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~~June 30, ~~2017~~2019

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~~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,Texas77024

(Address of principal executive offices including ZIP code)

~~(281)~~ (281) 589-4600

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.10 per share	COG	New York Stock Exchange

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 filerý	☒	Accelerated filero	☐

Non-accelerated filero	☐	Smaller reporting companyo	☐

~~(Do not check if a smaller reporting company)~~		Emerging growth companyo	☐

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,~~July 24, 2019, there were ~~462,508,414~~418,390,612 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~~June 30, ~~2017~~2019 and December 31, ~~2016~~2018		3

Condensed Consolidated Statement of Operations (Unaudited) for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018		4

Condensed Consolidated Statement of ~~Comprehensive Income~~Cash Flows (Unaudited) for the ~~Three and Nine~~Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018		5

Condensed Consolidated Statement of ~~Cash Flows~~Stockholders' Equity (Unaudited) for the ~~Nine~~Three and Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018		6

Notes to the Condensed Consolidated Financial Statements		7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2119

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	3431

Signatures		3532

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			June 30, 2019			December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	510,256		$	498,542		$	241,394		$	2,287
Accounts receivable, net	161,690			191,045			183,376			362,403
Income taxes receivable	26,963			10,298			121,859			109,251
Inventories	12,997			13,304			19,381			11,076
Derivative instruments							61,194			57,665
Other current assets	6,123			2,692			4,126			1,863
Total current assets	718,029			715,881			631,330			544,545
Properties and equipment, net (Successful efforts method)	4,234,772			4,250,125			3,699,575			3,463,606
Equity method investments	148,920			129,524			166,138			163,181
Other assets	27,045			27,039			66,686			27,497
	$	5,128,766		$	5,122,569		$	4,563,729		$	4,198,829
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	160,789		$	168,411		$	184,960		$	241,939
Current portion of long-term debt	237,000			—
Accrued liabilities	27,314			21,492			29,184			25,227
Interest payable	12,331			27,650			19,882			20,098
Derivative instruments	800			40,259
Total current liabilities	438,234			257,812			234,026			287,264
Long-term debt, net	1,284,551			1,520,530			1,219,555			1,226,104
Deferred income taxes	638,014			579,447			611,163			458,597
Asset retirement obligations	59,605			131,733			54,356			50,622
Postretirement benefits	27,360			36,259			28,874			27,912
Other liabilities	36,408			29,121			70,951			60,171
Total liabilities	2,484,172			2,554,902			2,218,925			2,110,670

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 2019 and 2018, respectively
Issued — 476,879,016 shares and 476,094,551 shares in 2019 and 2018, respectively							47,688			47,610
Additional paid-in capital	1,738,656			1,727,310			1,769,195			1,763,142
Retained earnings	1,230,002			1,098,703			1,983,733			1,607,658
Accumulated other comprehensive income	3,482			985			4,164			4,437
Less treasury stock, at cost:
12,935,926 and 9,892,680 shares in 2017 and 2016, respectively	(375,090		)	(306,835		)
58,490,638 shares and 53,409,705 shares in 2019 and 2018, respectively							(1,459,976		)	(1,334,688		)
Total stockholders' equity	2,644,594			2,567,667			2,344,804			2,088,159
	$	5,128,766		$	5,122,569		$	4,563,729		$	4,198,829

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 June 30,						Six Months Ended June 30,
(In thousands, except per share amounts)	2019			2018			2019			2018
OPERATING REVENUES
Natural gas	$	470,482		$	364,660		$	1,103,656		$	776,768
Crude oil and condensate	—			—			—			48,722
Gain (loss) on derivative instruments	63,649			(3,668		)	71,906			1,909
Brokered natural gas	—			92,576			—			97,526
Other	(14		)	(121		)	236			1,749
	534,117			453,447			1,175,798			926,674
OPERATING EXPENSES
Direct operations	18,093			15,657			36,427			35,727
Transportation and gathering	141,689			114,189			279,022			226,314
Brokered natural gas	—			80,082			—			85,032
Taxes other than income	3,640			5,392			9,487			12,582
Exploration	4,504			54,500			10,548			58,117
Depreciation, depletion and amortization	96,147			84,910			188,405			167,038
General and administrative	22,889			21,228			53,979			45,288
	286,962			375,958			577,868			630,098
Earnings (loss) on equity method investments	3,650			(4		)	7,334			(998		)
Gain (loss) on sale of assets	—			544			(1,500		)	(40,505		)
INCOME FROM OPERATIONS	250,805			78,029			603,764			255,073
Interest expense, net	14,567			23,328			26,748			43,386
Other expense	143			118			287			232
Income before income taxes	236,095			54,583			576,729			211,455
Income tax expense	55,086			12,152			132,957			51,793
NET INCOME	$	181,009		$	42,431		$	443,772		$	159,662

Earnings per share
Basic	$	0.43		$	0.09		$	1.05		$	0.35
Diluted	$	0.43		$	0.09		$	1.05		$	0.35

Weighted-average common shares outstanding
Basic	422,141			451,055			422,626			455,361
Diluted	424,349			453,114			424,550			457,142

Dividends per common share	$	0.09		$	0.06		$	0.16		$	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,						Six Months Ended June 30,
(In thousands)	2017			2016			2019			2018
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							$	443,772		$	159,662
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	425,689			448,910			188,405			167,038
Impairment of oil and gas properties	68,555			—
Deferred income tax expense (benefit)	89,731			(59,413		)
Deferred income tax expense							152,647			66,976
Loss on sale of assets	13,498			768			1,500			40,505
Exploratory dry hole cost	2,842			18			16			51,085
(Gain) loss on derivative instruments	(46,353		)	1,286
Net cash received in settlement of derivative instruments	3,587			3,204
Gain on derivative instruments							(71,906		)	(1,909		)
Net cash received (paid) in settlement of derivative instruments							68,377			(20,312		)
(Earnings) loss on equity method investments	3,986			(208		)	(7,334		)	998
Distribution of earnings from equity method investments							8,750			—
Amortization of debt issuance costs	3,579			3,888			2,464			2,390
Stock-based compensation and other	26,011			23,051			21,058			10,364
Changes in assets and liabilities:
Accounts receivable, net	29,276			(1,135		)	179,027			38,939
Income taxes	(16,665		)	(11,235		)	(5,577		)	12,107
Inventories	(2,100		)	2,860			(8,305		)	(12,377		)
Other current assets	(896		)	(917		)	(2,263		)	(1,096		)
Accounts payable and accrued liabilities	(5,133		)	(12,174		)	(35,867		)	7,168
Interest payable	(15,318		)	(17,618		)	(216		)	(215		)
Other assets and liabilities	(6,076		)	784			(22,611		)	25,337
Net cash provided by operating activities	719,047			257,705			911,937			546,660
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(586,813		)	(245,033		)	(421,500		)	(387,271		)
Proceeds from sale of assets	32,711			49,068			2,346			646,868
Investment in equity method investments	(23,382		)	(24,176		)	(5,131		)	(62,905		)
Net cash used in investing activities	(577,484		)	(220,141		)
Distribution of investment from equity method investments							758			—
Net cash (used in) provided by investing activities							(423,527		)	196,692
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	—			90,000			95,000			—
Repayments of debt	—			(587,000		)	(102,000		)	—
Treasury stock repurchases	(68,255		)	—			(156,638		)	(419,654		)
Sale of common stock, net	—			995,279
Dividends paid	(55,707		)	(26,885		)	(67,697		)	(54,718		)
Tax withholdings on stock award vestings	(5,929		)	(5,056		)
Tax withholdings on vesting of stock awards							(10,557		)	(8,033		)
Capitalized debt issuance costs	—			(3,223		)	(7,411		)	—
Other	42			—
Net cash provided by (used in) financing activities	(129,849		)	463,115
Net cash used in financing activities							(249,303		)	(482,405		)
Net increase in cash and cash equivalents	11,714			500,679			239,107			260,947
Cash and cash equivalents, beginning of period	498,542			514			2,287			480,047
Cash and cash equivalents, end of period	$	510,256		$	501,193		$	241,394		$	740,994

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

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (Unaudited)



