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~~2018

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,~~25, 2018, there were ~~462,508,414~~431,179,872 shares of Common Stock, Par Value $0.10 Per Share, outstanding.

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~~2018 and December 31, ~~2016~~2017		3

Condensed Consolidated Statement of Operations (Unaudited) for the Three and Nine Months Ended September 30, ~~2017~~2018 and ~~2016~~2017		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~~2018 and ~~2016~~2017		65

Notes to the Condensed Consolidated Financial Statements		76

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2118

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3227

Item 4.	Controls and Procedures	3329

Part II. Other Information

Item 1.	Legal Proceedings	3429

Item 1A.	Risk Factors	3430

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3430

Item 6.	Exhibits	3430

Signatures		3531

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			September 30, 2018			December 31, 2017
ASSETS
Current assets
Cash and cash equivalents	$	510,256		$	498,542		$	316,077		$	480,047
Accounts receivable, net	161,690			191,045			222,827			216,004
Income taxes receivable	26,963			10,298			65,792			56,666
Inventories	12,997			13,304			12,476			8,006
Current assets held for sale							—			1,440
Other current assets	6,123			2,692			2,692			2,794
Total current assets	718,029			715,881			619,864			764,957
Properties and equipment, net (Successful efforts method)	4,234,772			4,250,125			3,366,237			3,072,204
Equity method investments	148,920			129,524			157,934			86,077
Assets held for sale							6,114			778,855
Derivative instruments							1,248			2,239
Other assets	27,045			27,039			27,646			23,012
	$	5,128,766		$	5,122,569		$	4,179,043		$	4,727,344
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	160,789		$	168,411		$	263,623		$	238,045
Current portion of long-term debt	237,000			—			67,000			304,000
Accrued liabilities	27,314			21,492			15,453			27,441
Interest payable	12,331			27,650			9,101			27,575
Derivative instruments	800			40,259			10,921			30,637
Current liabilities held for sale							—			2,352
Total current liabilities	438,234			257,812			366,098			630,050
Long-term debt, net	1,284,551			1,520,530			1,218,848			1,217,891
Deferred income taxes	638,014			579,447			358,708			227,030
Asset retirement obligations	59,605			131,733			48,205			43,601
Liabilities held for sale							381			15,748
Postretirement benefits	27,360			36,259			30,769			29,396
Other liabilities	36,408			29,121			61,887			39,723
Total liabilities	2,484,172			2,554,902			2,084,896			2,203,439

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
Authorized — 960,000,000 shares of $0.10 par value in 2018 and 2017, respectively
Issued — 476,089,105 shares and 475,547,419 shares in 2018 and 2017, respectively							47,609			47,555
Additional paid-in capital	1,738,656			1,727,310			1,756,337			1,742,419
Retained earnings	1,230,002			1,098,703			1,362,797			1,162,430
Accumulated other comprehensive income	3,482			985			2,112			2,077
Less treasury stock, at cost:
12,935,926 and 9,892,680 shares in 2017 and 2016, respectively	(375,090		)	(306,835		)
42,080,250 shares and 14,935,926 shares in 2018 and 2017, respectively							(1,074,708		)	(430,576		)
Total stockholders' equity	2,644,594			2,567,667			2,094,147			2,523,905
	$	5,128,766		$	5,122,569		$	4,179,043		$	4,727,344

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

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.~~

~~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.~~



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands, except per share amounts)	2018			2017			2018			2017
OPERATING REVENUES
Natural gas	$	440,835		$	323,319		$	1,217,603		$	1,152,089
Crude oil and condensate	—			56,913			48,722			144,528
Gain (loss) on derivative instruments	(3,537		)	(836		)	(1,628		)	46,353
Brokered natural gas	105,849			3,528			203,375			12,260
Other	2,026			2,492			3,775			8,486
	545,173			385,416			1,471,847			1,363,716
OPERATING EXPENSES
Direct operations	17,030			26,282			52,757			78,185
Transportation and gathering	129,534			117,891			355,848			361,909
Brokered natural gas	93,405			2,797			178,437			10,262
Taxes other than income	2,852			9,194			15,434			26,562
Exploration	10,049			6,466			68,166			16,623
Depreciation, depletion and amortization	121,172			146,267			288,210			425,689
Impairment of oil and gas properties	—			—			—			68,555
General and administrative	20,724			23,244			66,013			70,902
	394,766			332,141			1,024,865			1,058,687
Loss on equity method investments	(11		)	(1,417		)	(1,009		)	(3,986		)
Gain (loss) on sale of assets	25,655			(11,872		)	(14,850		)	(13,498		)
INCOME FROM OPERATIONS	176,051			39,986			431,123			287,545
Interest expense, net	14,191			20,331			57,577			61,720
Other expense (income)	115			(5,083		)	347			(4,974		)
Income before income taxes	161,745			24,738			373,199			230,799
Income tax expense	39,408			7,151			91,201			85,965
NET INCOME	$	122,337		$	17,587		$	281,998		$	144,834

Earnings per share
Basic	$	0.28		$	0.04		$	0.63		$	0.31
Diluted	$	0.28		$	0.04		$	0.62		$	0.31

Weighted-average common shares outstanding
Basic	440,772			462,498			450,445			464,194
Diluted	443,110			464,780			452,313			466,010

Dividends per common share	$	0.06		$	0.05		$	0.18		$	0.12

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

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)


	Nine Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2017			2016			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	144,834		$	(124,364	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Net income							$	281,998		$	144,834
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	425,689			448,910			288,210			425,689
Impairment of oil and gas properties	68,555			—			—			68,555
Deferred income tax expense (benefit)	89,731			(59,413		)
Deferred income tax expense							131,799			89,731
Loss on sale of assets	13,498			768			14,850			13,498
Exploratory dry hole cost	2,842			18			56,425			2,842
(Gain) loss on derivative instruments	(46,353		)	1,286			1,628			(46,353		)
Net cash received in settlement of derivative instruments	3,587			3,204
(Earnings) loss on equity method investments	3,986			(208		)
Net cash received (paid) in settlement of derivative instruments							(20,354		)	3,587
Loss on equity method investments							1,009			3,986
Amortization of debt issuance costs	3,579			3,888			3,521			3,579
Stock-based compensation and other	26,011			23,051			16,472			26,011
Changes in assets and liabilities:
Accounts receivable, net	29,276			(1,135		)	(7,345		)	29,276
Income taxes	(16,665		)	(11,235		)	(14,447		)	(16,665		)
Inventories	(2,100		)	2,860			(5,326		)	(2,100		)
Other current assets	(896		)	(917		)	104			(896		)
Accounts payable and accrued liabilities	(5,133		)	(12,174		)	32,192			(5,133		)
Interest payable	(15,318		)	(17,618		)	(18,474		)	(15,318		)
Other assets and liabilities	(6,076		)	784			26,590			(6,076		)
Net cash provided by operating activities	719,047			257,705			788,852			719,047
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(586,813		)	(245,033		)	(647,503		)	(586,813		)
Proceeds from sale of assets	32,711			49,068			675,525			32,711
Investment in equity method investments	(23,382		)	(24,176		)	(72,866		)	(23,382		)
Net cash used in investing activities	(577,484		)	(220,141		)	(44,844		)	(577,484		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	—			90,000
Repayments of debt	—			(587,000		)	(237,000		)	—
Treasury stock repurchases	(68,255		)	—			(581,725		)	(68,255		)
Sale of common stock, net	—			995,279
Dividends paid	(55,707		)	(26,885		)	(81,185		)	(55,707		)
Tax withholdings on stock award vestings	(5,929		)	(5,056		)
Capitalized debt issuance costs	—			(3,223		)
Tax withholdings on vesting of stock awards							(8,068		)	(5,929		)
Other	42			—			—			42
Net cash provided by (used in) financing activities	(129,849		)	463,115
Net increase in cash and cash equivalents	11,714			500,679
Net cash used in financing activities							(907,978		)	(129,849		)
Net increase (decrease) in cash and cash equivalents							(163,970		)	11,714
Cash and cash equivalents, beginning of period	498,542			514			480,047			498,542
Cash and cash equivalents, end of period	$	510,256		$	501,193		$	316,077		$	510,256

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

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~~10-K/A for the year ended December 31, ~~2016~~2017 (Form ~~10-K)~~10-K/A) 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.~~10-K/A. 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.~~flows.

