Coterra Energy - 10-Q quarterly report FY2017 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, 2017

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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth 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)		Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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 23, 2017, there were 462,508,414 shares of Common Stock, Par Value $0.10 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, 2017 and December 31, 2016		3

Condensed Consolidated Statement of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2017 and 2016		4

Condensed Consolidated Statement of Comprehensive Income (Unaudited) for the Three and Nine Months Ended September 30, 2017 and 2016		5

Condensed Consolidated Statement of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2017 and 2016		6

Notes to the Condensed Consolidated Financial Statements		7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32

Item 4.	Controls and Procedures	33

Part II. Other Information

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

Item 6.	Exhibits	34

Signatures		35

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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, 2017			December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	510,256		$	498,542
Accounts receivable, net	161,690			191,045
Income taxes receivable	26,963			10,298
Inventories	12,997			13,304
Other current assets	6,123			2,692
Total current assets	718,029			715,881
Properties and equipment, net (Successful efforts method)	4,234,772			4,250,125
Equity method investments	148,920			129,524
Other assets	27,045			27,039
	$	5,128,766		$	5,122,569
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	160,789		$	168,411
Current portion of long-term debt	237,000			—
Accrued liabilities	27,314			21,492
Interest payable	12,331			27,650
Derivative instruments	800			40,259
Total current liabilities	438,234			257,812
Long-term debt, net	1,284,551			1,520,530
Deferred income taxes	638,014			579,447
Asset retirement obligations	59,605			131,733
Postretirement benefits	27,360			36,259
Other liabilities	36,408			29,121
Total liabilities	2,484,172			2,554,902

Commitments and contingencies

Stockholders' equity
Common stock:
Authorized — 960,000,000 shares of $0.10 par value in 2017 and 2016, respectively
Issued — 475,443,335 shares and 475,042,692 shares in 2017 and 2016, respectively	47,544			47,504
Additional paid-in capital	1,738,656			1,727,310
Retained earnings	1,230,002			1,098,703
Accumulated other comprehensive income	3,482			985
Less treasury stock, at cost:
12,935,926 and 9,892,680 shares in 2017 and 2016, respectively	(375,090		)	(306,835		)
Total stockholders' equity	2,644,594			2,567,667
	$	5,128,766		$	5,122,569

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)	2017			2016			2017			2016
OPERATING REVENUES
Natural gas	$	323,319		$	260,200		$	1,152,089		$	711,010
Crude oil and condensate	56,913			37,777			144,528			114,610
Gain (loss) on derivative instruments	(836		)	6,904			46,353			(1,286		)
Brokered natural gas	3,528			3,641			12,260			9,417
Other	2,492			1,907			8,486			5,435
	385,416			310,429			1,363,716			839,186
OPERATING EXPENSES
Direct operations	26,282			24,626			78,185			77,139
Transportation and gathering	117,891			105,671			361,909			322,883
Brokered natural gas	2,797			2,939			10,262			7,526
Taxes other than income	9,194			8,771			26,562			23,737
Exploration	6,466			2,988			16,623			13,109
Depreciation, depletion and amortization	146,267			139,490			425,689			448,910
Impairment of oil and gas properties	—			—			68,555			—
General and administrative	23,244			19,374			70,902			67,192
	332,141			303,859			1,058,687			960,496
Earnings (loss) on equity method investments	(1,417		)	(1,727		)	(3,986		)	208
Loss on sale of assets	(11,872		)	(1,245		)	(13,498		)	(768		)
INCOME (LOSS) FROM OPERATIONS	39,986			3,598			287,545			(121,870		)
Interest expense, net	20,331			21,483			61,720			67,821
Loss on debt extinguishment	—			—			—			4,709
Other expense (income)	(5,083		)	402			(4,974		)	1,207
Income (loss) before income taxes	24,738			(18,287		)	230,799			(195,607		)
Income tax expense (benefit)	7,151			(8,027		)	85,965			(71,243		)
NET INCOME (LOSS)	$	17,587		$	(10,260	)	$	144,834		$	(124,364	)

Earnings (loss) per share
Basic	$	0.04		$	(0.02	)	$	0.31		$	(0.27	)
Diluted	$	0.04		$	(0.02	)	$	0.31		$	(0.27	)

Weighted-average common shares outstanding
Basic	462,498			465,149			464,194			454,060
Diluted	464,780			465,149			466,010			454,060

Dividends per common share	$	0.05		$	0.02		$	0.12		$	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 COMPREHENSIVE INCOME (Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2017			2016			2017			2016
Net income (loss)	$	17,587		$	(10,260	)	$	144,834		$	(124,364	)
Postretirement benefits:
Net gain (loss) ⁽¹⁾	(1,429		)	—			(1,429		)	—
Prior service credit ⁽²⁾	5,449			—			5,449			—
Amortization of prior service cost ⁽³⁾	(1,551		)	17			(1,523		)	52
Amortization of (gain) net loss ⁽⁴⁾	287			—			—			—
Total other comprehensive income	2,756			17			2,497			52
Comprehensive income (loss)	$	20,343		$	(10,243	)	$	147,331		$	(124,312	)


(1)	Net of income taxes of $837 for the three and nine months ended September 30, 2017.


(2)	Net of income taxes of $(3,194) for the three months and nine months ended September 30, 2017.


(3)	Net of income taxes of $909 and $(10) for the three months ended September 30, 2017 and 2016, respectively, and $893 and $(31) for the nine months ended September 30, 2017 and 2016, respectively.


(4)	Net of income taxes of $(168) for the three months ended September 30, 2017.

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)	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	144,834		$	(124,364	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	425,689			448,910
Impairment of oil and gas properties	68,555			—
Deferred income tax expense (benefit)	89,731			(59,413		)
Loss on sale of assets	13,498			768
Exploratory dry hole cost	2,842			18
(Gain) loss on derivative instruments	(46,353		)	1,286
Net cash received in settlement of derivative instruments	3,587			3,204
(Earnings) loss on equity method investments	3,986			(208		)
Amortization of debt issuance costs	3,579			3,888
Stock-based compensation and other	26,011			23,051
Changes in assets and liabilities:
Accounts receivable, net	29,276			(1,135		)
Income taxes	(16,665		)	(11,235		)
Inventories	(2,100		)	2,860
Other current assets	(896		)	(917		)
Accounts payable and accrued liabilities	(5,133		)	(12,174		)
Interest payable	(15,318		)	(17,618		)
Other assets and liabilities	(6,076		)	784
Net cash provided by operating activities	719,047			257,705
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(586,813		)	(245,033		)
Proceeds from sale of assets	32,711			49,068
Investment in equity method investments	(23,382		)	(24,176		)
Net cash used in investing activities	(577,484		)	(220,141		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	—			90,000
Repayments of debt	—			(587,000		)
Treasury stock repurchases	(68,255		)	—
Sale of common stock, net	—			995,279
Dividends paid	(55,707		)	(26,885		)
Tax withholdings on stock award vestings	(5,929		)	(5,056		)
Capitalized debt issuance costs	—			(3,223		)
Other	42			—
Net cash provided by (used in) financing activities	(129,849		)	463,115
Net increase in cash and cash equivalents	11,714			500,679
Cash and cash equivalents, beginning of period	498,542			514
Cash and cash equivalents, end of period	$	510,256		$	501,193

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, 2016 (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 had no impact on previously reported stockholders' equity, net income (loss) or cash flows, except as discussed in "Recently Adopted Accounting Pronouncements" below.