(In thousands, except per share amounts)	Common Shares	Common Stock Par		Treasury Shares	Treasury Stock			Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
Balance at December 31, 2018	476,095	$	47,610	53,410	$	(1,334,688	)	$	1,763,142		$	4,437		$	1,607,658		$	2,088,159
Net income	—	—		—	—			—			—			262,763			262,763
Stock amortization and vesting	682	68		—	—			(281		)	—			—			(213		)
Purchase of treasury stock	—	—		—	(28		)	—			—			—			(28		)
Cash dividends at $0.07 per share	—	—		—	—			—			—			(29,605		)	(29,605		)
Other comprehensive loss	—	—		—	—			—			(137		)	—			(137		)
Balance at March 31, 2019	476,777	$	47,678	53,410	$	(1,334,716	)	$	1,762,861		$	4,300		$	1,840,816		$	2,320,939
Net income	—	—		—	—			—			—			181,009			181,009
Stock amortization and vesting	102	10		—	—			6,334			—			—			6,344
Purchase of treasury stock	—	—		5,081	(125,260		)	—			—			—			(125,260		)
Cash dividends at $0.09 per share	—	—		—	—			—			—			(38,092		)	(38,092		)
Other comprehensive loss	—	—		—	—			—			(136		)	—			(136		)
Balance at June 30, 2019	476,879	$	47,688	58,491	$	(1,459,976	)	$	1,769,195		$	4,164		$	1,983,733		$	2,344,804



(In thousands, except per share amounts)	Common Shares	Common Stock Par		Treasury Shares	Treasury Stock			Paid-In Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
Balance at December 31, 2017	475,547	$	47,555	14,936	$	(430,576	)	$	1,742,419	$	2,077		$	1,162,430		$	2,523,905
Net income	—	—		—	—			—		—			117,231			117,231
Stock amortization and vesting	534	53		—	—			249		—			—			302
Purchase of treasury stock	—	—		8,328	(207,135		)	—		—			—			(207,135		)
Cash dividends at $0.06 per share	—	—		—	—			—		—			(27,647		)	(27,647		)
Other comprehensive income	—	—		—	—			—		306			—			306
Cumulative impact from accounting change	—	—		—	—			—		—			(446		)	(446		)
Balance at March 31, 2018	476,081	$	47,608	23,264	$	(637,711	)	$	1,742,668	$	2,383		$	1,251,568		$	2,406,516
Net income	—	—		—	—			—		—			42,431			42,431
Exercise of stock appreciation rights	3	1		—	—			—		—			—			1
Stock amortization and vesting	2	—		—	—			6,769		—			—			6,769
Purchase of treasury stock	—	—		11,646	(274,337		)	—		—			—			(274,337		)
Cash dividends at $0.06 per share	—	—		—	—			—		—			(27,071		)	(27,071		)
Other comprehensive loss	—	—		—	—			—		(135		)	—			(135		)
Balance at June 30, 2018	476,086	$	47,609	34,910	$	(912,048	)	$	1,749,437	$	2,248		$	1,266,928		$	2,154,174

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 for the year ended December 31, ~~2016~~2018 (Form 10-K) filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications had no impact on previously reported stockholders' equity, net income (loss) or cash flows, except as discussed in "Recently Adopted Accounting Pronouncements" below.

Recently Adopted Accounting Pronouncements

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

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

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

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

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

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

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

~~Recently Issued Accounting Pronouncements~~

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

~~Leases.~~ ~~In February 2016, the FASB issued ASU No.~~ 2016-02, Leases ~~as a new Topic, ASC Topic 842.~~(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. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, which provides entities with an optional transition method that permits an entity to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The guidance is effective for interim and annual periods beginning after December 15, 2018. This ASU ~~is to be~~was adopted using a modified retrospective approach. The Company ~~plans to adopt~~adopted this guidance effective January 1, 2019 by applying the optional transition approach as of the beginning of the period of adoption. Comparative periods, including the disclosures related to those periods, were not restated.

On the adoption date, the Company elected the following practical expedients which are provided in the lease standard:

an election not to apply the recognition requirements in the lease 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 ~~currently evaluating~~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 ~~effect~~lease term;

a practical expedient that ~~adopting~~permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset class); and

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

On January 1, 2019, the Company recognized a right of use asset for operating leases and an operating lease liability of $44.6 million, representing the present value of the future minimum lease payment obligations associated with office leases, drilling rig commitments, surface use agreements and other leases. The adoption of this guidance ~~will~~did not have an impact on ~~its financial position,~~the Company’s results of operations or cash flows.

~~Revenue Recognition.~~ ~~In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, ASC Topic 606. The new revenue recognition standard provides a five-step analysis of transactions~~Refer 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 exchangeNote 8 for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption.

Additionally, in March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvements and practical expedients, which addresses narrow-scope improvements to the guidance on collectibility, non-cash consideration, and completed contracts at transition. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which clarifies the guidance or corrects unintended application of guidance.more details regarding leases.

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

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

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

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:



(In thousands)	June 30, 2019			December 31, 2018
Proved oil and gas properties	$	6,138,447		$	5,717,145
Unproved oil and gas properties	178,204			194,435
Land, building and other equipment	98,534			94,797
	6,415,185			6,006,377
Accumulated depreciation, depletion and amortization	(2,715,610		)	(2,542,771		)
	$	3,699,575		$	3,463,606

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

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

At ~~September~~June 30, ~~2017,~~2019, the Company did not have any projects that had exploratory well costs capitalized for a period of greater than one year after drilling.

~~Divestitures~~

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

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



	Constitution						Meade						Total
	Six Months Ended June 30,
(In thousands)	2019			2018			2019			2018			2019			2018
Balance at beginning of period	$	—		$	732		$	163,181		$	85,345		$	163,181		$	86,077
Contributions	500			250			4,631			62,655			5,131			62,905
Distributions	—			—			(9,508		)	—			(9,508		)	—
Earnings (loss) on equity method investments	(500		)	(982		)	7,834			(16		)	7,334			(998		)
Balance at end of period	$	—		$	—		$	166,138		$	147,984		$	166,138		$	147,984

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

~~During 2017, the Company expects to contribute approximately $70.0 million to its equity method investments.~~ For further information regarding the Company’s equity method investments, refer to Note 4 of the Notes to the Consolidated Financial Statements in the Form 10-K.

~~Constitution~~

On April 22, 2016, Constitution announced that the New York State Department of Environmental Conservation (NYSDEC) denied Constitution's application for a Section 401 Water Quality Certification (Certification) for the New York State portion of its proposed 126-mile route. During the second quarter of 2016, Constitution filed legal actions in the U.S. Court of Appeals for the Second Circuit and the U.S. District Court for the Northern District of New York challenging the legality and appropriateness of the NYSDEC’s decision. On March 16, 2017, the U.S. District Court for the Northern District of New York issued an order ruling, without prejudice, that it lacked subject matter jurisdiction to hear Constitution’s complaint. On August 18, 2017, the Second Circuit issued a decision denying in part and dismissing in part Constitution’s appeal. The Second Circuit determined that it lacked jurisdiction to address Constitution’s argument that the NYSDEC waived its ability to issue a Certification by unreasonably delaying action on Constitution's application. Instead, the Second Circuit found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. The Second Circuit, however, rejected Constitution’s assertion that the denial of the Certification by the NYSDEC was “arbitrary and capricious” and denied Constitution’s complaint in that regard. On October 11, 2017, Constitution filed a petition for a declaratory order requesting the Federal Energy Regulatory Commission (FERC) to find that, by operation of law, the Section 401 Water Quality Certification requirement for the New York State portion of the pipeline project was waived due to the failure of the NYSDEC to act on Constitution’s application within a reasonable period of time, as required by the Clean Water Act. The FERC has not yet ruled on this petition.

Constitution stated that it remains committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC’s decision. In light of the current status of the litigation and the regulatory challenges, Constitution estimates its target in-service date to be as early as the first half of 2019. This assumes the timely receipt of a notice to proceed from the FER~~C and the timely receipt of all other state and federal permits required for the project.~~

~~In light of the NYSDEC’s denial and actions taken to challenge the denial, the Company evaluated its investment in Constitution for other-th~~an-temporary impairment (OTTI) as of September 30, 2017 and does not believe there is an indication of an OTTI. The Company’s evaluation considered various factors, including but not limited to prior FERC approval and the related economic viability of the project, the pending legal and regulatory actions filed by Constitution and the other members’ commitment to the project. To the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is no longer viable or elects to not go forward as legal and regulatory actions progress, the Company will reevaluate the facts and circumstances relative to its conclusions with respect to OTTI. In the event that facts and circumstances change, the Company may be required to recognize an impairment charge up to its investment value at such time, net of any cash and working capital held by Constitution. The Company will continue to monitor the carrying value of its investment as required.