Recently Adopted Accounting Pronouncements

~~Stock-Based Compensation.~~ Revenue Recognition.In ~~March 2016,~~May 2014, the Financial Accounting Standards ~~Board~~Boards (FASB) issued Accounting Standards Update (ASU) No. ~~2016-09, Improvements to Employee Share-Based Payment Accounting, as an amendment to Accounting~~2014-09, Revenue from Contracts with Customers (Topic 606) (Accounting Standards Codification (ASC) 606, as subsequently amended). ASC 606 supersedes the revenue recognition requirements in Topic ~~718. The areas for simplification in this update involve several aspects~~605 Revenue Recognition (ASC 605), and requires entities to recognize revenue when control of the ~~accounting~~promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled to in exchange for ~~share-based payment transactions, including~~those goods or services. The Company adopted ASC 606 as of January 1, 2018 using 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~~ASC 606 also included the adoption and modification of other guidance, ~~impacted~~particularly the ~~Company's disclosures but had no effect~~creation of ASC 340-40 on ~~its financial position, results~~costs to obtain or fulfill contracts with customers and ASC 610-20 on gains or losses on derecognition of ~~operations~~nonfinancial assets. ASC 340-40 provides additional capitalization, amortization and impairment guidance for certain costs associated with obtaining or ~~cash flows.~~

~~Retirement Benefits~~. ~~In March 2017,~~fulfilling contracts subject to ASC 606. ASC 610-20 provides guidance on the ~~FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715).~~measurement and recognition of gains and losses for disposals of assets that are not the outputs of ordinary activities, such as sales of fixed assets, when they are not businesses or deconsolidation of subsidiaries. The ~~amendments~~guidance in ~~this update require~~ASC 610-20 largely aligns with the guidance in ASC 606. It also supersedes most guidance on real estate sales that ~~an employer report the service cost component~~was contained in ASC 360-20; however, it does not apply to conveyances 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 requiredoil and gas interests, which continue to be ~~presented~~governed by guidance in ~~the income statement separately~~ASC 932 for oil and gas extractive activities.

There was no material effect from the ~~service cost component and outside a subtotal~~adoption of ~~income~~ASC 340-40 or ASC 610-20 separate from ~~operations. The amendments in this update also allow only~~those discussed from the ~~service cost component to be eligible for capitalization when applicable. The amendments in this update should be applied retrospectively for the presentation~~adoption 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~~ASC 606.

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~~Company adopted ASU 2016-01 as of January 1, 2018. The adoption of this ~~amendment is~~guidance did not ~~permitted. The Company is currently evaluating~~have a material effect on the ~~effect that adopting this guidance will have on its~~Company's financial position, results of operation or cash flows.

Statement of Cash Flows.In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current accounting guidance is either unclear or does not include specific guidance. The Company adopted this guidance effective January 1, 2018. In conjunction with the adoption, the Company made an accounting policy election to classify distributions it receives from its equity method investees based on 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 adoption of this guidance did not have a material effect on the Company's financial position, results of operation or cash flows.

Recently Issued Accounting Pronouncements

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases ~~as a new Topic, ASC Topic 842.~~(Topic 842). The new lease guidance supersedes Topic 840. The core principle of the guidance is that ~~a company~~entities 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 by applying the transition approach as of the beginning of the period of adoption. Comparative periods will not be restated.

The Company plans to make use of the following practical expedients which are provided in the leases standard:

an election not to apply the recognition requirements in the leases standard to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise);

a package of practical expedients to not reassess whether a contract is or contains a lease, lease classification and initial direct costs;

a practical expedient to use hindsight when determining the lease term; and

a practical expedient to not reassess certain land easements in existence prior to January 1, 2019.

The Company 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,~~Recognition

On January 1, 2018, the ~~FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic,~~Company adopted 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~~and the related guidance ~~or corrects unintended application~~in ASC 340-40 (the new revenue standard), and related guidance on gains and losses on derecognition of ~~guidance.~~

~~The Company plans to adopt this guidance effective January 1, 2018~~nonfinancial assets ASC 610-20, using the modified retrospective method applied to those contracts ~~that are~~which were not completed as of ~~that date. To date,~~January 1, 2018. Under the modified retrospective method, the Company ~~has not identified changes to its~~recognizes the cumulative effect of initially applying the new revenue ~~recognition policies that would result in a material~~standard as an adjustment to the opening balance of retained ~~earnings on~~earnings; however, no significant adjustment was required as a result of adopting the new revenue standard. Results for reporting periods beginning after January 1, ~~2018; however, it~~2018 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods.

The Company’s revenue is ~~continuing~~typically generated from contracts to ~~evaluate~~sell natural gas, crude oil or NGLs produced from interests in oil and gas properties owned by the ~~effect, if any,~~Company. These contracts generally require the Company to deliver a specific amount of a commodity per day for a specified number of days at a price that ~~adopting this guidance will have on its financial position, results~~is either fixed or variable. The contracts specify a delivery point which represents the point at which control of ~~operations or cash flows.~~the product is transferred to the customer. These contracts frequently meet the definition of a derivative under ASC 815, and are accounted for as derivatives unless the Company elects to treat them as normal sales as permitted under that guidance. The Company typically elects to treat contracts to sell oil and gas production as normal sales, which are then accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point.

Revenue is ~~also evaluating~~measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the standalone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. Payment is generally received one or two months after the sale has occurred.

Gain or loss on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by the Company from a customer, are excluded from revenue.

Producer Gas Imbalances. The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties.

Production volume is monitored to minimize these natural gas imbalances. Under this method, a natural gas imbalance liability is recorded if the Company's excess takes of natural gas exceed its ~~agreements with royalty~~estimated remaining proved developed reserves for these properties at the actual price realized upon the gas sale. A receivable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at September 30, 2018 and ~~nonoperated partners for principal versus agent consideration. Adopting this guidance will result in increased disclosures~~December 31, 2017 were not material.

Brokered Natural Gas. Revenues and expenses related to ~~revenue recognition policies~~brokered natural gas are reported gross as part of operating revenues and ~~disaggregation of revenue. As allowed under Topic 606,~~operating expenses in accordance with applicable accounting standards. The Company buys and sells natural gas utilizing separate purchase and sale transactions whereby the Company ~~does not plan~~or the counterparty obtains control of the natural gas purchased or sold.

Disaggregation of Revenue. The following table presents revenues disaggregated by product:



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2018			2017			2018			2017
OPERATING REVENUES
Natural gas	$	440,835		$	323,319		$	1,217,603		$	1,152,089
Crude oil and condensate	—			56,913			48,722			144,528
Brokered natural gas	105,849			3,528			203,375			12,260
Other	2,026			2,492			3,775			8,486
Total revenues from contracts with customers	548,710			386,252			1,473,475			1,317,363
Gain (loss) on derivative instruments	(3,537		)	(836		)	(1,628		)	46,353
Total operating revenues	$	545,173		$	385,416		$	1,471,847		$	1,363,716

All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to ~~disclose~~the customer and are generated in the United States.

Transaction Price Allocated to Remaining Performance Obligations. A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

As of September 30, 2018, the Company has $9.2 billion of unsatisfied performance obligations related to natural gas sales that have a fixed pricing component and a contract term greater than one year. The Company expects to recognize these obligations over the next 10 to 20 years.

Contract Balances. Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $221.5 million and $215.5 million as of September 30, 2018 and December 31, 2017, respectively, and are reported in accounts receivable, net on the Condensed Consolidated Balance Sheet. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Practical Expedients. The Company has made use of certain practical expedients in adopting the new revenue standard, including the value of unsatisfied performance obligations are not disclosed for (i) contracts with an original expected length of one year or less, (ii) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (iii) contracts with variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only contracts that are not completed at transition.

The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or ~~with an original term of~~service to the customer and when the customer pays for that good or service will be 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.



(In thousands)	September 30, 2018			December 31, 2017
Proved oil and gas properties	$	5,489,836		$	4,932,512
Unproved oil and gas properties	199,219			190,474
Gathering and pipeline systems	1,569			1,569
Land, building and other equipment	86,953			82,670
	5,777,577			5,207,225
Accumulated depreciation, depletion and amortization	(2,411,340		)	(2,135,021		)
	$	3,366,237		$	3,072,204

At September 30, ~~2017,~~2018, 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,~~July 2018, the Company sold ~~certain proved~~its operated and ~~unproved~~non-operated oil and gas properties ~~and related pipeline assets located~~ in ~~West Virginia, Virginia and Ohio~~the Haynesville Shale for ~~$41.3~~$30.0 million. The sales price included a $5.0 million ~~subject to customary purchase price adjustments.~~deposit that was received in the fourth quarter of 2017. During the ~~second~~fourth quarter of 2017, the Company classified these assets as held for sale. The Company recognized a gain on sale of oil and gas properties of $29.5 million.

In February 2018, the Company sold its operated and non-operated Eagle Ford Shale assets for $765.0 million. During the fourth quarter of 2017, the Company classified these assets as held for sale and recorded an impairment charge of ~~$68.6~~$414.3 million associated with the proposed sale of these properties. ~~Upon closing the sale in the third quarter of 2017, the~~The Company recognized a loss on sale of oil and gas properties of ~~$11.9~~$45.2 million.

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					Constitution						Meade						Total
	Nine Months Ended September 30,																Nine Months Ended September 30,
(In thousands)	2017			2016		2017			2016			2017			2016		2018			2017			2018			2017			2018			2017
Balance at beginning of period	$	96,850		$	90,345	$	32,674		$	13,172		$	129,524		$	103,517	$	732		$	96,850		$	85,345		$	32,674		$	86,077		$	129,524
Contributions	3,750			8,325		19,632			15,851			23,382			24,176		250			3,750			72,616			19,632			72,866			23,382
Earnings (loss) on equity method investments	(3,971		)	211		(15		)	(3		)	(3,986		)	208
Loss on equity method investments																	(982		)	(3,971		)	(27		)	(15		)	(1,009		)	(3,986		)
Balance at end of period	$	96,629		$	98,881	$	52,291		$	29,020		$	148,920		$	127,901	$	—		$	96,629		$	157,934		$	52,291		$	157,934		$	148,920

During ~~2017,~~2018, 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.~~10-K/A.