Recently Adopted Accounting Pronouncements

Stock-Based Compensation. In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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. 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 elected to apply this guidance on a prospective basis.

The Company adopted this guidance effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits resulted in a cumulative-effect adjustment of $42.2 million, which increased retained earnings and decreased net deferred tax liabilities by the same amount as of the beginning of 2017. Effective January 1, 2017, cash paid by the Company when directly withholding shares from employee awards for tax-withholding purposes will be classified as a financing activity. This change has been recognized retrospectively beginning January 1, 2015. Prior periods have been adjusted as follows:



	Net Cash Provided by Operating Activities				Net Cash Provided by Financing Activities
(In thousands)	As Reported		As Adjusted		As Reported		As Adjusted
Year ended December 31, 2015	$	740,737	$	749,598	$	232,157	$	223,296
Three months ended March 31, 2016	62,090		67,112		570,773		565,751
Six months ended June 30, 2016	147,244		152,290		497,474		492,428
Nine months ended September 30, 2016	252,649		257,705		468,171		463,115
Year ended December 31, 2016	392,377		397,441		458,869		453,805

The remaining provisions of this amendment did not have a material effect on the Company's financial position, results of operations or cash flows.

Accounting Changes and Error Corrections. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately. The Company adopted this guidance during the first quarter of 2017. The adoption of this guidance impacted the Company's disclosures but had no effect on its financial position, results of operations or cash flows.

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Retirement Benefits. In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715). The amendments in this update require that an employer report the service cost component of postretirement benefits in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in this update also allow only the service cost component to be eligible for capitalization when applicable. The amendments in this update should be applied retrospectively for the presentation of the service cost component and the other components of net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic benefit cost in assets.

The guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. The Company elected to early adopt this guidance effective January 1, 2017. The reclassification of interest and amortization of prior service cost resulted in an increase in operating income and an increase in other expense (non-operating expense) of $1.6 million and $1.4 million for the years ended December 31, 2016 and 2015, respectively, and $1.2 million for the nine months ended September 30, 2016.

Recently Issued Accounting Pronouncements

Financial Instruments. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall, as an amendment to ASC Subtopic 825-10. The amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Among other items, this update will simplify the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment. When a qualitative assessment indicates that impairment exists, an entity is required to measure the investment at fair value. This impairment assessment reduces the complexity of the other-than-temporary impairment guidance that entities follow currently. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption of this amendment is not permitted. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, results of operation or cash flows.

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 is to be adopted using a modified retrospective approach. The Company plans to adopt this guidance 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. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which clarifies the guidance or corrects unintended application of guidance.

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The Company plans to adopt this guidance effective January 1, 2018 using the modified retrospective method applied to contracts that are not completed as of that date. To date, the Company has not identified changes to its revenue recognition policies that would result in a material adjustment to the opening balance of retained earnings on January 1, 2018; however, it is continuing to evaluate the effect, if any, that adopting this guidance will have on its financial position, results of operations or cash flows. The Company is also evaluating its agreements with royalty and nonoperated partners for principal versus agent consideration. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue. As allowed under Topic 606, the Company does not plan to disclose the value of unsatisfied performance obligations for contracts with variable consideration or with an original term of one year or less.

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 ASU must be adopted using a retrospective transition method.

Upon adopting this guidance, the Company will be required to make an accounting policy election to classify distributions it receives from its equity method investees under either (1) the cumulative earnings approach in which distributions received are considered returns on investment and classified as cash inflows from operating activities unless the cumulative distributions received exceed cumulative equity in earnings recognized by the Company, or (2) the nature of distributions approach in which distributions received are classified on the basis of the nature of the activity that generated the distribution as either a return on investment (cash inflows from operating activities) or a return of investment (cash inflows from investing activities). The Company has not yet determined which policy election it will make. Currently, the Company is not receiving any distributions from its equity method investees; therefore, the selection between the policy elections would not have a material effect on its presentation of cash flows. If material distributions are received in the future, the impact of the policy election could be material. The Company expects to adopt this guidance effective January 1, 2018 and is currently evaluating the effect that adopting the remaining areas of this guidance will have on its presentation of cash flows. Adoption of this guidance is not expected to have a material effect on the Company's financial position or results of operations.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:



(In thousands)	September 30, 2017			December 31, 2016
Proved oil and gas properties	$	6,967,205		$	7,437,604
Unproved oil and gas properties	287,147			260,543
Gathering and pipeline systems	1,451			187,846
Land, building and other equipment	88,371			84,462
	7,344,174			7,970,455
Accumulated depreciation, depletion and amortization	(3,109,402		)	(3,720,330		)
	$	4,234,772		$	4,250,125

Proved oil and gas properties, gathering and pipeline systems and accumulated depreciation, depletion and amortization decreased from December 31, 2016 to September 30, 2017 primarily as a result of the sale of assets in West Virginia, Virginia and Ohio discussed below.

At September 30, 2017, the Company did not have any projects that had exploratory well costs capitalized for a period of greater than one year after drilling.

Divestitures

In September 2017, the Company sold certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio for $41.3 million, subject to customary purchase price adjustments. During the second quarter of 2017, the Company classified these assets as held for sale and recorded an impairment charge of $68.6 million associated with the proposed sale of these properties. Upon closing the sale in the third quarter of 2017, the Company recognized a loss on sale of oil and gas properties of $11.9 million.

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The fair value of the impaired properties was determined using a market approach that took into consideration the expected sales price included in the purchase and sale agreement the Company executed on June 30, 2017. Accordingly, the inputs associated with the fair value of these assets were considered Level 3 in the fair value hierarchy. Refer to Note 1 of the Notes to the Consolidated Financial Statements in the Form 10-K for a description of the fair value hierarchy.

