)%

Earnings (loss) on equity method investments	$	208		$	4,581		$	(4,373	)	(95	)%
Gain (loss) on sale of assets	(768		)	3,814			(4,582		)	(120	)%
Loss on debt extinguishment	4,709			—			4,709			100	%
Interest expense	67,821			72,244			(4,423		)	(6	)%
Income tax expense (benefit)	(71,243		)	(2,169		)	(69,074		)	3,185	%

Total costs and expenses from operations decreased by $55.7 million, or 5%, in the first nine months of 2016 compared to the same period of 2015. The primary reasons for this fluctuation are as follows:


•	Direct operations decreased $29.8 million largely due to improved operational efficiencies, cost reductions from service providers and suppliers in 2016 compared to 2015 and the divestiture of certain oil and gas properties in east Texas in February 2016.


•	Transportation and gathering increased $1.2 million due to higher throughput as a result of higher Marcellus Shale production and the commencement of various transportation and gathering agreements in the Marcellus Shale throughout 2015.


•	Brokered natural gas decreased $2.1 million. See the preceding table titled “Brokered Natural Gas” for further analysis.

•

Taxes other than income decreased $10.6 million due to $6.6 million lower production taxes primarily resulting from lower crude oil prices and production in south Texas and the receipt of a production tax refund of $1.9 million in February 2016. Additionally, drilling impact fees decreased $2.3 million as a result of drilling fewer wells in Pennsylvania during 2016 compared to 2015 and ad valorem taxes decreased $1.7 million as a result of lower property values primarily in south Texas. The remaining changes in taxes other than income were not individually significant.


•	Exploration decreased $5.9 million as a result of charges related to the release of certain drilling rig contracts in south Texas and $2.4 million lower geophysical and geological costs and other exploration expenses. In the first nine months of 2016, we recorded rig termination charges of $1.7 million, compared to $5.1 million in the first nine months of 2015.

•

Depreciation, depletion and amortization decreased $23.4 million, of which $28.5 million was due to a lower DD&A rate of $0.89 per Mcfe for the first nine months of 2016 compared to $0.96 per Mcfe for the first nine months of 2015, partially offset by an $11.0 million increase due to higher equivalent production volumes. The lower DD&A rate was primarily due to lower cost reserve additions and the impairment charge recorded in the fourth quarter of 2015 associated with higher DD&A rate fields. In addition, amortization of unproved properties decreased $5.5 million in the first nine months of 2016 as a result of lower lease acquisition costs and lower amortization rates.


•	General and administrative increased $14.8 million due to higher stock-based compensation expense of $11.4 million primarily due to an increase in the Company's stock price during the first nine months of 2016 compared

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to the first nine months of 2015, $5.1 million higher legal expenses and $1.8 million higher professional services. These increases were offset by a $2.9 million decrease in employee-related expenses. The remaining changes in other general and administrative expenses were not individually significant.

Loss on Debt Extinguishment

A $4.7 million extinguishment loss was recognized in the second quarter of 2016 related to the premium paid for the repurchase of a portion of the our 6.51% weighted-average senior notes in May 2016 and the write-off of a portion of the associated deferred financing costs due to early repayment.

Gain (Loss) on Sale of Assets

An aggregate gain of $3.8 million was recognized in the first nine months of 2015 primarily due to the sale of certain of our oil and gas properties in east Texas. There were no individually significant gains or losses on the sale of assets recognized during the first nine months of 2016.

Interest Expense

Interest expense decreased $4.4 million due to a $3.2 million decrease resulting from the repayment of the outstanding borrowings under our revolving credit facility in March 2016, which remained undrawn through September 30, 2016. Interest expense also decreased $1.7 million resulting from the repurchase of a portion of our 6.51% weighted-average senior notes in May 2016. These decreases were offset by a $0.7 million increase in commitment fees as a result of an increase in the unused portion of the commitments under our revolving credit facility.

Income Tax Expense (Benefit)

Income tax benefit increased $69.1 million due to a higher pretax loss, partially offset by a lower effective tax rate. The effective tax rates for the first nine months of 2016 and 2015 were 36.4% and 43.9%, respectively. The decrease in the effective tax rate is primarily due to the impact of non-recurring discrete items recorded during the first nine months of 2016 versus the first nine months of 2015.

Forward-Looking Information

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 filings. See “Risk Factors” in Item 1A of the Form 10-K 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.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Market Risk

Our primary market risk is exposure to natural gas and crude oil prices. Realized prices are mainly driven by worldwide prices for crude oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

Derivative Instruments and Risk Management Activities

Our risk management strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets through the use of commodity derivatives. A committee that consists of members of senior management oversees our hedging activities. Our commodity derivatives generally cover a portion of our production and provide only partial price protection by limiting the benefit to us of increases in prices, while protecting us in the event of price declines. Further, if any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our commodity derivatives. Please read the discussion below as well as Note 6 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivative and risk management activities.