~~Constitution~~Meade

~~On April 22, 2016, Constitution announced that~~In February 2014, the ~~New York State Department of Environmental Conservation (NYSDEC) denied Constitution's application for~~Company acquired 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~~20% equity interest in Meade, which was formed to participate in the ~~U.S. Court~~development and construction of ~~Appeals for the Second Circuit~~a 177-mile pipeline (Central Penn Line) that will transport natural gas from Susquehanna County, Pennsylvania to interconnect with Transcontinental Gas Pipe Line Company, LLC’s (Transco) mainline in Lancaster County, Pennsylvania. The Central Penn Line is operated by Transco and ~~the U.S. District Court for the Northern District~~is owned by Transco and Meade in proportion to their respective ownership percentages of ~~New York challenging the legality~~approximately 61% and ~~appropriateness of the NYSDEC’s decision. On March 16,~~39%, respectively. By order issued on February 3, 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~~issued Transco a certificate of ~~law,~~public convenience and necessity authorizing the ~~Section 401 Water Quality Certification requirement for the New York State portion~~construction of the ~~pipeline~~new pipeline. Subsequently on October 4, 2018, the FERC issued a notice granting Authorization to Place the Facilities into service and on October 9, 2018, Transco notified the FERC that the Central Penn Line was placed into service on October 6, 2018.

On August 14, 2018, the Company entered into a precedent agreement with Transco for up to 250,000 Dth per day of firm transportation capacity on Transco's proposed Leidy South expansion project. The Company will also be participating as an equity owner in the expansion project ~~was waived due~~through its ownership in Meade and expects to ~~the failure~~contribute approximately $17.8 million, its proportionate share 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~~anticipated costs of the ~~current status of the litigation and the regulatory challenges, Constitution estimates its target in-service date~~expansion project. The expansion project is anticipated to be in-service as early as the ~~first half~~fourth quarter of ~~2019. This assumes the~~2021, assuming all necessary regulatory approvals are received in a timely ~~receipt of a notice to proceed from the FER~~Cmanner and ~~the timely receipt of all other state and federal permits required for the project.~~ construction proceeds on schedule.

~~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~~

As of September 30, ~~2017 and does not believe there is an indication of an OTTI. The~~2018, 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.~~in Constitution is less than its proportionate share of Constitution’s net assets by $95.9 million. This basis difference is due to the Company’s impairment recorded in the fourth quarter of 2017 and relates entirely to the pipeline assets of Constitution. The Company expects to amortize this basis difference once the related assets of Constitution are placed in service, which may or may not occur, depending on the outcome of the legal and regulatory process related to certain permitting matters.

~~At this time, the~~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, 2018			December 31, 2017
Total debt
6.51% weighted-average senior notes ⁽¹⁾	$	124,000		$	361,000
9.78% senior notes ⁽²⁾	67,000			67,000
5.58% weighted-average senior notes	175,000			175,000
3.65% weighted-average senior notes	925,000			925,000
Revolving credit facility	—			—
Unamortized debt issuance costs	(5,152		)	(6,109		)
	$	1,285,848		$	1,521,891

(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


(1)	Includes $237.0 million of current portion of long-term debt at December 31, 2017, which the Company paid in July 2018.


(2)	Includes $67.0 million of current portion of long-term debt at September 30, 2018 and December 31, 2017, respectively.

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,~~18, 2018, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively. At September 30, 2018, the Company had no borrowings outstanding under its revolving credit facility and had unused commitments of $1.8 billion.

At September 30, ~~2017,~~2018, 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,~~2018, the Company had the following outstanding financial commodity derivatives:

Collars Basis Swaps
Floor Ceiling 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



						Basis Swaps
				Swaps		Basis Swaps
Type of Contract	Volume		Contract Period	Weighted-Average		Weighted-Average
Natural gas (Leidy)	8.9	Bcf	Oct. 2018 - Dec. 2018			$	(0.69	)
Natural gas (Leidy)	53.2	Bcf	Jan. 2019 - Dec. 2019			$	(0.55	)
Natural gas (Transco)	13.3	Bcf	Oct. 2018 - Dec. 2019			$	0.42
Natural gas (NYMEX)	23.2	Bcf	Oct. 2018 - Dec. 2018	$	2.93
Natural gas (NYMEX)	1.5	Bcf	Oct. 2018	$	3.10

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

Mcf.

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet


		Derivative Assets				Derivative Liabilities					Derivative Assets				Derivative Liabilities
(In thousands)	Balance Sheet Location	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016		Balance Sheet Location	September 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Commodity contracts	Other current assets	$	2,536	$	—	$	—	$	—	Derivative instruments (current)	$	—	$	—	$	10,921	$	30,637
Commodity contracts	Other assets (non-current)	3,763		2,991		—		—		Derivative instruments (non-current)	1,248		2,239		—		—
Commodity contracts	Derivative instruments (current)	—		—		800		40,259
		$	6,299	$	2,991	$	800	$	40,259		$	1,248	$	2,239	$	10,921	$	30,637

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


(In thousands)	September 30, 2017			December 31, 2016		September 30, 2018			December 31, 2017
Derivative assets
Gross amounts of recognized assets	$	6,605		$	2,991	$	1,273		$	2,239
Gross amounts offset in the statement of financial position	(306		)	—		(25		)	—
Net amounts of assets presented in the statement of financial position	6,299			2,991		1,248			2,239
Gross amounts of financial instruments not offset in the statement of financial position	18			—		—			—
Net amount	$	6,317		$	2,991	$	1,248		$	2,239

Derivative liabilities
Gross amounts of recognized liabilities	$	1,106		$	40,259	$	10,946		$	30,637
Gross amounts offset in the statement of financial position	(306		)	—		(25		)	—
Net amounts of liabilities presented in the statement of financial position	800			40,259		10,921			30,637
Gross amounts of financial instruments not offset in the statement of financial position	—			757		—			241
Net amount	$	800		$	41,016	$	10,921		$	30,878

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations


	Three Months Ended September 30,						Nine Months Ended September 30,					Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2017			2016			2017		2016			2018			2017			2018			2017
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	3,906		$	(8,101	)	$	3,587	$	3,204		$	(41	)	$	3,906		$	(20,354	)	$	3,587
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(4,742		)	15,005			42,766		(4,490		)	(3,496		)	(4,742		)	18,726			42,766
	$	(836	)	$	6,904		$	46,353	$	(1,286	)	$	(3,537	)	$	(836	)	$	(1,628	)	$	46,353

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.~~

10-K/A.

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		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, 2018
Assets
Deferred compensation plan	$	14,336	$	—	$	—	$	14,336	$	16,671	$	—	$	—	$	16,671
Derivative instruments	—		—		6,605		6,605		—		—		1,273		1,273
Total assets	$	14,336	$	—	$	6,605	$	20,941	$	16,671	$	—	$	1,273	$	17,944
Liabilities
Deferred compensation plan	$	27,598	$	—	$	—	$	27,598	$	27,835	$	—	$	—	$	27,835
Derivative instruments	—		178		928		1,106		—		4,722		6,224		10,946
Total liabilities	$	27,598	$	178	$	928	$	28,704	$	27,835	$	4,722	$	6,224	$	38,781


(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		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, 2017
Assets
Deferred compensation plan		$	12,587	$	—	$	—	$	12,587	$	14,966	$	—	$	—	$	14,966
Derivative instruments		—		—		2,991		2,991		—		—		2,239		2,239
Total assets		$	12,587	$	—	$	2,991	$	15,578	$	14,966	$	—	$	2,239	$	17,205
Liabilities
Deferred compensation plan		$	24,169	$	—	$	—	$	24,169	$	29,145	$	—	$	—	$	29,145
Derivative instruments	��	—		21,400		18,859		40,259		—		—		30,637		30,637
Total liabilities		$	24,169	$	21,400	$	18,859	$	64,428	$	29,145	$	—	$	30,637	$	59,782

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.~~counterparties or internal models. Such quotes and models 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.~~differentials. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

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


	Nine Months Ended September 30,					Nine Months Ended September 30,
(In thousands)	2017			2016		2018			2017
Balance at beginning of period	$	(15,868	)	$	—	$	(28,398	)	$	(15,868	)
Total gain (loss) included in earnings	28,659			381		6,333			28,659
Settlement (gain) loss	(7,114		)	83		17,114			(7,114		)
Transfers in and/or out of level 3	—			—		—			—
Balance at end of period	$	5,677		$	464	$	(4,951	)	$	5,677

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	14,431		$	464
Change in unrealized gain (loss) relating to assets and liabilities still held at the end of the period						$	(6,685	)	$	14,431

There were no transfers between Level 1 and Level 2 fair value measurements for the nine months ended September 30, ~~2017~~2018 and ~~2016.~~2017.