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 resulting in a $0.5 million gain on sale of assets.

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,
(In thousands)	2017			2016		2017			2016			2017			2016
Balance at beginning of period	$	96,850		$	90,345	$	32,674		$	13,172		$	129,524		$	103,517
Contributions	3,750			8,325		19,632			15,851			23,382			24,176
Earnings (loss) on equity method investments	(3,971		)	211		(15		)	(3		)	(3,986		)	208
Balance at end of period	$	96,629		$	98,881	$	52,291		$	29,020		$	148,920		$	127,901

During 2017, the Company expects to contribute approximately $70.0 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

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 126-mile route. During the 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. On March 16, 2017, the U.S. District Court for the Northern District of New York issued an order ruling, without prejudice, that it lacked subject matter jurisdiction to hear Constitution’s complaint. On August 18, 2017, the Second Circuit issued a decision denying in part and dismissing in part Constitution’s appeal. The Second Circuit determined that it lacked jurisdiction to address Constitution’s argument that the NYSDEC waived its ability to issue a Certification by unreasonably delaying action on Constitution's application. Instead, the Second Circuit found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. The Second Circuit, however, rejected Constitution’s assertion that the denial of the Certification by the NYSDEC was “arbitrary and capricious” and denied Constitution’s complaint in that regard. On October 11, 2017, Constitution filed a petition for a declaratory order requesting the Federal Energy Regulatory Commission (FERC) to find that, by operation of law, the Section 401 Water Quality Certification requirement for the New York State portion of the pipeline project was waived due to the failure of the NYSDEC to act on Constitution’s application within a reasonable period of time, as required by the Clean Water Act. The FERC has not yet ruled on this petition.

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 current status of the litigation and the regulatory challenges, Constitution estimates its target in-service date to be as early as the first half of 2019. This assumes the timely receipt of a notice to proceed from the FERC and the timely receipt of all other state and federal permits required for the project.

In light of the NYSDEC’s denial and actions taken to challenge the denial, the Company evaluated its investment in Constitution for other-than-temporary impairment (OTTI) as of September 30, 2017 and does not believe there is an indication of an OTTI. The Company’s evaluation considered various factors, including but not limited to prior FERC approval and the related economic viability of the project, the pending legal and regulatory actions filed by Constitution 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 proportionate to its ownership interest for the development and construction of the new pipeline. As of September 30, 2017, the Company has made contributions of $92.3 million since inception of the project.

4. Debt and Credit Agreements

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



(In thousands)	September 30, 2017			December 31, 2016
Total debt
6.51% weighted-average senior notes	$	361,000		$	361,000
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
Current maturities
6.51% weighted-average senior notes	(237,000		)	—
Long-term debt, excluding current maturities	$	1,291,000		$	1,528,000
Unamortized debt issuance costs	(6,449		)	(7,470		)
	$	1,284,551		$	1,520,530

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 11, 2017, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively.

At September 30, 2017, the Company was in compliance with all restrictive financial covenants for both its revolving credit facility and senior notes. As of September 30, 2017, 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, 2017, the Company had no borrowings outstanding under its revolving credit facility and had unused commitments of $1.7 billion. The Company’s weighted-average effective interest rate for the revolving credit facility for the nine months ended September 30, 2016 was approximately 2.3%.

5. Derivative Instruments and Hedging Activities

As of September 30, 2017, 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 - NYMEX	8.9	Bcf	Oct. 2017 - Dec. 2017								$	3.12
Natural gas - TCO	4.5	Bcf	Oct. 2017 - Dec. 2017								$	3.46
Natural gas - NYMEX	8.9	Bcf	Oct. 2017 - Dec. 2017	$	—	$	3.09	$3.42-$3.45	$	3.43
Natural gas - Transco	21.3	Bcf	Jan. 2018 - Dec. 2019										$	0.42
Crude oil	0.5	Mmbbl	Oct. 2017 - Dec. 2017	$	—	$	50.00	$56.25-$56.50	$	56.39

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

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Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet



		Derivative Assets				Derivative Liabilities
(In thousands)	Balance Sheet Location	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016
Commodity contracts	Other current assets	$	2,536	$	—	$	—	$	—
Commodity contracts	Other assets (non-current)	3,763		2,991		—		—
Commodity contracts	Derivative instruments (current)	—		—		800		40,259
		$	6,299	$	2,991	$	800	$	40,259

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



(In thousands)	September 30, 2017			December 31, 2016
Derivative assets
Gross amounts of recognized assets	$	6,605		$	2,991
Gross amounts offset in the statement of financial position	(306		)	—
Net amounts of assets presented in the statement of financial position	6,299			2,991
Gross amounts of financial instruments not offset in the statement of financial position	18			—
Net amount	$	6,317		$	2,991

Derivative liabilities
Gross amounts of recognized liabilities	$	1,106		$	40,259
Gross amounts offset in the statement of financial position	(306		)	—
Net amounts of liabilities presented in the statement of financial position	800			40,259
Gross amounts of financial instruments not offset in the statement of financial position	—			757
Net amount	$	800		$	41,016

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2017			2016			2017		2016
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	3,906		$	(8,101	)	$	3,587	$	3,204
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(4,742		)	15,005			42,766		(4,490		)
	$	(836	)	$	6,904		$	46,353	$	(1,286	)

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.

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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, 2017
Assets
Deferred compensation plan	$	14,336	$	—	$	—	$	14,336
Derivative instruments	—		—		6,605		6,605
Total assets	$	14,336	$	—	$	6,605	$	20,941
Liabilities
Deferred compensation plan	$	27,598	$	—	$	—	$	27,598
Derivative instruments	—		178		928		1,106
Total liabilities	$	27,598	$	178	$	928	$	28,704



(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, 2016
Assets
Deferred compensation plan	$	12,587	$	—	$	—	$	12,587
Derivative instruments	—		—		2,991		2,991
Total assets	$	12,587	$	—	$	2,991	$	15,578
Liabilities
Deferred compensation plan	$	24,169	$	—	$	—	$	24,169
Derivative instruments	—		21,400		18,859		40,259
Total liabilities	$	24,169	$	21,400	$	18,859	$	64,428

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 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.

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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)	2017			2016
Balance at beginning of period	$	(15,868	)	$	—
Total gain (loss) included in earnings	28,659			381
Settlement (gain) loss	(7,114		)	83
Transfers in and/or out of level 3	—			—
Balance at end of period	$	5,677		$	464

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	14,431		$	464

There were no transfers between Level 1 and Level 2 fair value measurements for the nine months ended September 30, 2017 and 2016.