At this time, the Company remains committed to funding the project in an amount proportionate to its ownership interest for the development and construction of the new pipeline. As of September 30, 2017, the Company has made contributions of $92.3 million since inception of the project.

4. Debt and Credit Agreements

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



(In thousands)	June 30, 2019			December 31, 2018
6.51% weighted-average senior notes	$	124,000		$	124,000
5.58% weighted-average senior notes	175,000			175,000
3.65% weighted-average senior notes	925,000			925,000
Revolving credit facility	—			7,000
Unamortized debt issuance costs	(4,445		)	(4,896		)
	$	1,219,555		$	1,226,104

At June 30, 2019, the Company was in compliance with all restrictive financial covenants for both its revolving credit facility and senior notes.

(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
Revolving Credit Agreement

~~The borrowing base under~~On April 22, 2019, the ~~terms of the~~Company entered into a second amended and restated credit agreement (the revolving credit facility). The Company's revolving credit facility is unsecured and the borrowing base is redetermined annually ~~in April.~~on April 1. In addition, either the Company or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. ~~Effective April 11, 2017, the~~The Company’s borrowing base and available commitments under the revolving credit facility were ~~reaffirmed at~~ $3.2 billion and ~~$1.7~~$1.5 billion, respectively.

~~At September 30, 2017,~~ The maximum revolving credit available to the Company ~~was in compliance with all restrictive financial covenants for both its~~is the lesser of the available commitments or the difference of the borrowing base less outstanding senior notes. The

Company's revolving credit facility matures in April 2024 and ~~senior notes. As~~can be extended by one year upon the agreement of ~~September 30, 2017,~~the Company and lenders holding at least 50 percent of the commitments under the revolving credit facility.

Interest rates under the revolving credit facility are based on LIBOR or ABR indications, plus a margin which ranges from 150 to 225 basis points for LIBOR loans and from 50 to 125 basis points for ABR loans when not in an Investment Grade Period (as defined in the ~~Company's~~amended and restated credit agreement) and from 112.5 to 175 basis points for LIBOR loans and from 12.5 to 75 basis points for ABR loans during an Investment Grade Period. The revolving credit facility also provides for a commitment fee on the unused available balance and is calculated at annual rates ranging from 30 to 42.5 basis points when not in an Investment Grade Period and from 12.5 to 27.5 basis points during an Investment Grade Period. The Company is currently not in an Investment Grade Period.

The revolving credit facility contains various customary covenants, which include the following (with all calculations based on definitions contained in the amended and restated credit agreement):

Maintenance of a minimum asset coverage ~~and leverage ratios, there were no~~ratio of 1.75 to 1.0;

Maintenance of a minimum annual coverage ratio of consolidated cash flow to interest ~~rate adjustments required~~expense for the ~~Company's senior notes.~~trailing four quarters of 2.8 to 1.0; and

Maintenance of a minimum current ratio of 1.0 to 1.0.

At ~~September~~June 30, ~~2017,~~2019, the Company had no borrowings outstanding under its revolving credit facility and had unused commitments of ~~$1.7~~$1.5 billion.

The ~~Company’s weighted-average effective interest rate for~~Company incurred $7.4 million of debt issuance costs in connection with the ~~revolving~~amended and restated credit ~~facility for~~agreement, which were capitalized and will be amortized over the ~~nine months ended September 30, 2016 was approximately 2.3%.~~term of the amended and restated agreement. The remaining unamortized costs of $3.4 million will also be amortized over the term of the amended and restated agreement in accordance with ASC 470-50, Debt Modifications and Extinguishments.

5. Derivative Instruments ~~and Hedging Activities~~

As of ~~September~~June 30, ~~2017,~~2019, the Company had the following outstanding financial commodity derivatives:



			Swaps		Basis Swaps
Type of Contract	Volume (Mmbtu)	Contract Period	Weighted-Average ($/Mmbtu)		Weighted-Average ($/Mmbtu)
Natural gas (IFERC TRANSCO Z6 non-NY)	5,520,000	Jul. 2019 - Dec. 2019			$	0.41
Natural gas (IFERC TRANSCO Z6 non-NY)	18,450,000	Jul. 2019 - Oct. 2019	$	2.61
Natural gas (IFERC TRANSCO Leidy Line Receipts)	27,600,000	Jul. 2019 - Dec. 2019			$	(0.53	)
Natural gas (NYMEX)	43,050,000	Jul. 2019 - Oct. 2019	$	2.85
Natural gas (NYMEX)	55,200,000	Jul. 2019 - Dec. 2019	$	2.82

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

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

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet



		Derivative Assets				Derivative Liabilities
(In thousands)	Balance Sheet Location	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Commodity contracts	Derivative instruments (current)	$	61,194	$	57,665	$	—	$	—
		$	61,194	$	57,665	$	—	$	—

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

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



(In thousands)	June 30, 2019			December 31, 2018
Derivative assets
Gross amounts of recognized assets	$	62,808		$	60,105
Gross amounts offset in the statement of financial position	(1,614		)	(2,440		)
Net amounts of assets presented in the statement of financial position	61,194			57,665
Gross amounts of financial instruments not offset in the statement of financial position	—			—
Net amount	$	61,194		$	57,665

Derivative liabilities
Gross amounts of recognized liabilities	$	1,614		$	2,440
Gross amounts offset in the statement of financial position	(1,614		)	(2,440		)
Net amounts of liabilities presented in the statement of financial position	—			—
Gross amounts of financial instruments not offset in the statement of financial position	—			—
Net amount	$	—		$	—

(In thousands) September 30,
2017 December 31,
2016
Derivative assets

Gross amounts of recognized assets $ 6,605
$ 2,991
Gross amounts offset in the statement of financial position (306 ) —
Net amounts of assets presented in the statement of financial position 6,299
2,991
Gross amounts of financial instruments not offset in the statement of financial position 18
—
Net amount $ 6,317
$ 2,991

Derivative liabilities

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

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations



	Three Months Ended June 30,					Six Months Ended June 30,
(In thousands)	2019		2018			2019		2018
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	15,397	$	5,819		$	68,377	$	(20,312	)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	48,252		(9,487		)	3,529		22,221
	$	63,649	$	(3,668	)	$	71,906	$	1,909

Three Months Ended
September 30, Nine Months Ended
September 30,
(In thousands) 2017 2016 2017 2016
Cash received (paid) on settlement of derivative instruments

Gain (loss) on derivative instruments $ 3,906
$ (8,101 ) $ 3,587
$ 3,204
Non-cash gain (loss) on derivative instruments

Gain (loss) on derivative instruments (4,742 ) 15,005
42,766
(4,490 )
$ (836 ) $ 6,904
$ 46,353
$ (1,286 )

6. Fair Value Measurements

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

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 June 30, 2019
Assets
Deferred compensation plan	$	14,336	$	—	$	—	$	14,336	$	16,962	$	—	$	—	$	16,962
Derivative instruments	—		—		6,605		6,605		—		48,571		14,237		62,808
Total assets	$	14,336	$	—	$	6,605	$	20,941	$	16,962	$	48,571	$	14,237	$	79,770
Liabilities
Deferred compensation plan	$	27,598	$	—	$	—	$	27,598	$	28,345	$	—	$	—	$	28,345
Derivative instruments	—		178		928		1,106		—		—		1,614		1,614
Total liabilities	$	27,598	$	178	$	928	$	28,704	$	28,345	$	—	$	1,614	$	29,959



(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, 2018
Assets
Deferred compensation plan	$	14,699	$	—	$	—	$	14,699
Derivative instruments	—		35,689		24,416		60,105
Total assets	$	14,699	$	35,689	$	24,416	$	74,804
Liabilities
Deferred compensation plan	$	25,780	$	—	$	—	$	25,780
Derivative instruments	—		—		2,440		2,440
Total liabilities	$	25,780	$	—	$	2,440	$	28,220

(In thousands)
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)

Significant Other
Observable Inputs
(Level 2)