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,~~2018, 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				September 30, 2018						December 31, 2017
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value		Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
Debt, net	$	1,521,551		$	1,536,360		$	1,520,530	$	1,463,643
Long-term debt											$	1,285,848		$	1,245,971		$	1,521,891		$	1,527,624
Current maturities	(237,000		)	(243,569		)	—		—		(67,000		)	(67,679		)	(304,000		)	(312,055		)
Long-term debt, excluding current maturities	$	1,284,551		$	1,292,791		$	1,520,530	$	1,463,643	$	1,218,848		$	1,178,292		$	1,217,891		$	1,215,569

7. Asset Retirement Obligations

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



(In thousands)	Nine Months Ended September 30, 2018
Balance at beginning of period⁽¹⁾	$	48,553
Liabilities incurred	3,592
Liabilities settled	(1,025		)
Liabilities divested	(3,782		)
Accretion expense	1,867
Balance at end of period⁽²⁾	$	49,205

(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.


(1)	Includes $5.0 million of current asset retirement obligations included in accrued liabilities at December 31, 2017.


(2)	Includes $1.0 million of current asset retirement obligations included in accrued liabilities at September 30, 2018.

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”~~Agreements” and ~~“Hydraulic Fracturing Services~~"Lease Commitments” as disclosed in Note 9 inof the Notes to Consolidated Financial Statements in the Form ~~10-K.~~10-K/A.

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~~

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

~~9. 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

~~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.~~9. Capital Stock

Treasury Stock

In ~~August 1998,~~February 2018, the Board of Directors authorized aan increase of 25.0 million shares to the Company’s share repurchase program. In July 2018, the Board of Directors authorized an increase of an additional 20.0 million shares to the Company’s share repurchase program. After the most recent authorization, the total number of shares available for repurchase was 30.1 million shares. Under the 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,~~2018, the Company repurchased ~~3.0~~27.1 million shares for a total cost of ~~$68.3~~$644.2 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~~2018, 22.9 million shares are available for repurchase under the share repurchase program.

As of September 30, 2018, 42.1 million shares were held as treasury ~~stock.~~stock, which includes 2.7 million shares that were repurchased prior to September 30, 2018 and settled in October 2018.

Subsequent Event. Subsequent to September 30, 2018, the Company repurchased 2.8 million shares for a total cost of $65.6 million under a Rule 10b5-1 Plan.

In October 2018, the Board of Directors approved an increase in the quarterly dividend on our common stock from $0.06 per share to $0.07 per share.

~~11.~~10. Stock-based Compensation

General

From time to time the Company grants certain stock-based compensation awards, including restricted stock awards, restricted stock units and performance share awards. Stock-based compensation expense associated with these awards was ~~$7.8~~$6.5 million and ~~$5.1~~$7.8 million in the third quarter of ~~2017~~2018 and ~~2016,~~2017, respectively, and ~~$26.2~~$17.6 million and ~~$23.0~~$26.2 million during the first nine months of ~~2017~~2018 and ~~2016,~~2017, 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~~10-K/A for further description of the various types of stock-based compensation awards and the applicable award terms.

Restricted Stock Units

During the first nine months of ~~2017, 57,028~~2018, 80,131 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date value of ~~$22.94~~$23.45 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~~2018 commenced on January 1, ~~2017~~2018 and ends on December 31, ~~2019.~~2020. The Company used an annual forfeiture rate assumption ranging from 0% to 6%5% 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,~~2018, 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~~2018, 531,670 Employee Performance Share Awards were granted at a grant date value of ~~$22.60~~$23.25 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~~2018, 321,720 Hybrid Performance Share Awards were granted at a grant date value of ~~$22.60~~$23.25 per share. The ~~2017~~2018 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~~2018, 482,581 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)~~21, 2018) and the period-end fair value of the liability component of the TSR Performance Share Awards:


	Grant Date			September 30, 2017	Grant Date			September 30, 2018
Fair value per performance share award	$	19.85		$12.28-$20.22	$	19.92		$2.46-$12.02
Assumptions:
Stock price volatility	37.8		%	20.8% - 39.9%	37.3		%	26.1% - 29.9%
Risk free rate of return	1.4		%	1.1% - 1.5%	2.40		%	2.18% - 2.81%

~~12.~~11. Earnings per Common Share

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

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


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,
(In thousands)	2017	2016	2017	2016	2018	2017	2018	2017
Weighted-average shares - basic	462,498	465,149	464,194	454,060	440,772	462,498	450,445	464,194
Dilution effect of stock appreciation rights and stock awards at end of period	2,282	—	1,816	—	2,338	2,282	1,868	1,816
Weighted-average shares - diluted	464,780	465,149	466,010	454,060	443,110	464,780	452,313	466,010

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,		Three Months Ended September 30,		Nine Months Ended September 30,
(In thousands)	2017	2016	2017	2016	2018	2017	2018	2017
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	1	2	1	6
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect	2	1,784	6	1,327

12. Income Taxes

On December 22, 2017, the U.S. enacted tax legislation referred to as the Tax Cuts and Jobs Act (the Tax Act) which significantly changes U.S. corporate income tax laws beginning, generally, in 2018. These changes include, among others, (i) a permanent reduction of the U.S. corporate income tax rate from a top marginal rate of 35% to a flat rate of 21%, (ii) elimination of the corporate alternative minimum tax, (iii) immediate deductions for certain new investments instead of deductions for depreciation expense over time, (iv) limitation on the tax deduction for interest expense to 30% of adjusted taxable income, (v) limitation of the deduction for net operating losses to 80% of current year taxable income and elimination of net operating loss carrybacks, and (vi) elimination of many business deductions and credits, including the domestic production activities deduction, the deduction for entertainment expenditures, and the deduction for certain executive compensation in excess of $1 million. The Company included the impacts of the Tax Act in the fourth quarter 2017 consolidated financial statements, and no changes were made to those provisional amounts during the first nine months of 2018. The Company will continue to examine the impact of this legislation and future regulations. Additional impacts from the enactment of the Tax Act will be recorded as they are identified during the measurement period as provided for in SAB No. 118, which extends up to one year from the enactment date. The 2018 tax provision reflects the legislative changes noted above, including the new corporate tax rate of 21%.

Income tax expense for the first nine months of 2018 increased $5.2 million compared to the first nine months of 2017 due to higher pre-tax income, partially offset by a lower effective tax rate. The effective tax rates for the first nine months of 2018 and 2017 were 24.4% and 37.2%, respectively. The decrease in the effective tax rate is primarily due to the impact of the Tax Act law changes that were effective January 1, 2018, partially offset by an increase in the blended state statutory tax rate as a result of changes in the Company's state apportionment factors due to the Eagle Ford Shale asset divestiture in February 2018.

As of September 30, 2018, the Company had a $19.3 million net reserve for unrecognized tax benefits primarily related to alternative minimum tax (AMT) associated with uncertain tax positions, and a $3.7 million liability for accrued interest associated with the uncertain tax positions. Any additional AMT payments could be utilized as credits against future regular tax liabilities and would be fully refunded from 2018 through 2021 under the new Tax Act. Accordingly, the uncertain tax positions identified would not have a material impact on the Company's effective tax rate.

13. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:


(In thousands)	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
Accounts receivable, net
Trade accounts	$	162,069		$	185,594		$	221,515		$	215,511
Joint interest accounts	1,208			1,359			1,916			467
Other accounts	425			5,335			852			1,312
	163,702			192,288			224,283			217,290
Allowance for doubtful accounts	(2,012		)	(1,243		)	(1,456		)	(1,286		)
	$	161,690		$	191,045		$	222,827		$	216,004

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		$	16,671		$	14,966
Debt issuance costs	8,845			11,403			5,427			7,990
Derivative instruments	3,763			2,991
Income taxes receivable							5,321			—
Other accounts	101			58			227			56
	$	27,045		$	27,039
							$	27,646		$	23,012
Accounts payable
Trade accounts	$	25,851		$	27,355		$	34,869		$	7,815
Natural gas purchases	3,457			2,231			36,115			4,299
Royalty and other owners	33,135			36,472			33,206			39,207
Accrued transportation	48,104			48,977			47,934			51,433
Accrued capital costs	33,440			34,647			33,150			31,130
Taxes other than income	12,938			13,827			11,787			16,801
Deposits received for asset sales							—			81,500
Other accounts	3,864			4,902			66,562			5,860
	$	160,789		$	168,411
							$	263,623		$	238,045
Accrued liabilities
Employee benefits	$	17,065		$	14,153		$	12,970		$	20,645
Taxes other than income	4,018			3,829			1,708			550
Asset retirement obligations	6,073			2,000			1,000			4,952
Other accounts	158			1,510			(225		)	1,294
	$	27,314		$	21,492		$	15,453		$	27,441

Other liabilities
Deferred compensation plan	$	27,598		$	24,169		$	27,835		$	29,145
Other accounts	8,810			4,952			34,052			10,578
	$	36,408		$	29,121		$	61,887		$	39,723

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~~2018 and ~~2016~~2017 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~~10-K/A for the year ended December 31, ~~2016~~2017 (Form ~~10-K)~~10-K/A).