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. The Company recorded an impairment charge related to certain oil and gas properties during the quarter ended June 30, 2017. Refer to Note 2 of the Notes to the Condensed Consolidated Financial Statements for additional disclosures related to fair value associated with the impaired assets. As none of the Company’s other non-financial assets and liabilities were measured at fair value as of September 30, 2017, additional disclosures were not required.

The estimated fair value of the Company’s asset retirement obligations 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.

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



	September 30, 2017						December 31, 2016
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value
Debt, net	$	1,521,551		$	1,536,360		$	1,520,530	$	1,463,643
Current maturities	(237,000		)	(243,569		)	—		—
Long-term debt, excluding current maturities	$	1,284,551		$	1,292,791		$	1,520,530	$	1,463,643

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7. Asset Retirement Obligations

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



(In thousands)	Nine Months Ended September 30, 2017
Balance at beginning of period	$	133,733
Liabilities incurred	3,788
Liabilities settled	(1,225		)
Liabilities divested	(75,014		)
Accretion expense	4,396
Balance at end of period	$	65,678

As of September 30, 2017 and December 31, 2016, approximately $6.1 million and $2.0 million, respectively, is included in accrued liabilities in the Condensed Consolidated Balance Sheet, which represents the current portion of the Company's asset retirement obligation.

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,” “Lease Commitments” and “Hydraulic Fracturing Services Commitments” as disclosed in Note 9 in the Notes to Consolidated Financial Statements 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.

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9. Employee Benefit Plans

Postretirement Benefits

The change in the Company's postretirement benefit obligation is as follows:



(In thousands)	Nine Months Ended September 30, 2017			Year Ended December 31, 2016
Change in Benefit Obligation
Benefit obligation at beginning of the period	$	37,482		$	36,626
Service cost	1,163			2,323
Interest cost	810			1,498
Actuarial (gain) loss	3,084			(2,846		)
Benefits paid	(817		)	(934		)
Curtailment (gain) loss	(4,185		)	—
Plan amendments	(8,643		)	815
Benefit obligation at end of the period	28,894			37,482
Change in Plan Assets
Fair value of plan assets at end of the period	—			—
Funded status at end of the period	$	(28,894	)	$	(37,482	)

In September 2017, in conjunction with its sale of properties located in West Virginia, Virginia and Ohio, the Company terminated approximately 100 employees. As a result, the employees’ participation in the postretirement plan terminated, which resulted in a remeasurement and curtailment of the postretirement benefit obligation at September 30, 2017.

The change in benefit obligation for the nine months ended September 30, 2017 also reflects a plan amendment for the Company's change from a Medicare Supplemental program to a Medicare Advantage program for participants age 65 and older. This coverage continues to be provided under a fully-insured arrangement.

Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income (Loss)



	Nine Months Ended September 30,
(In thousands)	2017			2016
Components of Net Periodic Postretirement Benefit Cost
Service cost	$	1,163		$	1,743
Interest cost	810			1,123
Amortization of prior service cost (credit)	(934		)	83
Net periodic postretirement cost	$	1,039		$	2,949
Recognized curtailment (gain) loss	(4,850		)	—
Total postretirement cost (benefit)	$	(3,811	)	$	2,949
Other Changes in Benefit Obligations Recognized in Other Comprehensive Income (Loss)
Net (gain) loss	$	2,266		$	—
Amortization of prior service cost	2,416			(83		)
Prior service credit	(8,643		)	—
Total recognized in other comprehensive income	$	(3,961	)	$	(83	)

Total recognized in net periodic benefit cost and other comprehensive income (loss)	$	(7,772	)	$	2,866

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Assumptions

Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:



(In thousands)	September 30, 2017		December 31, 2016
Discount rate	4.00	%	4.30	%
Health care cost trend rate for medical benefits assumed for next year (pre-65)	7.75	%	7.50	%
Health care cost trend rate for medical benefits assumed for next year (post-65)	6.00	%	5.00	%
Ultimate trend rate (pre-65)	4.50	%	4.50	%
Ultimate trend rate (post-65)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate (pre-65)	2030		2023
Year that the rate reaches the ultimate trend rate (post-65)	2023		2018

10. Capital Stock

Treasury Stock

In August 1998, the Board of Directors authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. The timing and amount of any stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs currently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase common stock of the Company.

During the first nine months of 2017, the Company repurchased 3.0 million shares for a total cost of $68.3 million. Since the authorization date, the Company has repurchased 32.9 million shares of the 40.0 million total shares authorized for a total cost of approximately $456.6 million, of which 20.0 million shares have been retired. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. As of September 30, 2017, 12.9 million shares were held as treasury stock.

11. 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 associated with these awards was $7.8 million and $5.1 million in the third quarter of 2017 and 2016, respectively, and $26.2 million and $23.0 million during the first nine months of 2017 and 2016, respectively. Stock-based compensation expense is included in general and administrative expense in the Condensed Consolidated Statement of Operations.

As described in Note 1 to the Condensed Consolidated Financial Statements, effective January 1, 2017, the Company adopted ASU No. 2016-09, which requires that excess tax benefits and tax deficiencies on stock-based compensation be recorded in the income statement. During the first nine months of 2017, the Company recorded an increase to tax expense of $2.6 million in the Condensed Consolidated Statement of Operations as a result of book compensation cost for employee stock-based compensation exceeding the federal and state tax deductions for awards that vested during the period.

Prior to the adoption of ASU No. 2016-09, windfall tax benefits were recorded in additional paid in capital in the Condensed Consolidated Balance Sheet and tax shortfalls reduced additional paid in capital to the extent they offset previously recorded windfall tax benefits. 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 was recorded in additional paid in capital in the Condensed Consolidated Balance Sheet. The tax shortfall was 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.

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.

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Restricted Stock Units

During the first nine months of 2017, 57,028 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date value of $22.94 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 during the first nine months of 2017 commenced on January 1, 2017 and ends on December 31, 2019. 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, 2017, 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 2017, 406,460 Employee Performance Share Awards were granted at a grant date value of $22.60 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 2017, 272,920 Hybrid Performance Share Awards were granted at a grant date value of $22.60 per share. The 2017 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.