Significant
Unobservable Inputs
(Level 3)
Balance at
December 31, 2016
Assets

Deferred compensation plan $ 12,587
$ —
$ —
$ 12,587
Derivative instruments —
—
2,991
2,991
Total assets $ 12,587
$ —
$ 2,991
$ 15,578
Liabilities

Deferred compensation plan $ 24,169
$ —
$ —
$ 24,169
Derivative instruments �� —
21,400
18,859
40,259
Total liabilities $ 24,169
$ 21,400
$ 18,859
$ 64,428

The ~~Company’s~~Company's investments associated with its deferred compensation plan consist of mutual funds and deferred shares of the ~~Company’s~~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.~~Company's counterparties and/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 commodity 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 derived from or 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~~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~~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’~~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:



	Six Months Ended June 30,
(In thousands)	2019			2018
Balance at beginning of period	$	21,976		$	(28,398	)
Total gain (loss) included in earnings	17,080			9,019
Settlement (gain) loss	(26,433		)	18,040
Balance at end of period	$	12,623		$	(1,339	)

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	7,252		$	(1,276	)

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

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

There were no transfers between Level 1 and Level 2 fair value measurements for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016.~~2018.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments or acquisitions, 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~~June 30, ~~2017,~~2019, 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:



	June 30, 2019				December 31, 2018
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	1,219,555	$	1,245,889	$	1,226,104	$	1,202,994

September 30, 2017 December 31, 2016
(In thousands)
Carrying
Amount

Estimated Fair
Value

Carrying
Amount

Estimated Fair
Value
Debt, net $ 1,521,551
$ 1,536,360
$ 1,520,530
$ 1,463,643
Current maturities (237,000 ) (243,569 ) —
—
Long-term debt, excluding current maturities $ 1,284,551
$ 1,292,791
$ 1,520,530
$ 1,463,643

7. Asset Retirement Obligations

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



(In thousands)	Six Months Ended June 30, 2019
Balance at beginning of period⁽¹⁾	$	51,622
Liabilities incurred	3,159
Liabilities settled	(970		)
Liabilities divested	(188		)
Accretion expense	1,733
Balance at end of period⁽¹⁾	$	55,356

_______________________________________________________________________________

(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 $1.0 million of current asset retirement obligations included in accrued liabilities at June 30, 2019 and December 31, 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” and “Hydraulic Fracturing Services Commitments”~~Agreements” as disclosed in Note 9 inof the Notes to Consolidated Financial Statements in the Form 10-K.

Lease Commitments (Topic 840)

Future minimum rental commitments under non-cancelable leases in effect at December 31, 2018 are as follows:



(In thousands)
2019	$	5,571
2020	5,684
2021	4,777
2022	1,659
2023	1,691
Thereafter	2,852
	$	22,234

The table above was prepared under the guidance of Topic 840. As discussed in Note 1 above, the Company adopted the guidance of Topic 842 effective January 1, 2019.

Leases (Topic 842)

The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Operating leases are included in operating lease right-of-use assets (ROU assets) and operating lease liabilities (current and noncurrent) on the Condensed Consolidated Balance Sheet. The Company does not have any finance leases at June 30, 2019.

ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the leases. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of minimum lease payments over the lease term. Most leases do not provide an implicit interest rate; therefore, the Company used its incremental borrowing rate based on the information available at the inception date to determine the present value of the lease payments. Lease terms include options to extend the lease when it is reasonably certain that the Company will exercise that option. Lease cost for lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities.

For all operating leases, lease and non-lease components are accounted for as a single lease component.

The Company has operating leases for office space, drilling rig commitments, surface use agreements and other leases. The leases have remaining terms ranging from less than one month to 26.5 years, including options to extend leases that the Company is reasonably certain to exercise. During the six months ended June 30, 2019, the Company recognized operating lease cost and variable lease cost of $6.0 million and $3.5 million, respectively.

Short-term leases. The Company leases drilling rigs, fracturing and other equipment under lease terms ranging from 30 days to one year. Lease cost of $157.7 million was recognized on short-term leases during the six months ended June 30, 2019. Certain lease costs are capitalized and included in Properties and equipment, net in the Condensed Consolidated Balance Sheet because they relate to drilling and completion activities, while other costs are expensed because they relate to production and administrative activities.

As of June 30, 2019, the Company’s future undiscounted minimum cash payment obligations for its operating lease liabilities are as follows:



(In thousands)	Year Ending December 31,
2019 (excluding the six months ended June 30, 2019)	$	5,302
2020	4,549
2021	4,575
2022	4,577
2023	4,613
Thereafter	29,824
Total undiscounted lease payments	53,440
Present value adjustment	(13,861		)
Net operating lease liabilities	$	39,579

Supplemental cash flow information related to leases was as follows:



(In thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1,124	$	2,247
Investing cash flows from operating leases	$	1,811	$	3,602

Information regarding the weighted-average remaining lease term and the weighted-average discount rate for operating leases is summarized below:



	June 30, 2019
Weighted-average remaining lease term (in years)
Operating leases	11.7
Weighted-average discount rate
Operating leases	4.9	%

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~~Revenue Recognition

~~Postretirement Benefits~~Disaggregation of Revenue

The ~~change~~following table presents revenues disaggregated by product:



	Three Months Ended June 30,						Six Months Ended June 30,
(In thousands)	2019			2018			2019		2018
OPERATING REVENUES
Natural gas	$	470,482		$	364,660		$	1,103,656	$	776,768
Crude oil and condensate	—			—			—		48,722
Brokered natural gas	—			92,576			—		97,526
Other	(14		)	(121		)	236		1,749
Total revenues from contracts with customers	470,468			457,115			1,103,892		924,765
Gain (loss) on derivative instruments	63,649			(3,668		)	71,906		1,909
Total operating revenues	$	534,117		$	453,447		$	1,175,798	$	926,674

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

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales contracts 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 ~~as follows:~~part of a contract that has an original expected duration of one year or less.

(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~~As of ~~properties located in West Virginia, Virginia and Ohio,~~June 30, 2019, the Company ~~terminated approximately 100 employees. As~~has $9.8 billion of unsatisfied performance obligations related to natural gas sales that have a ~~result,~~fixed pricing component and a contract term greater than one year. The Company expects to recognize these obligations over periods ranging from five to 20 years.

Contract Balances

Receivables from contracts with customers are recorded when the ~~employees’ participation in the postretirement plan terminated, which resulted in a remeasurement and curtailment~~right to consideration becomes unconditional, generally when control of the ~~postretirement benefit obligation at September~~product has been transferred to the customer. Receivables from contracts with customers were $183.7 million and $363.0 million as of June 30, ~~2017.~~

2019 and December 31, 2018, respectively, and are reported in accounts receivable, net on the Condensed Consolidated Balance Sheet. 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~~Company currently has no assets or liabilities related to ~~a Medicare Advantage program for participants age 65 and older. This coverage continues~~its revenue contracts, including no upfront or rights 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
deficiency payments.

10. Capital Stock

Treasury Stock

In ~~August 1998,~~July 2019, the Board of Directors authorized aan increase of 25.0 million shares to the Company’s share repurchase ~~program under which~~program. After this authorization, the ~~Company may purchase~~total number of 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, oravailable for ~~other corporate purposes. All purchases executed to date have been through open market transactions. There~~repurchase is ~~no expiration date associated with the authorization to repurchase common stock of the Company.~~

~~During the first nine months of 2017, the Company repurchased 3.0~~31.5 million shares for a total cost of $68.3 million. Since the authorization date, the Company has repurchased 32.9 million shares of the 40.0 million total shares authorized for a total cost of approximately $456.6 million, of which 20.0 million shares have been retired. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. As of September 30, 2017, 12.9 million shares were held as treasury stock.shares.