OVERVIEW

Financial and Operating Overview

Financial and operating results for the nine months ended September 30, ~~2017~~2018 compared to the nine months ended September 30, ~~2016~~2017 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~~32.4 Bcf, or ~~11%~~6.6%, from ~~441.8 Bcf in 2016 to~~ 491.2 Bcf in 2017 to 523.6 Bcf in 2018, as a result of drilling and completion activities in Pennsylvania.

Crude oil/condensate/NGL production ~~increased 0.1~~decreased 2.8 Mmbbls, or 2%77%, from ~~3.5 Mmbbls in 2016 to~~ 3.6 Mmbbls in 2017 to 0.8 Mmbbls in 2018, as result of anthe sale of our Eagle Ford Shale assets in February 2018.

Equivalent production increased 16.0 Bcfe, or 3.1%, from 512.7 Bcfe, or 1,877.9 Mmcfe per day, in 2017 to 528.6 Bcfe, or 1,936.4 Mmcfe per day, in 2018. The increase inis primarily due to drilling and completion ~~activity~~activities in ~~south Texas~~Pennsylvania, partially offset by ~~a natural decline~~the sale of our Eagle Ford Shale assets in ~~production.~~south Texas.

Average realized natural gas price was ~~$2.35~~$2.32 per Mcf, ~~45% higher~~1% lower than the ~~$1.62~~$2.35 per Mcf realized in the comparable period of the prior year.

Average realized crude oil price was ~~$45.70~~$63.72 per Bbl, ~~27%~~39% higher than the ~~$35.85~~$45.70 per Bbl realized in the comparable period of the prior year.

Total capital expenditures were ~~$582.8~~$593.1 million compared to ~~$262.1~~$582.8 million in the comparable period of the prior year.

Drilled 60 gross wells (60.0 net) with a success rate of 91.7% compared to 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 61 gross wells (61.0 net) in 2018 compared to 81 gross wells (70.2 net) in ~~2017 compared to 51 gross wells (51.0 net) in 2016.~~2017.

Average rig count during ~~2017~~2018 was approximately ~~2.0~~3.3 rigs in the Marcellus Shale ~~approximately 1.0 rig in the Eagle Ford Shale~~ and approximately ~~0.2~~0.7 rigs in other areas, compared to an average rig count in the Marcellus Shale of approximately ~~1.1~~2.0 rigs, ~~and~~ approximately ~~0.3 rigs~~1.0 rig in the Eagle Ford Shale and approximately 0.2 rigs in ~~2016.~~other areas during 2017.

Received net proceeds of ~~$32.7~~$675.5 million primarily related to the divestiture of ~~certain oil and gas properties and related pipeline~~our Eagle Ford Shale assets in ~~West Virginia, Virginia~~south Texas in February 2018 and ~~Ohio.~~Haynesville Shale assets in July 2018.

Repaid $237.0 million of our 6.51% weighted-average senior notes which matured in July 2018.

Repurchased ~~3.0~~27.1 million shares of our common stock for ~~a total cost of $68.3 million.~~$644.2 million in 2018.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly ~~the price of natural gas and crude oil~~commodity prices 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~~commodity prices to remain volatile. In addition to production volumes and commodity prices, finding and developing sufficient amounts of ~~natural~~oil and 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

likely experience volatility in our earnings due to commodity price volatility. Refer to “Impact of Derivative Instruments on

Operating Revenues” below and Note 5 of the Notes 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.~~volatile. 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 we believe 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~~2018 capital spending program, the majority of which is allocated to the Marcellus Shale, includes approximately ~~$775.0~~$870.0 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,~~2017, we drilled 4091 gross wells ~~(38.0~~(82.5 net) and completed 76105 gross wells ~~(76.0~~(94.2 net), of which 6250 gross wells ~~(62.0~~(44.3 net) were drilled but uncompleted in prior years. ~~In 2017,~~For the full year of 2018, we plan to drill ~~100~~approximately 85 gross wells ~~(95.0~~(85.0 net) and complete 9590 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~~2018 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),~~investments, principal and 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,~~18, 2018, the borrowing base and available commitments were reaffirmed at $3.2 billion and ~~$1.7~~$1.8 billion, respectively. There were no borrowings outstanding under our revolving credit facility as of September 30, ~~2017.~~2018.

On July 2, 2018, we closed on the sale of our oil and gas properties in the Haynesville Shale for $30.0 million. The divestiture did not have an impact on our borrowing base or available commitments.

A decline in commodity prices could result in the future reduction of our borrowing base and related commitments under the revolving credit facility. Unless commodity prices decline significantly from current levels, we do not believe that any such reductions would have a significant impact on our ability to service our debt and fund our drilling program and related operations.

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,~~2018, 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~~10-K/A for further discussion of our restrictive financial covenants.

Cash Flows

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


	Nine Months Ended September 30,						Nine Months Ended September 30,
(In thousands)	2017			2016			2018			2017
Cash flows provided by operating activities	$	719,047		$	257,705		$	788,852		$	719,047
Cash flows used in investing activities	(577,484		)	(220,141		)	(44,844		)	(577,484		)
Cash flows provided by (used in) financing activities	(129,849		)	463,115
Net increase in cash and cash equivalents	$	11,714		$	500,679
Cash flows used in financing activities							(907,978		)	(129,849		)
Net (decrease) increase in cash and cash equivalents							$	(163,970	)	$	11,714

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~~2018 and December 31, ~~2016,~~2017, we had a working capital surplus of ~~$279.8~~$253.8 million and ~~$458.1~~$134.9 million, respectively.

Net cash provided by operating activities in the first nine months of ~~2017~~2018 increased by ~~$461.3~~$69.8 million compared to the first nine months of ~~2016.~~2017. This increase was primarily due to favorable changes in working capital and other assets and liabilities and higher operating revenues, partially offset by higher cash operating expenses. The increase in operating revenues was primarily due to ~~an increase~~higher equivalent production and higher crude oil prices, partially offset by a decrease in realized natural gas ~~and crude oil prices and higher equivalent production.~~prices. Average realized natural gas prices decreased by 1% and crude oil prices increased by ~~45% and 27%~~39%, respectively, for the first nine months of ~~2017~~2018 compared to the first nine months of ~~2016.~~2017. Equivalent production increased by ~~11%~~3.1% for the first nine months of ~~2017~~2018 compared to the first nine months of ~~2016 driven by~~2017 due to higher natural gas production in the Marcellus ~~Shale.~~Shale, offset by lower crude oil production due to the Eagle Ford Shale divestiture in February 2018.

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~~decreased by ~~$357.3~~$532.6 million for the first nine months of ~~2017~~2018 compared to the first nine months of ~~2016.~~2017. The ~~increase~~decrease was due to ~~$341.8~~$642.8 million higher ~~capital expenditures and $16.4 million lower~~ proceeds from the sale of assets primarily due to the divestiture of our Eagle Ford Shale assets in February 2018 and our Haynesville Shale assets in July 2018. This change was partially offset by ~~$0.8~~$60.7 million ~~lower~~higher capital expenditures and $49.5 million higher capital contributions associated with our equity method investments.

Financing Activities. Cash flows ~~provided by~~used in financing activities ~~decreased~~increased by ~~$593.0~~$778.1 million for the first nine months of ~~2017~~2018 compared to the first nine months of ~~2016.~~2017. This ~~decrease~~increase was primarily due to ~~$995.3~~the repayment of $237.0 million ~~lower net proceeds from the issuance~~ of ~~common stock~~our 6.51% weighted-average senior notes which matured in ~~2016, $68.3~~July 2018, $513.5 million of higher repurchases of our common stock in 2018 compared to 2017 and ~~$28.8~~$25.5 million of higher dividend payments related to an increase in ~~the~~our dividend rate ~~and~~from $0.12 per share for the ~~issuance~~first nine months of ~~common stock~~2017 to $0.18 per share in ~~2016. These decreases were partially offset by $497.0 million~~the first nine months 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 2016.2018.

Capitalization

Information about our capitalization is as follows:



(In thousands)	September 30, 2018			December 31, 2017
Debt ⁽¹⁾	$	1,285,848		$	1,521,891
Stockholders' equity	2,094,147			2,523,905
Total capitalization	$	3,379,995		$	4,045,796
Debt to total capitalization	38		%	38		%
Cash and cash equivalents	$	316,077		$	480,047

(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~~$67.0 million and $304.0 million of current portion of long-term debt at September 30, ~~2017.~~2018 and December 31, 2017, respectively.

During the first nine months of ~~2017,~~2018, we repurchased ~~3.0~~27.1 million shares of our common stock for ~~$68.3~~$644.2 million. ~~We also~~During the first nine months of 2018 and 2017, we paid dividends of $81.2 million ($0.18 per share) and $55.7 million ($0.12 per share), respectively, on our common stock.

In ~~May 2017,~~January 2018, the Board of Directors approved an increase in the quarterly dividend on our common stock from ~~$0.02~~$0.05 per share to ~~$0.05~~$0.06 per share.