TSR Performance Share Awards. During the first nine months of 2017, 409,380 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 22, 2017) and the period-end fair value of the liability component of the TSR Performance Share Awards:



	Grant Date			September 30, 2017
Fair value per performance share award	$	19.85		$12.28-$20.22
Assumptions:
Stock price volatility	37.8		%	20.8% - 39.9%
Risk free rate of return	1.4		%	1.1% - 1.5%

12. 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 are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

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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)	2017	2016	2017	2016
Weighted-average shares - basic	462,498	465,149	464,194	454,060
Dilution effect of stock appreciation rights and stock awards at end of period	2,282	—	1,816	—
Weighted-average shares - diluted	464,780	465,149	466,010	454,060

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)	2017	2016	2017	2016
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect due to net loss	—	1,784	—	1,326
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method	2	—	6	1
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect	2	1,784	6	1,327

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13. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:



(In thousands)	September 30, 2017			December 31, 2016
Accounts receivable, net
Trade accounts	$	162,069		$	185,594
Joint interest accounts	1,208			1,359
Other accounts	425			5,335
	163,702			192,288
Allowance for doubtful accounts	(2,012		)	(1,243		)
	$	161,690		$	191,045

Inventories
Tubular goods and well equipment	$	12,130		$	11,005
Natural gas in storage	867			2,299
	$	12,997		$	13,304

Other current assets
Prepaid balances and other	$	3,587		$	2,692
Derivative instruments	2,536			—
	$	6,123		$	2,692

Other assets
Deferred compensation plan	$	14,336		$	12,587
Debt issuance costs	8,845			11,403
Derivative instruments	3,763			2,991
Other accounts	101			58
	$	27,045		$	27,039

Accounts payable
Trade accounts	$	25,851		$	27,355
Natural gas purchases	3,457			2,231
Royalty and other owners	33,135			36,472
Accrued transportation	48,104			48,977
Accrued capital costs	33,440			34,647
Taxes other than income	12,938			13,827
Other accounts	3,864			4,902
	$	160,789		$	168,411

Accrued liabilities
Employee benefits	$	17,065		$	14,153
Taxes other than income	4,018			3,829
Asset retirement obligations	6,073			2,000
Other accounts	158			1,510
	$	27,314		$	21,492

Other liabilities
Deferred compensation plan	$	27,598		$	24,169
Other accounts	8,810			4,952
	$	36,408		$	29,121

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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, 2017 and 2016 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, 2016 (Form 10-K).

OVERVIEW

Financial and Operating Overview

Financial and operating results for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 are as follows:


•	Equivalent production increased 49.7 Bcfe, or 11%, from 463.0 Bcfe, or 1,689.6 Mmcfe per day, in 2016 to 512.7 Bcfe, or 1,877.9 Mmcfe per day, in 2017.


•	Natural gas production increased 49.4 Bcf, or 11%, from 441.8 Bcf in 2016 to 491.2 Bcf in 2017, as a result of drilling and completion activities in Pennsylvania.


•	Crude oil/condensate/NGL production increased 0.1 Mmbbls, or 2%, from 3.5 Mmbbls in 2016 to 3.6 Mmbbls in 2017, as result of an increase in drilling and completion activity in south Texas partially offset by a natural decline in production.


•	Average realized natural gas price was $2.35 per Mcf, 45% higher than the $1.62 per Mcf realized in the comparable period of the prior year.


•	Average realized crude oil price was $45.70 per Bbl, 27% higher than the $35.85 per Bbl realized in the comparable period of the prior year.


•	Total capital expenditures were $582.8 million compared to $262.1 million in the comparable period of the prior year.


•	Drilled 71 gross wells (62.5 net) with a success rate of 98.6% compared to 28 gross wells (28.0 net) with a success rate of 100% for the comparable period of the prior year.


•	Completed 81 gross wells (70.2 net) in 2017 compared to 51 gross wells (51.0 net) in 2016.


•	Average rig count during 2017 was approximately 2.0 rigs in the Marcellus Shale, approximately 1.0 rig in the Eagle Ford Shale and approximately 0.2 rigs in other areas, compared to an average rig count in the Marcellus Shale of approximately 1.1 rigs and approximately 0.3 rigs in the Eagle Ford Shale in 2016.


•	Received proceeds of $32.7 million primarily related to the divestiture of certain oil and gas properties and related pipeline assets in West Virginia, Virginia and Ohio.


•	Repurchased 3.0 million shares of our common stock for a total cost of $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. Location differentials have improved in certain regions, such as in the Appalachian region, resulting in further increases in natural gas prices. As a result, we cannot accurately predict future commodity prices and, therefore, 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. 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.

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, we will

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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 2017 compared to the fourth quarter of 2016. 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.

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


•	Continuing to exercise discipline in our capital program with the expectation of funding our capital expenditures with cash on hand, operating cash flows, and if required, borrowings under our revolving credit facility.


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


•	Continuing to manage our balance sheet, which provides 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

Based on the expectation for higher operating cash flow due to an improvement in the commodity price outlook, we increased our 2017 budgeted capital expenditures compared to 2016. Our full year 2017 capital spending program includes approximately $775.0 million in capital expenditures related to our drilling and completion program, leasehold acquisitions and contributions of approximately $70.0 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 drilled 40 gross wells (38.0 net) and completed 76 gross wells (76.0 net), of which 62 gross wells (62.0 net) were drilled but uncompleted in prior years. In 2017, we plan to drill 100 gross wells (95.0 net) and complete 95 gross wells (90.0 net), of which 51 gross wells (45.0 net) were drilled but uncompleted in prior years. In 2017, we plan to operate an average of approximately 3.0 rigs, an increase from an average of approximately 1.4 rigs in 2016. 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, 2017 were from 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), interest payments on debt, repurchase of shares of our common stock and payment of dividends. See below for additional discussion and analysis of cash flow.

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 divestitures of oil and gas properties. Effective April 11, 2017, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively. There were no borrowings outstanding under our revolving credit facility as of September 30, 2017.

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 existing cash on hand, operating cash flow and availability under our revolving credit facility, we have the capacity to fund our spending plans.

At September 30, 2017, we were in compliance with all restrictive financial covenants for both the revolving credit facility and senior notes. As of September 30, 2017, 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.

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Cash Flows

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



	Nine Months Ended September 30,
(In thousands)	2017			2016
Cash flows provided by operating activities	$	719,047		$	257,705
Cash flows used in investing activities	(577,484		)	(220,141		)
Cash flows provided by (used in) financing activities	(129,849		)	463,115
Net increase in cash and cash equivalents	$	11,714		$	500,679

Operating Activities. Operating cash flow fluctuations are substantially driven by commodity prices, 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, basis differentials, inventory storage levels and seasonal influences. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures. 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.

Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit facility, repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, sales and repurchases of our securities 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, 2017 and December 31, 2016, we had a working capital surplus of $279.8 million and $458.1 million, respectively.