11. Stock-based Compensation

General

~~From time to time the~~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~~$6.7 million and ~~$5.1~~$5.7 million in the ~~third~~second quarter of ~~2017~~2019 and ~~2016,~~2018, respectively, and ~~$26.2~~$21.9 million and ~~$23.0~~$11.1 million during the first ~~nine~~six months of ~~2017~~2019 and ~~2016,~~2018, 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~~For the ~~Condensed Consolidated Financial Statements, effective January 1, 2017,~~first six months of 2019, the Company ~~adopted ASU No. 2016-09, which requires that excess~~recorded a decrease to tax ~~benefits~~expense of $0.9 million as a result of federal and state tax ~~deficiencies on~~deductions exceeding the book compensation expense for employee stock-based compensation ~~be recorded in~~awards that vested during the ~~income statement. During~~period. For the first ~~nine~~six months of ~~2017,~~2018, the Company recorded an increase to tax expense of ~~$2.6~~$0.2 million ~~in the Condensed Consolidated Statement of Operations~~ as a result

of book compensation ~~cost for employee stock-based compensation~~expense exceeding the federal and state tax deductions for ~~awards that vested during the period.~~

Prior to the adoption of ASU No. 2016-09, windfall tax benefits were recorded in additional paid in capital in the Condensed Consolidated Balance Sheet and tax shortfalls reduced additional paid in capital to the extent they offset previously recorded windfall tax benefits. During the first nine months of 2016, the Company recorded a tax shortfall of $2.1 million, resulting in a reduction of the Company's windfall tax benefit that was recorded in additional paid in capital in the Condensed Consolidated Balance Sheet. The tax shortfall was a result of book compensation cost for employee stock-based compensation ~~exceeding the federal and state tax deductions for certain~~ awards that vested during the period.

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

Restricted Stock Units

During the first ~~nine~~six months of ~~2017, 57,028~~2019, 78,290 restricted stock units were granted to non-employee directors of the Company with a weighted-average grant date value of ~~$22.94~~$25.01 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~~six months of ~~2017~~2019 commenced on January 1, ~~2017~~2019 and ends on December 31, ~~2019.~~2021. The Company used an annual forfeiture rate assumption ranging from 0%zero percent to 6%five percent 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~~June 30, ~~2017,~~2019, 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~~six months of ~~2017, 406,460~~2019, 526,730 Employee Performance Share Awards were granted at a grant date value of ~~$22.60~~$24.95 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~~six months of ~~2017, 272,920~~2019, 315,029 Hybrid Performance Share Awards were granted at a grant date value of ~~$22.60~~$24.95 per share. The ~~2017~~2019 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~~six months of ~~2017, 409,380~~2019, 536,673 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)~~19, 2019) and the period-end fair value of the liability component of the TSR Performance Share Awards:



	Grant Date			June 30, 2019
Fair value per performance share award	$	20.63		$11.46 - $22.04
Assumptions:
Stock price volatility	31.3		%	24.28% - 29.01%
Risk free rate of return	2.46		%	1.72%-2.08%

Grant Date September 30, 2017
Fair value per performance share award $ 19.85
$12.28-$20.22
Assumptions:

Stock price volatility 37.8 % 20.8% - 39.9%
Risk free rate of return 1.4 % 1.1% - 1.5%

12. Earnings per Common Share

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

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



	Three Months Ended June 30,		Six Months Ended June 30,
(In thousands)	2019	2018	2019	2018
Weighted-average shares - basic	422,141	451,055	422,626	455,361
Dilution effect of stock awards at end of period	2,208	2,059	1,924	1,781
Weighted-average shares - diluted	424,349	453,114	424,550	457,142

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

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



	Three Months Ended June 30,		Six Months Ended June 30,
(In thousands)	2019	2018	2019	2018
Weighted-average stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method	14	—	948	956

Three Months Ended
September 30, Nine Months Ended
September 30,
(In thousands) 2017 2016 2017 2016
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect due to net loss —
1,784
—
1,326
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method 2
—
6
1
Weighted-average stock appreciation rights and stock awards excluded from diluted EPS due to the anti-dilutive effect 2
1,784
6
1,327

13. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:



(In thousands)	June 30, 2019			December 31, 2018
Accounts receivable, net
Trade accounts	$	183,700		$	362,973
Joint interest accounts	64			101
Other accounts	796			567
	184,560			363,641
Allowance for doubtful accounts	(1,184		)	(1,238		)
	$	183,376		$	362,403
Other assets
Deferred compensation plan	$	16,962		$	14,699
Debt issuance costs	9,971			4,572
Income taxes receivable	—			8,165
Operating lease right-of-use assets	39,690			—
Other accounts	63			61
	$	66,686		$	27,497
Accounts payable
Trade accounts	$	35,178		$	30,033
Natural gas purchases	8,487			—
Royalty and other owners	32,597			61,507
Accrued transportation	49,373			50,540
Accrued capital costs	46,376			43,207
Taxes other than income	8,691			19,824
Income taxes payable	—			1,134
Other accounts	4,258			35,694
	$	184,960		$	241,939
Accrued liabilities
Employee benefits	$	17,873		$	21,761
Taxes other than income	3,664			1,472
Operating lease liabilities	5,782			—
Asset retirement obligations	1,000			1,000
Other accounts	865			994
	$	29,184		$	25,227
Other liabilities
Deferred compensation plan	$	28,345		$	25,780
Operating lease liabilities	33,797			—
Other accounts	8,809			34,391
	$	70,951		$	60,171

(In thousands) September 30,
2017 December 31,
2016
Accounts receivable, net

Trade accounts $ 162,069
$ 185,594
Joint interest accounts 1,208
1,359
Other accounts 425
5,335
163,702
192,288
Allowance for doubtful accounts (2,012 ) (1,243 )
$ 161,690
$ 191,045

Inventories

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

Other current assets

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

Other assets

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

Accounts payable

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

Accrued liabilities

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

Other liabilities

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

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

The following review of operations for the three and ~~nine~~six month periods ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Corporation Annual Report on Form 10-K for the year ended December 31, ~~2016~~2018 (Form 10-K).

OVERVIEW

Financial and Operating Overview

Financial and operating results for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2018 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~~81.6 Bcf, or ~~11%~~24%, from ~~441.8~~337.0 Bcf in ~~2016~~2018 to ~~491.2~~418.6 Bcf in ~~2017,~~2019, as a result of drilling and completion activities in Pennsylvania.

~~Crude oil/condensate/NGL~~Equivalent production increased ~~0.1 Mmbbls,~~76.6 Bcfe, or 2%22%, from ~~3.5 Mmbbls~~342.0 Bcfe, or 1,889.5 Mmcfe per day, in ~~2016~~2018 to ~~3.6 Mmbbls~~418.6 Bcfe, or 2,312.6 Mmcfe per day, in ~~2017, as result of an~~2019. The increase inis primarily due to drilling and completion ~~activity~~activities in Pennsylvania, partially offset by the sale of our Eagle Ford Shale assets in south Texas ~~partially offset by a natural decline~~ in ~~production.~~February 2018.

Average realized natural gas price was ~~$2.35~~$2.80 per Mcf, ~~45%~~22% higher than the ~~$1.62~~$2.29 per Mcf ~~realized in the comparable period of the prior year.~~

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

Total capital expenditures were ~~$582.8~~$424.7 million compared to ~~$262.1~~$329.9 million in the comparable period of the prior year.

Drilled 7149 gross wells ~~(62.5~~(49.0 net) with a success rate of ~~98.6%~~100% compared to 2839 gross wells ~~(28.0~~(39.0 net) with a success rate of ~~100%~~87.2% for the comparable period of the prior year.

Completed 8142 gross wells ~~(70.2~~(42.0 net) in ~~2017~~2019 compared to 5134 gross wells ~~(51.0~~(34.0 net) in ~~2016.~~2018.

Average rig count during ~~2017~~2019 was approximately ~~2.0~~3.2 rigs in the Marcellus Shale, ~~approximately 1.0 rig in the Eagle Ford Shale and approximately 0.2 rigs in other areas,~~ compared to an average rig count in the Marcellus Shale of approximately ~~1.1~~3.0 rigs and approximately ~~0.3 rigs~~1.0 rig in ~~the Eagle Ford Shale in 2016.~~

~~Received proceeds of $32.7 million primarily related to the divestiture of certain oil and gas properties and related pipeline assets in West Virginia, Virginia and Ohio.~~other areas during 2018.

Repurchased ~~3.0~~5.1 million shares of our common stock for a total cost of ~~$68.3 million.~~$125.3 million in 2019.

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 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~~“Results of ~~Operations”~~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 associated with our derivative instruments, we will

~~likely~~ experience volatility in our earnings due to commodity price volatility. Refer to ~~“Impact~~“Impact of Derivative Instruments on Operating ~~Revenues”~~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~~been and are expected to the fourth quarter of 2016. In the event that commodity prices significantly decline, management would test the recoverability of the carrying value of its oil and gas properties and, if necessary, record an impairment charge.

remain volatile. We believe that we are well-positioned to manage the challenges presented in a ~~depressed~~volatile 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~~While we are unable to ~~an improvement~~predict future commodity prices, in the event that commodity ~~price outlook, we increased our 2017 budgeted~~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.