Subsequent Events. Subsequent to September 30, 2018, we repurchased 2.8 million shares for a total cost of $65.6 million under a Rule 10b5-1 Plan.

In October 2018, the Board of Directors approved an increase in the quarterly dividend on our common stock from $0.06 per share to $0.07 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,				Nine Months Ended September 30,
(In thousands)	2017		2016		2018		2017
Capital expenditures
Drilling and facilities	$	475,240	$	255,139	$	551,351	$	475,240
Leasehold acquisitions	97,835		1,687		27,487		97,835
Pipeline and gathering	597		1,009		—		597
Other	9,091		4,251		14,260		9,091
	582,763		262,086		593,098		582,763
Exploration expenditures(1)	16,623		13,109		68,166		16,623
Total	$	599,386	$	275,195	$	661,264	$	599,386


(1)	Exploration expenditures include $56.4 million and $2.8 million of exploratory dry hole expenditures for the first nine months of 2018 and 2017, respectively.

For the full year of ~~2017,~~2018, we plan to drill approximately ~~100~~85 gross wells ~~(95.0~~(85.0 net) and complete 9590 gross wells (90.0 net)~~, of which 51 gross wells (45.0 net) were drilled but uncompleted in prior years.~~. In ~~2017,~~2018, our drilling program includes approximately ~~$775.0~~$870.0 million in total capital expenditures compared to ~~$372.5~~$757.2 million in ~~2016.~~2017. 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,”~~Agreements” and “Lease ~~Commitments” and “Hydraulic Fracturing Services~~ Commitments” as disclosed in Note 9 inof the Notes to the 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.~~10-K/A.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our Condensed Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the

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

Recently Adopted and Recently Issued Accounting Pronouncements

Refer to Note 1 of the Notes 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~~2018 and ~~2016~~2017 Compared

We reported net income in the third quarter of ~~2017~~2018 of $122.3 million, or $0.28 per share, compared to net income 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.~~2017. The increase in net income was primarily due to higher operating revenues and higher gain on sale of assets, partially offset by higher operating ~~expenses, loss on sale of assets and income tax expense.~~expenses.

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					Three Months Ended September 30,						Variance
Revenue Variances (In thousands)	2017			2016		Amount			Percent		2018			2017			Amount			Percent
Natural gas	$	323,319		$	260,200	$	63,119		24	%	$	440,835		$	323,319		$	117,516		36	%
Crude oil and condensate	56,913			37,777		19,136			51	%	—			56,913			(56,913		)	(100	)%
Gain (loss) on derivative instruments	(836		)	6,904		(7,740		)	(112	)%	(3,537		)	(836		)	(2,701		)	323	%
Brokered natural gas	3,528			3,641		(113		)	(3	)%	105,849			3,528			102,321			2,900	%
Other	2,492			1,907		585			31	%	2,026			2,492			(466		)	(19	)%
	$	385,416		$	310,429	$	74,987		24	%	$	545,173		$	385,416		$	159,757		41	%


	Three Months Ended September 30,				Variance				Increase (Decrease) (In thousands)		Three Months Ended September 30,				Variance				Increase (Decrease) (In thousands)
	2017		2016		Amount		Percent		Increase (Decrease) (In thousands)		2018		2017		Amount		Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	2.01	$	1.80	$	0.21	12	%	$	32,879	$	2.36	$	2.01	$	0.35	17	%	$	66,663
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	186.5		161.2		25.3		16	%	$	50,853
Crude oil and condensate (Mbbl)	1,268		941		327		35	%	13,123
Total									$	43,363									$	117,516

Natural Gas Revenues

The increase in natural gas revenues of ~~$63.1~~$117.5 million was due to higher natural gas prices and higher 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~~decrease in crude oil and condensate revenues of ~~$19.1~~$56.9 million was ~~due to higher crude oil prices and production.~~ a result of the sale of our Eagle Ford Shale assets in February 2018.

Impact of Derivative Instruments on Operating Revenues



	Three Months Ended September 30,
(In thousands)	2018			2017
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	(41	)	$	3,906
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(3,496		)	(4,742		)
	$	(3,537	)	$	(836	)

Brokered Natural Gas



	Three Months Ended September 30,				Variance
(In thousands)	2018		2017		Amount		Percent
Brokered natural gas sales	$	105,849	$	3,528
Brokered natural gas purchases		93,405		2,797
Brokered natural gas margin	$	12,444	$	731	$	11,713	1,602	%

The $11.7 million increase in ~~production was~~brokered natural gas margin is a result of an increase in ~~our drilling and completion activities in south Texas.~~brokered activity. This increase was due to higher volumes associated with natural gas purchases that were required to satisfy certain sales obligations.

~~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
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

Operating and Other Expenses


	Three Months Ended September 30,						Variance					Three Months Ended September 30,						Variance
(In thousands)	2017			2016			Amount			Percent		2018			2017			Amount			Percent
Operating and Other Expenses
Direct operations	$	26,282		$	24,626		$	1,656		7	%	$	17,030		$	26,282		$	(9,252	)	(35	)%
Transportation and gathering	117,891			105,671			12,220			12	%	129,534			117,891			11,643			10	%
Brokered natural gas	2,797			2,939			(142		)	(5	)%	93,405			2,797			90,608			3,239	%
Taxes other than income	9,194			8,771			423			5	%	2,852			9,194			(6,342		)	(69	)%
Exploration	6,466			2,988			3,478			116	%	10,049			6,466			3,583			55	%
Depreciation, depletion and amortization	146,267			139,490			6,777			5	%	121,172			146,267			(25,095		)	(17	)%
General and administrative	23,244			19,374			3,870			20	%	20,724			23,244			(2,520		)	(11	)%
	$	332,141		$	303,859		$	28,282		9	%	$	394,766		$	332,141		$	62,625		19	%

Earnings (loss) on equity method investments	$	(1,417	)	$	(1,727	)	$	310		(18	)%
Loss on sale of assets	(11,872		)	(1,245		)	(10,627		)	854	%
Loss on equity method investments												$	(11	)	$	(1,417	)	$	(1,406	)	(99	)%
Gain (loss) on sale of assets												25,655			(11,872		)	(37,527		)	(316	)%
Interest expense, net	20,331			21,483			(1,152		)	(5	)%	14,191			20,331			(6,140		)	(30	)%
Other expense (income)	(5,083		)	402			(5,485		)	(1,364	)%	115			(5,083		)	5,198			(102	)%
Income tax expense (benefit)	7,151			(8,027		)	15,178			189	%
Income tax expense												39,408			7,151			32,257			451	%

Total costs and expenses from operations increased by ~~$28.3~~$62.6 million, or 9%19%, in the third quarter of ~~2017~~2018 compared to the same period of ~~2016.~~2017. The primary reasons for this fluctuation are as follows:

Direct operations ~~increased $1.7~~decreased $9.3 million largely due to the sale of our oil and gas properties in West Virginia in the third quarter of 2017 and Eagle Ford Shale assets in the first quarter of 2018, partially offset by an increase in operating costs primarily driven by higher ~~production, partially offset by improved operational efficiencies.~~Marcellus Shale production.

Transportation and gathering increased ~~$12.2~~$11.6 million due to ~~higher~~increased throughput as a result of higher Marcellus Shale ~~production.~~production and slightly higher rates, partially offset by the sale of our oil and gas properties in West Virginia in the third quarter of 2017 and Eagle Ford Shale assets in the first quarter of 2018.

Brokered natural gas ~~decreased $0.1~~increased $90.6 million. See the preceding table titled “Brokered Natural Gas” for further analysis.

Taxes other than income ~~increased $0.4~~decreased $6.3 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~~$1.6 million lower drilling impact fees as a result of lower ~~rates. The remaining changes~~rates, $3.2 million lower production taxes and $1.7 million lower ad valorem taxes both resulting from the sale of our oil and gas properties in ~~taxes other than income were not individually significant.~~West Virginia in the third quarter of 2017 and Eagle Ford Shale assets in the first quarter of 2018.

Exploration increased ~~$3.5~~$3.6 million ~~primarily as a result of higher geophysical~~due to an increase in exploratory dry hole costs of ~~$2.0 million~~$5.3 million. The exploratory dry hole costs in 2018 relate to our activities in one of our exploratory areas and our decision to cease further activity in that area based on the results of those activities.

Depreciation, depletion and amortization ~~increased $6.8~~decreased $25.1 million primarily due to lower DD&A of $40.6 million, partially offset by higher amortization of unproved properties of ~~$9.4 million, partially offset by lower DD&A of $1.4~~$15.6 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~~2018. DD&A ~~was due to a decrease of $17.3~~decreased $52.7 million due to a lower DD&A rate of $0.46 per Mcfe for the third quarter of 2018 compared to $0.75 per Mcfe for the third quarter of 2017, ~~compared~~partially offset by $12 .0 million related to ~~$0.85 per Mcfe for~~higher production volumes in the ~~third quarter~~Marcellus Shale. The lower DD&A rate was due to the sale of ~~2016 primarily due to~~higher rate fields in Eagle Ford Shale and West Virginia and positive reserve revisions ~~and the impairment~~related to our year end reserve estimation process. Amortization of ~~oil and gas~~unproved properties ~~and related pipeline assets in West Virginia and Virginia in 2016, partially offset by an increase of $15.8 million associated with~~increased due to higher ~~equivalent production primarily in Pennsylvania for the third quarter of 2017 compared to the third quarter of 2016.~~amortization rates.