Net cash provided by operating activities in the first nine months of 2017 increased by $461.3 million compared to the first nine months of 2016. This increase was primarily due to higher operating revenues, partially offset by higher cash operating expenses. The increase in operating revenues was primarily due to an increase in realized natural gas and crude oil prices and higher equivalent production. Average realized natural gas and crude oil prices increased by 45% and 27%, respectively, for the first nine months of 2017 compared to the first nine months of 2016. Equivalent production increased by 11% for the first nine months of 2017 compared to the first nine months of 2016 driven by higher natural gas production in the Marcellus Shale.

See “Results of Operations” for additional information relative to commodity price, production and operating expense fluctuations.

Investing Activities. Cash flows used in investing activities increased by $357.3 million for the first nine months of 2017 compared to the first nine months of 2016. The increase was due to $341.8 million higher capital expenditures and $16.4 million lower proceeds from the sale of assets, partially offset by $0.8 million lower capital contributions associated with our equity method investments.

Financing Activities. Cash flows provided by financing activities decreased by $593.0 million for the first nine months of 2017 compared to the first nine months of 2016. This decrease was primarily due to $995.3 million lower net proceeds from the issuance of common stock in 2016, $68.3 million of repurchases of our common stock in 2017 and $28.8 million of higher dividend payments related to an increase in the dividend rate and the issuance of common stock in 2016. These decreases were partially offset by $497.0 million of lower 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 in 2016.

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Capitalization

Information about our capitalization is as follows:



(In thousands)	September 30, 2017			December 31, 2016
Debt ⁽¹⁾	$	1,521,551		$	1,520,530
Stockholders' equity	2,644,594			2,567,667
Total capitalization	$	4,166,145		$	4,088,197
Debt to total capitalization	37		%	37		%
Cash and cash equivalents	$	510,256		$	498,542


(1)	Includes $237.0 million of current portion of long-term debt at September 30, 2017.

During the first nine months of 2017, we repurchased 3.0 million shares of our common stock for $68.3 million. We also paid dividends of $55.7 million ($0.12 per share) on our common stock. In May 2017, the Board of Directors approved an increase in the quarterly dividend on our common stock from $0.02 per share to $0.05 per share.

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.

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



	Nine Months Ended September 30,
(In thousands)	2017		2016
Capital expenditures
Drilling and facilities	$	475,240	$	255,139
Leasehold acquisitions	97,835		1,687
Pipeline and gathering	597		1,009
Other	9,091		4,251
	582,763		262,086
Exploration expenditures	16,623		13,109
Total	$	599,386	$	275,195

For the full year of 2017, we plan to drill approximately 100 gross wells (95.0 net) and complete 95 gross wells (90.0 net), of which 51 gross wells (45.0 net) were drilled but uncompleted in prior years. In 2017, our drilling program includes approximately $775.0 million in total capital expenditures compared to $372.5 million in 2016. See “Outlook” 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.

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,” “Lease Commitments” and “Hydraulic Fracturing Services 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

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reported amounts of assets, liabilities, revenues and expenses. See our Form 10-K for further discussion of our critical accounting policies.

Recently Adopted and Recently Issued 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 2017 and 2016 Compared

We reported net income in the third quarter of 2017 of $17.6 million, or $0.04 per share, compared to a net loss of $10.3 million, or $0.02 per share, in the third quarter of 2016. The increase in net income was primarily due to higher operating revenues, partially offset by higher operating expenses, loss on sale of assets and income tax expense.

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)	2017			2016		Amount			Percent
Natural gas	$	323,319		$	260,200	$	63,119		24	%
Crude oil and condensate	56,913			37,777		19,136			51	%
Gain (loss) on derivative instruments	(836		)	6,904		(7,740		)	(112	)%
Brokered natural gas	3,528			3,641		(113		)	(3	)%
Other	2,492			1,907		585			31	%
	$	385,416		$	310,429	$	74,987		24	%



	Three Months Ended September 30,				Variance				Increase (Decrease) (In thousands)
	2017		2016		Amount		Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	2.01	$	1.80	$	0.21	12	%	$	32,879
Crude oil and condensate	$	44.88	$	40.13	$	4.75	12	%	6,013
Total									$	38,892
Volume Variances
Natural gas (Bcf)	161.2		144.4		16.8		12	%	$	30,240
Crude oil and condensate (Mbbl)	1,268		941		327		35	%	13,123
Total									$	43,363

Natural Gas Revenues

The increase in natural gas revenues of $63.1 million was due to higher natural gas prices and production. The increase in production was a result of an increase in our drilling and completion activities in Pennsylvania.

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Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $19.1 million was due to higher crude oil prices and production. The increase in production was a result of an increase in our drilling and completion activities in south Texas.

Impact of Derivative Instruments on Operating Revenues



	Three Months Ended September 30,
(In thousands)	2017			2016
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	3,906		$	(8,101	)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(4,742		)	15,005
	$	(836	)	$	6,904

Brokered Natural Gas



	Three Months Ended September 30,				Variance					Price and Volume Variances (In thousands)
	2017		2016		Amount			Percent		Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	2.61	$	2.85	$	(0.24	)	(8	)%	$	(327	)
Volume brokered (Mmcf)	x	1,354	x	1,279	75			6	%	214
Brokered natural gas (In thousands)	$	3,528	$	3,641						$	(113	)

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.07	$	2.30	$	(0.23	)	(10	)%	$	(315	)
Volume brokered (Mmcf)	x	1,354	x	1,279	75			6	%	173
Brokered natural gas (In thousands)	$	2,797	$	2,939						$	(142	)

Brokered natural gas margin (In thousands)	$	731	$	702						$	29

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Operating and Other Expenses



	Three Months Ended September 30,						Variance
(In thousands)	2017			2016			Amount			Percent
Operating and Other Expenses
Direct operations	$	26,282		$	24,626		$	1,656		7	%
Transportation and gathering	117,891			105,671			12,220			12	%
Brokered natural gas	2,797			2,939			(142		)	(5	)%
Taxes other than income	9,194			8,771			423			5	%
Exploration	6,466			2,988			3,478			116	%
Depreciation, depletion and amortization	146,267			139,490			6,777			5	%
General and administrative	23,244			19,374			3,870			20	%
	$	332,141		$	303,859		$	28,282		9	%

Earnings (loss) on equity method investments	$	(1,417	)	$	(1,727	)	$	310		(18	)%
Loss on sale of assets	(11,872		)	(1,245		)	(10,627		)	854	%
Interest expense, net	20,331			21,483			(1,152		)	(5	)%
Other expense (income)	(5,083		)	402			(5,485		)	(1,364	)%
Income tax expense (benefit)	7,151			(8,027		)	15,178			189	%

Total costs and expenses from operations increased by $28.3 million, or 9%, in the third quarter of 2017 compared to the same period of 2016. The primary reasons for this fluctuation are as follows:


•	Direct operations increased $1.7 million largely due to an increase in operating costs primarily driven by higher production, partially offset by improved operational efficiencies.