Outlook

Our 2019 capital ~~expenditures compared to 2016. Our full year 2017 capital spending~~ program includes approximately $775.0 million in capital expenditures related to our drilling and completion program, leasehold acquisitions and contributions of approximately $70.0 million to our equity method investments. All such expenditures areis expected to be ~~funded by existing~~approximately $800.0 million to $820.0 million. We expect to fund these expenditures with our cash on hand, operating cash flow and, if required, borrowings under our revolving credit facility.

In ~~2016,~~2018, we drilled 4097 gross wells ~~(38.0~~(95.1 net) and completed 7694 gross wells ~~(76.0~~(93.0 net), of which 6227 gross wells ~~(62.0~~(27.0 net) were drilled but uncompleted in prior years. ~~In 2017,~~For the full year of 2019, our capital program will focus on the Marcellus Shale, where we ~~plan~~expect to drill ~~100 gross wells (95.0 net)~~ and complete ~~95 gross~~approximately 90.0 net wells ~~(90.0 net), of which 51 gross~~and place approximately 85 net 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.~~on production. 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~~six months ended ~~September~~June 30, ~~2017~~2019 were primarily from the sale of natural gas ~~and crude oil production and proceeds from the sale of assets.~~production. These cash flows were ~~primarily~~ used to fund our capital expenditures, ~~(including contributions to our equity method investments),~~ interest payments on debt, ~~repurchase~~repurchases of shares of ~~our~~ common stock and payment of dividends. See below for additional discussion and analysis of cash flow.

On April 22, 2019, we entered into a second amended and restated credit agreement (the revolving credit facility) . The borrowing base under the terms of our revolving credit facility is redetermined annually in April. In addition, either we or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. ~~Effective April 11, 2017, the borrowing base and available commitments~~As of June 30, 2019, there were ~~reaffirmed at $3.2 billion and $1.7 billion, respectively. There were~~ no borrowings outstanding under our revolving credit facility asand our unused commitments were $1.5 billion. Refer to Note 4 of ~~September 30, 2017.~~the Notes to the Condensed Consolidated Financial Statements for more information.

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

At ~~September~~June 30, ~~2017,~~2019, we were in compliance with all restrictive financial covenants for both the revolving credit facility and senior notes. ~~As of September 30, 2017, based on our asset coverage and leverage ratios, there were no interest rate adjustments required for our senior notes.~~ See our Form 10-K for further discussion of our restrictive financial covenants.

Cash Flows

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


	Nine Months Ended September 30,						Six Months Ended June 30,
(In thousands)	2017			2016			2019			2018
Cash flows provided by operating activities	$	719,047		$	257,705		$	911,937		$	546,660
Cash flows used in investing activities	(577,484		)	(220,141		)
Cash flows provided by (used in) financing activities	(129,849		)	463,115
Cash flows (used in) provided by investing activities							(423,527		)	196,692
Cash flows used in financing activities							(249,303		)	(482,405		)
Net increase in cash and cash equivalents	$	11,714		$	500,679		$	239,107		$	260,947

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~~Commodity prices 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~~June 30, ~~2017~~2019 and December 31, ~~2016,~~2018, we had a working capital surplus of ~~$279.8~~$397.3 million and ~~$458.1~~$257.3 million, respectively. We believe that we have adequate liquidity and availability under our revolving credit facility to meet our working capital requirements over the next twelve months.

Net cash provided by operating activities in the first ~~nine~~six months of ~~2017~~2019 increased by ~~$461.3~~$365.3 million compared to the first ~~nine~~six months of ~~2016.~~2018. This increase was primarily due to higher operating revenues, ~~partially offset by higher cash~~lower operating ~~expenses.~~expenses and favorable changes in working capital. The increase in operating revenues was primarily due to ~~an increase in~~higher equivalent production and higher realized natural gas ~~and crude oil prices and higher equivalent production.~~prices. Average realized natural gas ~~and crude oil~~ prices increased by ~~45% and 27%, respectively,~~22% for the first ~~nine~~six months of ~~2017~~2019 compared to the first ~~nine~~six months of ~~2016.~~2018. Equivalent production increased by ~~11%~~22% for the first ~~nine~~six months of ~~2017~~2019 compared to the first ~~nine~~six months of ~~2016 driven by~~2018 due to higher natural gas production in the Marcellus Shale.

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

Investing Activities.Cash flows used in investing activities increased by ~~$357.3~~$620.2 million for the first ~~nine~~six months of ~~2017~~2019 compared to the first ~~nine~~six months of ~~2016.~~2018. The increase was due to ~~$341.8 million higher capital expenditures and $16.4~~$644.5 million lower proceeds from the sale of assets and $34.2 million higher capital expenditures. These changes were partially offset by ~~$0.8~~$57.8 million lower capital contributions associated with our equity method investments.

Financing Activities.Cash flows ~~provided by~~used in financing activities decreased by ~~$593.0~~$233.1 million for the first ~~nine~~six months of ~~2017~~2019 compared to the first ~~nine~~six months of ~~2016.~~2018. This decrease was primarily due to ~~$995.3~~$263.0 million ~~lower net proceeds from the issuance~~ of ~~common stock in 2016, $68.3 million of~~lower repurchases of our common stock in ~~2017 and $28.8~~2019 compared to 2018. This decrease was partially offset by $13.0 million of higher dividend payments related to an increase in ~~the~~our dividend rate from $0.12 per share for the first six months of 2018 to $0.16 per share in the first six months of 2019 and $2.5 million higher tax withholdings on vesting stock awards. During the ~~issuance of common stock in 2016. These decreases were partially offset by $497.0~~six months ended June 30, 2019, we repaid $7.0 million of ~~lower~~ net ~~repayments of debt due to the repayment of the outstanding balance on~~borrowings under our revolving credit ~~facility~~facility. Treasury stock repurchases for the six months ended June 30, 2019 include $31.4 million of share repurchases that were accrued in 2018 and ~~certain of our senior notes with the proceeds from the issuance of common stock~~paid in ~~2016.~~

2019.

Capitalization

Information about our capitalization is as follows:



(In thousands)	June 30, 2019			December 31, 2018
Debt ⁽¹⁾	$	1,219,555		$	1,226,104
Stockholders' equity	2,344,804			2,088,159
Total capitalization	$	3,564,359		$	3,314,263
Debt to total capitalization	34		%	37		%
Cash and cash equivalents	$	241,394		$	2,287

(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~~$7.0 million of ~~current portion~~borrowings outstanding under our revolving credit facility as of ~~long-term debt at September 30, 2017.~~December 31, 2018.

During the first ~~nine~~six months of ~~2017,~~2019 and 2018, we repurchased ~~3.0~~5.1 million shares of our common stock for ~~$68.3 million. We also~~$125.3 million and 20.0 million shares of our common stock for $481.5 million, respectively. During the first six months of 2019 and 2018, we paid dividends of ~~$55.7~~$67.7 million ($0.16 per share) and $54.7 million ($0.12 per share), respectively, on our common stock.

In ~~May 2017,~~April 2019, the Board of Directors approved an increase in the quarterly dividend on our common stock from ~~$0.02~~$0.07 per share to ~~$0.05~~$0.09 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,				Six Months Ended June 30,
(In thousands)	2017		2016		2019		2018
Capital expenditures
Drilling and facilities	$	475,240	$	255,139	$	415,431	$	313,900
Leasehold acquisitions	97,835		1,687		3,246		11,344
Pipeline and gathering	597		1,009
Other	9,091		4,251		5,975		4,667
	582,763		262,086		424,652		329,911
Exploration expenditures	16,623		13,109
Exploration expenditures⁽¹⁾					10,548		58,117
Total	$	599,386	$	275,195	$	435,200	$	388,028


(1)	Exploratory dry hole expenditures included in exploration expenditures for the first six months of 2019 were not significant. Exploration expenditures include $51.1 million of exploratory dry hole expenditures for the first six months of 2018.