General and administrative ~~increased $3.9~~decreased $2.5 million primarily due to ~~$3.2~~$1.4 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~~lower stock-based compensation expense associated with certain of our market-based performance awards ~~partially offset by $2.0~~and $1.9 million lower employee costs and professional services. The remaining changes in other general and administrative expenses were not individually significant.

~~Earnings~~Gain (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 inDuring the third quarter of ~~2017.~~2018, we recognized a net aggregate gain of $25.7 million primarily due to the sale of certain of our oil and gas assets in east Texas. During the third quarter of 2017, we recognized a net aggregate loss of $11.9 million primarily due to the sale of our assets in West Virginia.

Interest Expense, net

Interest expense, net decreased $6.1 million due to $3.3 million lower interest expense resulting from the repayment of $237.0 million of our 6.51% weighted-average senior notes which matured in July 2018 and $1.9 million lower interest expense related to uncertain tax positions.

Other Expense (Income)

Other income ~~increased $5.5~~decreased $5.2 million ~~primarily~~ due to ~~the~~a lower 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.~~in 2017.

Income Tax Expense ~~(Benefit)~~

Income tax expense increased ~~$15.2~~$32.3 million ~~primarily~~ due to higher ~~pretax~~pre-tax income, partially offset by a lower effective tax rate. The effective tax rates for the third quarter of 2018 and 2017 were 24.4% 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~~impact of the Tax Cuts and Jobs Act law changes ~~in our state apportionment factors in the states in which we operate,~~that were effective January 1, 2018, as well as the impact of non-recurring discrete items recorded during the third quarter of ~~2017 versus~~2018 as compared to the third quarter of ~~2016.~~2017.

First Nine Months of ~~2017~~2018 and ~~2016~~2017 Compared

We reported net income in the first nine months of ~~2017~~2018 of $282.0 million, or $0.63 per share, compared to net income 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.~~2017. The increase in net income was primarily due to higher operating revenues ~~partially offset by higher~~and lower operating ~~expenses, loss on sale of assets and income tax expense.~~expenses.

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				Nine Months Ended September 30,					Variance
Revenue Variances (In thousands)	2017		2016			Amount		Percent		2018			2017		Amount			Percent
Natural gas	$	1,152,089	$	711,010		$	441,079	62	%	$	1,217,603		$	1,152,089	$	65,514		6	%
Crude oil and condensate	144,528		114,610			29,918		26	%	48,722			144,528		(95,806		)	(66	)%
Gain (loss) on derivative instruments	46,353		(1,286		)	47,639		3,704	%	(1,628		)	46,353		(47,981		)	(104	)%
Brokered natural gas	12,260		9,417			2,843		30	%	203,375			12,260		191,115			1,559	%
Other	8,486		5,435			3,051		56	%	3,775			8,486		(4,711		)	(56	)%
	$	1,363,716	$	839,186		$	524,530	63	%	$	1,471,847		$	1,363,716	$	108,131		8	%


	Nine Months Ended September 30,				Variance				Increase (Decrease) (In thousands)		Nine Months Ended September 30,				Variance					Increase (Decrease) (In thousands)
	2017		2016		Amount		Percent		Increase (Decrease) (In thousands)		2018		2017		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	2.35	$	1.61	$	0.74	46	%	$	361,545	$	2.33	$	2.35	$	(0.02	)	(1	)%	$	(10,626	)
Crude oil and condensate	$	45.13	$	35.92	$	9.21	26	%	29,451		$	64.68	$	45.13	$	19.55		43	%	14,717
Total									$	390,996										$	4,091
Volume Variances
Natural gas (Bcf)	491.2		441.8		49.4		11	%	$	79,534	523.6		491.2		32.4			7	%	$	76,140
Crude oil and condensate (Mbbl)	3,203		3,190		13		—	%	467		754		3,203		(2,449		)	(76	)%	(110,523		)
Total									$	80,001										$	(34,383	)

Natural Gas Revenues

The increase in natural gas revenues of ~~$441.1~~$65.5 million was due to ~~higher~~an increase in production, partially offset by lower natural gas ~~prices and production.~~prices. 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~~decrease in crude oil and condensate revenues of ~~$29.9~~$95.8 million was primarily due to lower production, partially offset by higher crude oil prices. The decrease in production was the result of the sale of our Eagle Ford Shale assets in February 2018.

Impact of Derivative Instruments on Operating Revenues


	Nine Months Ended September 30,					Nine Months Ended September 30,
(In thousands)	2017		2016			2018			2017
Cash received (paid) on settlement of derivative instruments
Gain on derivative instruments	$	3,587	$	3,204
Gain (loss) on derivative instruments						$	(20,354	)	$	3,587
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	42,766		(4,490		)	18,726			42,766
	$	46,353	$	(1,286	)	$	(1,628	)	$	46,353

Brokered Natural Gas

Nine Months Ended September 30, Variance
Price and
Volume
Variances
(In thousands)
2017 2016 Amount Percent
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



	Nine Months Ended September 30,				Variance
(In thousands)	2018		2017		Amount		Percent
Brokered natural gas sales	$	203,375	$	12,260
Brokered natural gas purchases		178,437		10,262
Brokered natural gas margin	$	24,938	$	1,998	$	22,940	1,148	%

The $22.9 million increase in brokered natural gas margin is a result of an increase in brokered activity. This increase was due to higher volumes associated with natural gas purchases that were required to satisfy certain sales obligations.

Operating and Other Expenses


	Nine Months Ended September 30,						Variance					Nine Months Ended September 30,						Variance
(In thousands)	2017			2016			Amount			Percent		2018			2017			Amount			Percent
Operating and Other Expenses
Direct operations	$	78,185		$	77,139		$	1,046		1	%	$	52,757		$	78,185		$	(25,428	)	(33	)%
Transportation and gathering	361,909			322,883			39,026			12	%	355,848			361,909			(6,061		)	(2	)%
Brokered natural gas	10,262			7,526			2,736			36	%	178,437			10,262			168,175			1,639	%
Taxes other than income	26,562			23,737			2,825			12	%	15,434			26,562			(11,128		)	(42	)%
Exploration	16,623			13,109			3,514			27	%	68,166			16,623			51,543			310	%
Depreciation, depletion and amortization	425,689			448,910			(23,221		)	(5	)%	288,210			425,689			(137,479		)	(32	)%
Impairment of oil and gas properties	68,555			—			68,555			100	%	—			68,555			(68,555		)	(100	)%
General and administrative	70,902			67,192			3,710			6	%	66,013			70,902			(4,889		)	(7	)%
	$	1,058,687		$	960,496		$	98,191		10	%	$	1,024,865		$	1,058,687		$	(33,822	)	(3	)%

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	%
Loss on equity method investments												$	(1,009	)	$	(3,986	)	$	(2,977	)	(75	)%
Gain (loss) on sale of assets												(14,850		)	(13,498		)	1,352			10	%
Interest expense, net	61,720			67,821			(6,101		)	(9	)%	57,577			61,720			(4,143		)	(7	)%
Loss on debt extinguishment	—			4,709			(4,709		)	(100	)%
Other expense (income)	(4,974		)	1,207			(6,181		)	(512	)%	347			(4,974		)	5,321			(107	)%
Income tax expense (benefit)	85,965			(71,243		)	157,208			221	%
Income tax expense												91,201			85,965			5,236			6	%

Total costs and expenses from operations ~~increased~~decreased by ~~$98.2~~$33.8 million, or ~~10%~~3%, in the first nine months of ~~2017~~2018 compared to the same period of ~~2016.~~2017. The primary reasons for this fluctuation are as follows:

Direct operations ~~increased $1.0~~decreased $25.4 million largely due to the sale of our oil and gas properties in West Virginia in the third quarter of 2017 and the Eagle Ford Shale assets in the first quarter of 2018, partially offset by 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.~~Marcellus Shale production.

Transportation and gathering ~~increased $39.0~~decreased $6.1 million largely due to the sale of our oil and gas properties in West Virginia in the third quarter of 2017 and the Eagle Ford Shale assets in the first quarter of 2018, partially offset by an increase in costs due to higher ~~throughput as a result of higher~~rates and increased Marcellus Shale production.

Brokered natural gas increased ~~$2.7~~$168.2 million. See the preceding table titled “Brokered Natural Gas” for further analysis.

Taxes other than income ~~increased $2.8~~decreased $11.1 million primarily due to ~~$3.4~~$6.0 million ~~higher~~lower production taxes ~~primarily~~and $6.1 million lower ad valorem taxes both resulting from ~~higher natural~~the sale of our oil and gas properties in West Virginia in the third quarter of 2017 and ~~crude oil prices and an increase~~Eagle Ford Shale assets in ~~drilling impact fees~~the first quarter of ~~$1.9~~2018.