•	Transportation and gathering increased $12.2 million due to higher throughput as a result of higher Marcellus Shale production.


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


•	Taxes other than income increased $0.4 million primarily due to $0.9 million higher production taxes resulting from higher crude oil prices and production in south Texas, partially offset by $0.6 million lower drilling impact fees as a result of lower rates. The remaining changes in taxes other than income were not individually significant.


•	Exploration increased $3.5 million primarily as a result of higher geophysical costs of $2.0 million

•

Depreciation, depletion and amortization increased $6.8 million, primarily due to higher amortization of unproved properties of $9.4 million, partially offset by lower DD&A of $1.4 million in the third quarter of 2017. The increase in amortization of unproved properties is primarily due to an increase in leasing activity and an increase in amortization rates. The decrease in DD&A was due to a decrease of $17.3 million due to a lower DD&A rate of $0.75 per Mcfe for the third quarter of 2017 compared to $0.85 per Mcfe for the third quarter of 2016 primarily due to positive reserve revisions and the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia in 2016, partially offset by an increase of $15.8 million associated with higher equivalent production primarily in Pennsylvania for the third quarter of 2017 compared to the third quarter of 2016.

•

General and administrative increased $3.9 million due to $3.2 million of severance costs for employees terminated as a result of the sale of properties located in West Virginia, Virginia and Ohio and $2.7 million of higher stock-based compensation expense associated with certain of our market-based performance awards, partially offset by $2.0 million lower professional services. The remaining changes in other general and administrative expenses were not individually significant.

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Earnings (Loss) on Equity Method Investments

The increase in loss on equity method investments is a result of our proportionate share of net loss from our equity method investments in 2017 compared to 2016.

Loss on Sale of Assets

Loss on sale of assets increased $10.6 million due to the Company's sale of certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio in the third quarter of 2017.

Other Expense (Income)

Other income increased $5.5 million primarily due to the curtailment gain on postretirement benefits as a result of the termination of approximately 100 employees in West Virginia, Virginia and Ohio.

Interest Expense, net

Interest expense, net decreased $1.2 million due to $0.8 million higher interest income.

Income Tax Expense (Benefit)

Income tax expense increased $15.2 million primarily due to higher pretax income, partially offset by a lower effective tax rate. The effective tax rates for the third quarter of 2017 and 2016 were 28.9% and 43.9%, respectively. The decrease in the effective tax rate is primarily due to a decrease in the blended state statutory tax rate as a result of changes in our state apportionment factors in the states in which we operate, as well as non-recurring discrete items recorded during the third quarter of 2017 versus the third quarter of 2016.

First Nine Months of 2017 and 2016 Compared

We reported net income in the first nine months of 2017 of $144.8 million, or $0.31 per share, compared to a net loss of $124.4 million, or $0.27 per share, in the first nine months of 2016. The increase in net income was primarily due to higher operating revenues, partially offset by higher operating expenses, loss on sale of assets and income tax expense.

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)	2017		2016			Amount		Percent
Natural gas	$	1,152,089	$	711,010		$	441,079	62	%
Crude oil and condensate	144,528		114,610			29,918		26	%
Gain (loss) on derivative instruments	46,353		(1,286		)	47,639		3,704	%
Brokered natural gas	12,260		9,417			2,843		30	%
Other	8,486		5,435			3,051		56	%
	$	1,363,716	$	839,186		$	524,530	63	%



	Nine Months Ended September 30,				Variance				Increase (Decrease) (In thousands)
	2017		2016		Amount		Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	2.35	$	1.61	$	0.74	46	%	$	361,545
Crude oil and condensate	$	45.13	$	35.92	$	9.21	26	%	29,451
Total									$	390,996
Volume Variances
Natural gas (Bcf)	491.2		441.8		49.4		11	%	$	79,534
Crude oil and condensate (Mbbl)	3,203		3,190		13		—	%	467
Total									$	80,001

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Natural Gas Revenues

The increase in natural gas revenues of $441.1 million was due to higher natural gas prices and production. The increase in production was a result of an increase in our drilling and completion activities in Pennsylvania.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $29.9 million was primarily due to higher crude oil prices.

Impact of Derivative Instruments on Operating Revenues



	Nine Months Ended September 30,
(In thousands)	2017		2016
Cash received (paid) on settlement of derivative instruments
Gain on derivative instruments	$	3,587	$	3,204
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	42,766		(4,490		)
	$	46,353	$	(1,286	)

Brokered Natural Gas



	Nine Months Ended September 30,				Variance					Price and Volume Variances (In thousands)
	2017		2016		Amount			Percent		Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)	$	3.17	$	2.38	$	0.79		33	%	$	3,038
Volume brokered (Mmcf)	x	3,872	x	3,954	(82		)	(2	)%	(195		)
Brokered natural gas (In thousands)	$	12,260	$	9,417						$	2,843

Brokered Natural Gas Purchases
Purchase price ($/Mcf)	$	2.65	$	1.90	$	0.75		39	%	$	2,892
Volume brokered (Mmcf)	x	3,872	x	3,954	(82		)	(2	)%	(156		)
Brokered natural gas (In thousands)	$	10,262	$	7,526						$	2,736

Brokered natural gas margin (In thousands)	$	1,998	$	1,891						$	107

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Operating and Other Expenses



	Nine Months Ended September 30,						Variance
(In thousands)	2017			2016			Amount			Percent
Operating and Other Expenses
Direct operations	$	78,185		$	77,139		$	1,046		1	%
Transportation and gathering	361,909			322,883			39,026			12	%
Brokered natural gas	10,262			7,526			2,736			36	%
Taxes other than income	26,562			23,737			2,825			12	%
Exploration	16,623			13,109			3,514			27	%
Depreciation, depletion and amortization	425,689			448,910			(23,221		)	(5	)%
Impairment of oil and gas properties	68,555			—			68,555			100	%
General and administrative	70,902			67,192			3,710			6	%
	$	1,058,687		$	960,496		$	98,191		10	%

Earnings (loss) on equity method investments	$	(3,986	)	$	208		$	(4,194	)	2,016	%
Loss on sale of assets	(13,498		)	(768		)	(12,730		)	1,658	%
Interest expense, net	61,720			67,821			(6,101		)	(9	)%
Loss on debt extinguishment	—			4,709			(4,709		)	(100	)%
Other expense (income)	(4,974		)	1,207			(6,181		)	(512	)%
Income tax expense (benefit)	85,965			(71,243		)	157,208			221	%

Total costs and expenses from operations increased by $98.2 million, or 10%, in the first nine months of 2017 compared to the same period of 2016. The primary reasons for this fluctuation are as follows:


•	Direct operations increased $1.0 million largely due to an increase in operating costs primarily driven by higher production, partially offset by improved operational efficiencies, cost reductions from service providers and suppliers in 2017 compared to 2016.