For the full year of ~~2017,~~2019, our capital program will focus on the Marcellus Shale, where we ~~plan~~expect to drill ~~approximately 100 gross wells (95.0 net)~~ and complete ~~95 gross~~approximately 90.0 net wells ~~(90.0 net), of which 51 gross~~and place approximately 85 net wells ~~(45.0 net) were drilled but uncompleted in prior years.~~on production. In ~~2017,~~2019, our drilling program includes approximately ~~$775.0~~$800.0 million to $820.0 million in total capital expenditures compared to ~~$372.5~~$816.1 million in ~~2016.~~2018. See ~~“Outlook”~~“Outlook” for additional information regarding the current year drilling program. We will continue to assess the ~~natural gas and crude oil~~commodity 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.

Critical Accounting Policies and Estimates

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

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

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~~Second Quarters of ~~2017~~2019 and ~~2016~~2018 Compared

We reported net income in the ~~third~~second quarter of ~~2017~~2019 of ~~$17.6~~$181.0 million, or ~~$0.04~~$0.43 per share, compared to a net ~~loss~~income of ~~$10.3~~$42.4 million, or ~~$0.02~~$0.09 per share, in the ~~third~~second quarter of ~~2016.~~2018. The increase in net income was primarily due to higher operating revenues and lower operating expenses and interest expense, partially offset by higher ~~operating expenses, loss on sale of assets and~~ income tax expense.

Revenue, Price and Volume Variances

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


	Three Months Ended September 30,					Variance					Three Months Ended June 30,						Variance
Revenue Variances (In thousands)	2017			2016		Amount			Percent		2019			2018			Amount			Percent
Natural gas	$	323,319		$	260,200	$	63,119		24	%	$	470,482		$	364,660		$	105,822		29	%
Crude oil and condensate	56,913			37,777		19,136			51	%
Gain (loss) on derivative instruments	(836		)	6,904		(7,740		)	(112	)%	63,649			(3,668		)	67,317			1,835	%
Brokered natural gas	3,528			3,641		(113		)	(3	)%	—			92,576			(92,576		)	(100	)%
Other	2,492			1,907		585			31	%	(14		)	(121		)	107			88	%
	$	385,416		$	310,429	$	74,987		24	%	$	534,117		$	453,447		$	80,670		18	%


	Three Months Ended September 30,				Variance				Increase (Decrease) (In thousands)		Three Months Ended June 30,				Variance				Increase (Decrease) (In thousands)
	2017		2016		Amount		Percent		Increase (Decrease) (In thousands)		2019		2018		Amount		Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	2.01	$	1.80	$	0.21	12	%	$	32,879	$	2.20	$	2.11	$	0.09	4	%	$	18,468
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	213.8		172.4		41.4		24	%	$	87,354
Crude oil and condensate (Mbbl)	1,268		941		327		35	%	13,123
Total									$	43,363									$	105,822

Natural Gas Revenues

The increase in natural gas revenues of ~~$63.1~~$105.8 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 in crude oil and condensate revenues of $19.1 million was due to higher crude oil prices and production. The increase in production was a result of an increase in our drilling and completion activities in south Texas.

Impact of Derivative Instruments on Operating Revenues


	Three Months Ended September 30,						Three Months Ended June 30,
(In thousands)	2017			2016			2019		2018
Cash received (paid) on settlement of derivative instruments
Gain (loss) on derivative instruments	$	3,906		$	(8,101	)	$	15,397	$	5,819
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	(4,742		)	15,005			48,252		(9,487		)
	$	(836	)	$	6,904		$	63,649	$	(3,668	)

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
Brokered natural gas decreased $92.6 million. There was no brokered natural gas activity in the current period.

Operating and Other Expenses


	Three Months Ended September 30,						Variance					Three Months Ended June 30,					Variance
(In thousands)	2017			2016			Amount			Percent		2019		2018			Amount			Percent
Operating and Other Expenses
Direct operations	$	26,282		$	24,626		$	1,656		7	%	$	18,093	$	15,657		$	2,436		16	%
Transportation and gathering	117,891			105,671			12,220			12	%	141,689		114,189			27,500			24	%
Brokered natural gas	2,797			2,939			(142		)	(5	)%	—		80,082			(80,082		)	(100	)%
Taxes other than income	9,194			8,771			423			5	%	3,640		5,392			(1,752		)	(32	)%
Exploration	6,466			2,988			3,478			116	%	4,504		54,500			(49,996		)	(92	)%
Depreciation, depletion and amortization	146,267			139,490			6,777			5	%	96,147		84,910			11,237			13	%
General and administrative	23,244			19,374			3,870			20	%	22,889		21,228			1,661			8	%
	$	332,141		$	303,859		$	28,282		9	%	$	286,962	$	375,958		$	(88,996	)	(24	)%

Earnings (loss) on equity method investments	$	(1,417	)	$	(1,727	)	$	310		(18	)%	$	3,650	$	(4	)	$	(3,654	)	(91,350	)%
Loss on sale of assets	(11,872		)	(1,245		)	(10,627		)	854	%
Gain (loss) on sale of assets												—		544			544			100	%
Interest expense, net	20,331			21,483			(1,152		)	(5	)%	14,567		23,328			(8,761		)	(38	)%
Other expense (income)	(5,083		)	402			(5,485		)	(1,364	)%
Income tax expense (benefit)	7,151			(8,027		)	15,178			189	%
Other expense												143		118			25			21	%
Income tax expense												55,086		12,152			42,934			353	%

Total costs and expenses from operations ~~increased~~decreased by ~~$28.3~~$89.0 million, or 9%24%, in the ~~third~~second quarter of ~~2017~~2019 compared to the same period of ~~2016.~~2018. The primary reasons for this fluctuation are as follows:

Direct operations increased ~~$1.7~~$2.4 million ~~largely due to 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~~$27.5 million due to higher ~~throughput as a result of higher~~ Marcellus Shale production.

Brokered natural gas decreased ~~$0.1~~$80.1 million. ~~See~~There was no brokered natural gas activity in the ~~preceding table titled “Brokered Natural Gas” for further analysis.~~

current period.

Taxes other than income ~~increased $0.4~~decreased $1.8 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 in taxes other than income were not individually significant.~~

Exploration ~~increased $3.5~~decreased $50.0 million ~~primarily as~~due to a ~~result of higher geophysical~~decrease in exploratory dry hole costs of ~~$2.0 million~~$51.1 million. The exploratory dry hole costs in 2018 related to our activities in west Texas.

Depreciation, depletion and amortization increased ~~$6.8~~$11.2 million primarily due to higher DD&A of $12.8 million, partially offset by lower amortization of unproved properties of ~~$9.4 million, partially offset by lower DD&A of $1.4~~$1.9 million in the ~~third~~second quarter of ~~2017.~~2019. The increase in ~~amortization of unproved properties is~~DD&A was primarily due to an increase of $18.4 million related to higher production volumes in ~~leasing activity and an increase in amortization rates. The~~the Marcellus Shale, partially offset by a $5.6 million decrease ~~in DD&A was due to a decrease of $17.3 million~~ due to a lower DD&A rate of ~~$0.75~~$0.42 per Mcfe for the ~~third~~second quarter of ~~2017~~2019 compared to ~~$0.85~~$0.45 per Mcfe for the ~~third~~second quarter of ~~2016 primarily~~2018. The lower DD&A rate was due to 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 higher equivalent production primarily in Pennsylvania for the third quarter of 2017 compareddecreased due to ~~the third quarter of 2016.~~lower amortization rates.

General and administrative increased ~~$3.9~~$1.7 million primarily due to ~~$3.2~~$2.1 million of severance costs ~~for employees terminated as a result~~incurred in the second quarter of ~~the sale of properties located in West Virginia, Virginia~~2019 and ~~Ohio and $2.7~~$1.0 million of higher stock-based compensation expense associated with certain of our market-based performance ~~awards, partially offset by $2.0 million lower professional services.~~awards. The remaining changes in other general and administrative expenses were not individually significant.

Earnings (Loss) on Equity Method Investments

~~The increase in loss~~Earnings on equity method investments isincreased $3.7 million as a result of our proportionate share of net ~~loss~~income from our equity method investments ~~in 2017~~during the second quarter of 2019 compared to ~~2016.~~

~~Loss on Sale of Assets~~

~~Loss on sale of assets increased $10.6 million due to~~ the ~~Company's sale of certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio in the third~~second quarter of ~~2017.~~2018 primarily from our investment in Meade, which commenced operations in late 2018.