Exploration increased $51.5 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~~exploratory dry hole costs of ~~$2.8 million~~$53.6 million. The exploratory dry hole costs in ~~2017~~2018 relate to our activities in one of our exploratory areas and ~~$2.6 million higher geophysical costs, partially offset by lower charges related~~our decision to cease further activity in that area based on the ~~release~~results 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.those activities.

Depreciation, depletion and amortization decreased ~~$23.2~~$137.5 million primarily due to lower DD&A of ~~$38.0~~$141.9 million and lower accretion of $2.5 million, partially offset by higher amortization of unproved properties of ~~$15.9 million in 2017.~~$6.9 million. The decrease in DD&A was primarily due to a decrease of ~~$82.5~~$150.4 million ~~due~~related to a lower DD&A rate of $0.45 per Mcfe for the first nine months of 2018 compared to $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~~$11.7 million ~~increase due~~related to higher ~~equivalent~~ production ~~volumes.~~volumes in the Marcellus Shale. The lower DD&A rate was ~~primarily~~ due to the cessation of DD&A related to the sale of our higher rate Eagle Ford Shale assets that were classified as held for sale in the fourth quarter of 2017 and 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~~to our year end reserve estimation process. Amortization of unproved properties ~~is primarily~~increased due to ~~the ongoing evaluation of our unproved properties and an increase in leasing activity.~~higher amortization rates.

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

Ohio associated with the proposed sale of these properties in the third quarter of 2017.

General and administrative ~~increased $3.7~~decreased $4.9 million primarily due to ~~$3.4 million higher employee-related expenses, $3.2 million of higher~~lower stock-based compensation ~~expense~~cost of $8.5 million 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~~$4.6 million ~~lower~~higher employee costs and professional services. The remaining changes in ~~other~~ general and administrative expenses were not individually significant.

~~Earnings (Loss)~~Loss on Equity Method Investments

~~The increase in loss~~Loss on equity method investments ~~is the~~decreased $3.0 million as a result of our proportionate share of net ~~earnings~~loss from our equity method investments in ~~2017~~the first nine months of 2018 compared to ~~2016.~~the first nine months of 2017.

Loss on Sale of Assets

~~Loss on sale~~During the first nine months of ~~assets increased $12.7~~2018, we recognized a net aggregate loss of $14.9 million primarily due to the ~~Company's~~ sale of ~~certain proved and unproved~~our Eagle Ford Shale assets, partially offset by a gain on the sale of oil and gas properties ~~and related pipeline~~in east Texas. During the first nine months of 2017, we recognized a net aggregate loss of $13.5 million primarily due to the sale of our assets ~~located~~ in West ~~Virginia, Virginia~~Virginia.

Interest Expense, net

Interest expense, net decreased $4.1 million due to $3.3 million lower interest expense resulting from the repayment of $237.0 million of our 6.51% weighted-average senior notes which matured in July 2018 and ~~Ohio in the third quarter of 2017.~~$4.0 million higher interest income partially offset by $3.8 million higher interest expense related to uncertain tax positions.

Other Expense (Income)

Other income ~~increased $6.2~~decreased $5.3 million ~~primarily~~ due to ~~the~~a lower 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~~$5.2 million due to higher ~~pretax~~pre-tax income, ~~and~~partially offset by a ~~higher~~lower effective tax rate. The effective tax rates for the first nine months of 2018 and 2017 were 24.4% and ~~2016 were~~ 37.2% ~~and 36.4%~~, respectively. The ~~increase~~decrease in the effective tax rate is primarily due to the impact of the Tax Cuts and Jobs Act law changes that were effective January 1, 2018, partially offset by an increase in the blended state statutory tax rate as a result of changes in our state apportionment factors due to the Eagle Ford Shale asset divestiture 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.February 2018.

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~~10-K/A for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

Market Risk

Our primary market risk is exposure to natural gas and crude oil prices. Realized prices are mainly driven by worldwide prices for crude oil and spot market prices for North American natural gas production. Commodity prices 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~~10-K/A 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,~~2018, we had the following outstanding financial commodity derivatives:

Collars Basis Swaps
Estimated
Fair Value
Asset (Liability)
(In thousands)
Floor Ceiling 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



				Swaps		Basis Swaps			Estimated Fair Value Asset (Liability) (In thousands)
				Swaps		Basis Swaps
Type of Contract	Volume		Contract Period	Weighted-Average		Weighted- Average
Natural gas (Leidy)	8.9	Bcf	Oct. 2018 - Dec. 2018			$	(0.69	)	$	(2,195	)
Natural gas (Leidy)	53.2	Bcf	Jan. 2019 - Dec. 2019			$	(0.55	)	(1,787		)
Natural gas (Transco)	13.3	Bcf	Oct. 2018 - Dec. 2019			$	0.42		210
Natural gas (NYMEX)	23.2	Bcf	Oct. 2018 - Dec. 2018	$	2.93				(4,709		)
Natural gas (NYMEX)	1.5	Bcf	Oct. 2018	$	3.10				(12		)
									$	(8,493	)

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

The amounts set forth in the table above represent our total unrealized derivative position at September 30, ~~2017~~2018 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,~~2018, natural gas ~~collars with floor prices of $3.09 per Mcf and ceiling prices ranging from $3.42 to $3.45 per Mcf~~basis swaps covered ~~26.5~~33.0 Bcf, or 5%6%, of natural gas production at an average price of ~~$3.23~~$2.56 per Mcf. Natural gas swaps covered ~~38.3~~72.9 Bcf, or 8%14%, of natural gas production at an average price of ~~$3.23~~$2.95 per Mcf. Crude oil collars with floor prices of ~~$50.00~~$55.00 per Bbl and ceiling prices ranging from ~~$56.25~~$63.35 to ~~$56.50~~$63.80 per Bbl covered ~~1.4~~0.2 Mmbbl, or ~~43%~~33%, of crude oil production at an average price of ~~$50.77~~$63.62 per Bbl.

In January 2018, as a result of the pending sale of our Eagle Ford Shale assets, we terminated all of our outstanding crude oil financial derivatives for $0.3 million.

We are exposed to market risk on commodity derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of

natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.

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

Fair Value of Other Financial Instruments

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

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


	September 30, 2017						December 31, 2016				September 30, 2018						December 31, 2017
(In thousands)	Carrying Amount			Estimated Fair Value			Carrying Amount		Estimated Fair Value		Carrying Amount			Estimated Fair Value			Carrying Amount			Estimated Fair Value
Debt, net	$	1,521,551		$	1,536,360		$	1,520,530	$	1,463,643
Long-term debt											$	1,285,848		$	1,245,971		$	1,521,891		$	1,527,624
Current maturities	(237,000		)	(243,569		)	—		—		(67,000		)	(67,679		)	(304,000		)	(312,055		)
Long-term debt, excluding current maturities	$	1,284,551		$	1,292,791		$	1,520,530	$	1,463,643	$	1,218,848		$	1,178,292		$	1,217,891		$	1,215,569

ITEM 4. Controls and Procedures

As of September 30, ~~2017,~~2018, 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~~On January 1, 2018, the Company implemented a new Enterprise Resource Planning (ERP) system designed to upgrade our technology and improve our financial and operational information. The Company has modified its existing internal controls related to the ERP system implementation. While the Company believes that this new system and related changes to internal controls will ultimately strengthen its internal control over financial reporting, there are inherent risks in implementing a new ERP system and the Company will continue to evaluate and test these control changes in order to provide certification as of its fiscal year ending December 31, 2018 on the effectiveness, in all material respects, of its internal control over financial reporting.

With the exception of the ERP implementation described above, there were no changes in the Company's internal control over financial reporting that occurred during the third quarter of ~~2017~~2018 that have materially affected, or are reasonably likely to materially effect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

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

Environmental Matters

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~~10-K/A for the year ended December 31, ~~2016.~~2017.

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. In July 2018, the Board of Directors authorized an increase of 20.0 million shares to our share repurchase program. There is no expiration date associated with the authorization. The ~~maximum number of remaining~~ shares ~~that may be~~included in the table below were purchased ~~under~~on the ~~plan~~open market and were held as treasury stock as of September 30, ~~2017 was 7.1~~2018.



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
July 2018	—	$	—	—	30,080,295
August 2018	39,037	$	22.87	39,037	30,041,258
September 2018⁽¹⁾	7,131,508	$	22.67	7,131,508	22,909,750
Total	7,170,545			7,170,545

⁽¹⁾ Includes 2.7 million ~~shares.~~shares that were repurchased prior to September 30, 2018 and settled in October 2018.

Subsequent to September 30, 2018, we repurchased 2.8 million shares for a total cost of $65.6 million under a Rule 10b5-1 Plan.

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.

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~~26, 2018	By:	/s/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

October ~~30, 2017~~26, 2018	By:	/s/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

October ~~30, 2017~~26, 2018	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Vice President and Controller
		(Principal Accounting Officer)

3531



	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



				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 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



(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	)



	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