•	Transportation and gathering increased $39.0 million due to higher throughput as a result of higher Marcellus Shale production.


•	Brokered natural gas increased $2.7 million. See the preceding table titled “Brokered Natural Gas” for further analysis.

•

Taxes other than income increased $2.8 million due to $3.4 million higher production taxes primarily resulting from higher natural gas and crude oil prices and an increase in drilling impact fees of $1.9 million due to an increase in drilling activity in Pennsylvania. These increases were offset by a decrease of $2.4 million in ad valorem taxes as a result of lower property values primarily in south Texas.

•

Exploration increased $3.5 million as a result of higher dry hole costs of $2.8 million in 2017 and $2.6 million higher geophysical costs, partially offset by lower charges related to the release of certain drilling rig contracts in south Texas. In the first nine months of 2016, we recorded rig termination charges of $1.7 million. We recorded no rig termination charges in the first nine months of 2017.

•

Depreciation, depletion and amortization decreased $23.2 million, primarily due to lower DD&A of $38.0 million, partially offset by higher amortization of unproved properties of $15.9 million in 2017. The decrease in DD&A was due to a decrease of $82.5 million due to a lower DD&A rate of $0.73 per Mcfe for the first nine months of 2017 compared to $0.89 per Mcfe for the first nine months of 2016, partially offset by a $44.5 million increase due to higher equivalent production volumes. The lower DD&A rate was primarily due to positive reserve revisions and the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia in 2016. The increase in amortization of unproved properties is primarily due to the ongoing evaluation of our unproved properties and an increase in leasing activity.

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•	Impairment of oil and gas properties was $68.6 million in 2017 due to the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia.

•

General and administrative increased $3.7 million due to $3.4 million higher employee-related expenses, $3.2 million of higher stock-based compensation expense associated with certain of our market-based performance awards and $3.2 million of severance costs for employees terminated as a result of its sale of properties located in West Virginia, Virginia and Ohio. These increases were partially offset by $6.8 million lower professional services. The remaining changes in other general and administrative expenses were not individually significant.

Earnings (Loss) on Equity Method Investments

The increase in loss on equity method investments is the result of our proportionate share of net earnings from our equity method investments in 2017 compared to 2016.

Loss on Sale of Assets

Loss on sale of assets increased $12.7 million due to the Company's sale of certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio in the third quarter of 2017.

Other Expense (Income)

Other income increased $6.2 million primarily due to the curtailment gain on postretirement benefits as a result of the termination of approximately 100 employees in West Virginia, Virginia and Ohio.

Interest Expense, net

Interest expense, net decreased $6.1 million primarily due to a $1.4 million increase in interest income and a $2.1 million decrease resulting from the repayment of the outstanding borrowings under our revolving credit facility in March 2016, which has remained undrawn through September 30, 2017. Interest expense also decreased $2.4 million resulting from the repurchase of $64.0 million of our 6.51% weighted-average senior notes in May 2016 and the repayment of $20.0 million of our 7.33% weighted-average senior notes in July 2016.

Loss on Debt Extinguishment

A $4.7 million debt extinguishment loss was recognized in the second quarter of 2016 related to the premium paid for the repurchase of a portion of 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.

Income Tax Expense (Benefit)

Income tax expense increased $157.2 million due to higher pretax income and a higher effective tax rate. The effective tax rates for the first nine months of 2017 and 2016 were 37.2% and 36.4%, 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 and the impact of excess tax benefits and tax deficiencies on shares vesting during the period as a result of the adoption of ASU No. 2016-09 in January 2017, partially offset by non-recurring discrete items recorded during the first nine months of 2017 versus the first nine months of 2016.

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,” “target,” “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.

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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 can be 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 risk management 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.

Periodically, we enter into commodity derivatives including collar, swap and basis 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, 2017, 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 - NYMEX	8.9	Bcf	Oct. 2017 - Dec. 2017								$	3.12			$	(177	)
Natural gas - TCO	4.5	Bcf	Oct. 2017 - Dec. 2017								$	3.46			2,322
Natural gas - NYMEX	8.9	Bcf	Oct. 2017 - Dec. 2017	$	—	$	3.09	$3.42-$3.45	$	3.43					261
Natural gas - Transco	21.3	Bcf	Jan. 2018 - Dec. 2019										$	0.42	2,858
Crude oil	0.5	Mmbbl	Oct. 2017 - Dec. 2017	$	—	$	50.00	$56.25-$56.50	$	56.39					259
															$	5,523

In the above table, 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 total unrealized derivative position at September 30, 2017 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 with which we have derivative contracts, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.

During the first nine months of 2017, natural gas collars with floor prices of $3.09 per Mcf and ceiling prices ranging from $3.42 to $3.45 per Mcf covered 26.5 Bcf, or 5%, of natural gas production at an average price of $3.23 per Mcf. Natural gas swaps covered 38.3 Bcf, or 8%, of natural gas production at an average price of $3.23 per Mcf. Crude oil collars with floor prices of $50.00 per Bbl and ceiling prices ranging from $56.25 to $56.50 per Bbl covered 1.4 Mmbbl, or 43%, of crude oil production at an average price of $50.77 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

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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.

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



	September 30, 2017						December 31, 2016
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value
Debt, net	$	1,521,551		$	1,536,360		$	1,520,530	$	1,463,643
Current maturities	(237,000		)	(243,569		)	—		—
Long-term debt, excluding current maturities	$	1,284,551		$	1,292,791		$	1,520,530	$	1,463,643

ITEM 4. Controls and Procedures

As of September 30, 2017, 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 2017 that have materially affected, or are reasonably likely to materially effect, the Company's internal control over financial reporting.

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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

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, 2016.

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, 2017 was 7.1 million shares.

ITEM 6. Exhibits



Exhibit Number		Description

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 30, 2017	By:	/s/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

October 30, 2017	By:	/s/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

October 30, 2017	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Vice President and Controller
		(Principal Accounting Officer)

Coterra Energy - 10-Q quarterly report FY2017 Q3

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