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Periodically, we enter into commodity derivatives, including collar and swap agreements, to protect against exposure to price declines related to our natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity derivatives other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

As of September 30, 2016, we had the following outstanding commodity derivatives:



				Collars									Basis Swaps		Estimated Fair Value Asset (Liability) (In thousands)
				Floor				Ceiling			Swaps		Basis Swaps
Type of Contract	Volume		Contract Period	Range		Weighted- Average		Range	Weighted- Average		Weighted- Average		Weighted- Average
Natural gas	7.5	Bcf	Oct. 2016								$	2.51			$	(3,721	)
Natural gas	35.5	Bcf	Jan. 2017 - Dec. 2017								$	3.12			(2,009		)
Natural gas	35.5	Bcf	Jan. 2017 - Dec. 2017	$	—	$	3.09	$3.42-$3.45	$	3.43					1,545
Natural gas	17.7	Bcf	Jan. 2018 - Dec. 2019										$	0.42	1,134
Crude oil	0.5	Mmbbl	Oct. 2016 - Dec. 2016	$	—	$	38.00	$47.10-$47.50	$	47.28					(1,440		)
															$	(4,491	)

In the table above, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.

The amounts set forth in the table above represent our derivative position at September 30, 2016 and exclude the impact of non-performance risk. Non-performance risk is considered in the fair value of our derivative instruments that are recorded in our Condensed Consolidated Financial Statements and is primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.

During the first nine months of 2016, natural gas swaps covered 44.4 Mcf, or 10%, of natural gas production at an average price of $2.51 per Mcf. Crude oil collars with floor prices of $38.00 per Bbl and ceiling prices ranging from $47.10 to $47.50 per Bbl covered 0.9 Mmbbl, or 29%, of crude oil production at an average price of $45.01 per Bbl.

We are exposed to market risk on commodity derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future commodity prices. See “Forward-Looking Information” for further details.

Fair Value of Other Financial Instruments

We use available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt is the estimated amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all senior notes and the revolving credit facility is based on interest rates currently available to us.

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The carrying amount and fair value of debt is as follows:



	September 30, 2016				December 31, 2015
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount			Estimated Fair Value
Debt, net	$	1,520,190	$	1,507,258	$	2,016,139		$	1,839,530
Current maturities	—		—		(20,000		)	(20,378		)
Long-term debt, excluding current maturities	$	1,520,190	$	1,507,258	$	1,996,139		$	1,819,152

ITEM 4. Controls and Procedures

As of September 30, 2016, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company's internal control over financial reporting that occurred during the third quarter of 2016 that have materially affected, or are reasonably likely to materially effect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

The information set forth under the heading “Legal Matters” in Note 8 of the Notes to Condensed Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

Environmental Matters

On November 12, 2015, we received a proposed Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (PaDEP) relating to gas migration allegations in an area surrounding several wells owned and operated by us in Susquehanna County, Pennsylvania. The allegations relating to these wells were initially raised by residents in the area in August 2011. We received a Notice of Violation from the PaDEP in September 2011 for failure to prevent the migration of gas into fresh groundwater sources in the area surrounding these wells. Since then, we have been engaged with the PaDEP in investigating the incident and have performed appropriate remediation efforts, including the provision of alternative sources of drinking water to affected residents. We believe the source of methane has been remediated and are working with the PaDEP to reach agreement on the disposition of this matter. The proposed Consent Order and Agreement is the culmination of this effort and, if finalized, would result in the payment of a civil monetary penalty in an amount likely to exceed $100,000, up to approximately $300,000. We will continue to work with the PaDEP to finalize the Consent Order and Agreement and bring this matter to a close.

From time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions individually or in the aggregate in excess of $100,000.

ITEM 1A. Risk Factors

For additional information about the risk factors that affect us, see Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2015.

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ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. The maximum number of remaining shares that may be purchased under the plan as of September 30, 2016 was 10.1 million shares.

ITEM 6. Exhibits



Exhibit Number		Description

3.1		Amended and Restated Bylaws of Cabot Oil & Gas Corporation (Form 8-K dated July 29, 2016).

31.1		302 Certification — Chairman, President and Chief Executive Officer.

31.2		302 Certification — Executive Vice President and Chief Financial Officer.

32.1		906 Certification.

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

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 thereunto duly authorized.



	CABOT OIL & GAS CORPORATION
	(Registrant)

October 28, 2016	By:	/s/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

October 28, 2016	By:	/s/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

October 28, 2016	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Controller
		(Principal Accounting Officer)

Coterra Energy - 10-Q quarterly report FY2016 Q3

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