~~Other Expense (Income)~~

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

Interest Expense, net

Interest expense, net decreased ~~$1.2~~$8.8 million due to ~~$0.8~~$5.4 million ~~higher~~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 $67.0 million of our 9.78% senior notes which matured in December 2019 and $5.5 million lower interest expense related to income tax reserves, partially offset by $1.9 million lower interest income.

Income Tax Expense ~~(Benefit)~~

Income tax expense increased ~~$15.2~~$42.9 million ~~primarily~~ due to higher ~~pretax~~pre-tax income ~~partially offset by~~and a ~~lower~~higher effective tax rate. The effective tax rates for the ~~third~~second quarter of ~~2017~~2019 and ~~2016~~2018 were ~~28.9%~~23.3% and ~~43.9%~~22.3%, respectively. The ~~decrease in the~~ effective tax rate ~~is primarily~~was higher for the second quarter of 2019 due to ~~a decrease in~~ the ~~blended state statutory tax rate as a result~~impact of ~~changes in our state apportionment factors in the states in which we operate, as well as~~ non-recurring discrete items recorded during the ~~third~~second quarter of ~~2017 versus~~2019 as compared to the ~~third~~second quarter of ~~2016.~~2018.

First ~~Nine~~Six Months of ~~2017~~2019 and ~~2016~~2018 Compared

We reported net income in the first ~~nine~~six months of ~~2017~~2019 of ~~$144.8~~$443.8 million, or ~~$0.31~~$1.05 per share, compared to a net ~~loss~~income of ~~$124.4~~$159.7 million, or ~~$0.27~~$0.35 per share, in the first ~~nine~~six months of ~~2016.~~2018. The increase in net income was primarily due to higher operating revenues ~~partially offset by higher~~and lower operating expenses, interest expense and loss on sale of assets, ~~and~~partially offset by higher income tax expense.

Revenue, Price and Volume Variances

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


	Nine Months Ended September 30,					Variance				Six Months Ended June 30,				Variance
Revenue Variances (In thousands)	2017		2016			Amount		Percent		2019		2018		Amount			Percent
Natural gas	$	1,152,089	$	711,010		$	441,079	62	%	$	1,103,656	$	776,768	$	326,888		42	%
Crude oil and condensate	144,528		114,610			29,918		26	%	—		48,722		(48,722		)	(100	)%
Gain (loss) on derivative instruments	46,353		(1,286		)	47,639		3,704	%	71,906		1,909		69,997			3,667	%
Brokered natural gas	12,260		9,417			2,843		30	%	—		97,526		(97,526		)	(100	)%
Other	8,486		5,435			3,051		56	%	236		1,749		(1,513		)	(87	)%
	$	1,363,716	$	839,186		$	524,530	63	%	$	1,175,798	$	926,674	$	249,124		27	%


	Nine Months Ended September 30,				Variance				Increase (Decrease) (In thousands)		Six Months Ended June 30,				Variance					Increase (Decrease) (In thousands)
	2017		2016		Amount		Percent		Increase (Decrease) (In thousands)		2019		2018		Amount			Percent		Increase (Decrease) (In thousands)
Price Variances
Natural gas	$	2.35	$	1.61	$	0.74	46	%	$	361,545	$	2.64	$	2.30	$	0.34		15	%	$	139,208
Crude oil and condensate	$	45.13	$	35.92	$	9.21	26	%	29,451		$	—	$	64.68	$	(64.68	)	(100	)%	—
Total									$	390,996										$	139,208
Volume Variances
Natural gas (Bcf)	491.2		441.8		49.4		11	%	$	79,534	418.6		337.0		81.6			24	%	$	187,680
Crude oil and condensate (Mbbl)	3,203		3,190		13		—	%	467		—		754		(754		)	(100	)%	(48,722		)
Total									$	80,001										$	138,958

Natural Gas Revenues

The increase in natural gas revenues of ~~$441.1~~$326.9 million was due to an increase in production and higher 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~~$48.7 million was primarily due to ~~higher crude oil prices.~~the sale of our Eagle Ford Shale assets in February 2018.

Impact of Derivative Instruments on Operating Revenues


	Nine Months Ended September 30,					Six Months Ended June 30,
(In thousands)	2017		2016			2019		2018
Cash received (paid) on settlement of derivative instruments
Gain on derivative instruments	$	3,587	$	3,204
Gain (loss) on derivative instruments						$	68,377	$	(20,312	)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments	42,766		(4,490		)	3,529		22,221
	$	46,353	$	(1,286	)	$	71,906	$	1,909

Brokered Natural Gas

Brokered natural gas decreased $97.5 million. There was no brokered natural gas activity in the current period.

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

Operating and Other Expenses


	Nine Months Ended September 30,						Variance					Six Months Ended June 30,						Variance
(In thousands)	2017			2016			Amount			Percent		2019			2018			Amount			Percent
Operating and Other Expenses
Direct operations	$	78,185		$	77,139		$	1,046		1	%	$	36,427		$	35,727		$	700		2	%
Transportation and gathering	361,909			322,883			39,026			12	%	279,022			226,314			52,708			23	%
Brokered natural gas	10,262			7,526			2,736			36	%	—			85,032			(85,032		)	(100	)%
Taxes other than income	26,562			23,737			2,825			12	%	9,487			12,582			(3,095		)	(25	)%
Exploration	16,623			13,109			3,514			27	%	10,548			58,117			(47,569		)	(82	)%
Depreciation, depletion and amortization	425,689			448,910			(23,221		)	(5	)%	188,405			167,038			21,367			13	%
Impairment of oil and gas properties	68,555			—			68,555			100	%
General and administrative	70,902			67,192			3,710			6	%	53,979			45,288			8,691			19	%
	$	1,058,687		$	960,496		$	98,191		10	%	$	577,868		$	630,098		$	(52,230	)	(8	)%

Earnings (loss) on equity method investments	$	(3,986	)	$	208		$	(4,194	)	2,016	%	$	7,334		$	(998	)	$	(8,332	)	(835	)%
Loss on sale of assets	(13,498		)	(768		)	(12,730		)	1,658	%
Gain (loss) on sale of assets												(1,500		)	(40,505		)	39,005			(96	)%
Interest expense, net	61,720			67,821			(6,101		)	(9	)%	26,748			43,386			(16,638		)	(38	)%
Loss on debt extinguishment	—			4,709			(4,709		)	(100	)%
Other expense (income)	(4,974		)	1,207			(6,181		)	(512	)%
Income tax expense (benefit)	85,965			(71,243		)	157,208			221	%
Other expense												287			232			55			24	%
Income tax expense												132,957			51,793			81,164			157	%

Total costs and expenses from operations ~~increased~~decreased by ~~$98.2~~$52.2 million, or ~~10%~~8%, in the first ~~nine~~six months of ~~2017~~2019 compared to the same period of ~~2016.~~2018. The primary reasons for this fluctuation are as follows:


•	Direct operations increased $0.7 million primarily driven by higher operating costs of $9.3 million due to higher Marcellus Shale production partially offset by lower operating costs of $8.3 million decrease primarily as a result of the the sale of our Eagle Ford Shale assets in February 2018.

Transportation and gathering increased ~~$1.0~~$52.7 million largely due to an increase in operating costs primarily driven by higher production, partially offset by improved operational efficiencies, cost reductions from service providers and suppliers in 2017 compared to 2016.

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

Brokered natural gas ~~increased $2.7~~decreased $85.0 million. ~~See~~There was no brokered natural gas activity in the ~~preceding table titled “Brokered Natural Gas” for further analysis.~~

current period.

Taxes other than income ~~increased $2.8~~decreased $3.1 million primarily due to $2.4 million lower production taxes resulting from the sale of our Eagle Ford Shale assets in February 2018 and $0.6 million lower drilling impact fees as a result of lower rates.

Exploration decreased $47.6 million due to ~~$3.4~~a decrease in exploratory dry hole costs of $51.1 million, ~~higher production taxes primarily resulting from higher natural gas and crude oil prices and~~partially offset by an increase of $3.5 million geological and geophysical expenses. The exploratory dry hole costs in ~~drilling impact fees~~2018 related to our activities in west Texas.

Depreciation, depletion and amortization increased $21.4 million primarily due to higher DD&A of ~~$1.9~~$25.2 million, partially offset by lower amortization of unproved properties of $4.4 million. The increase in DD&A was primarily

due to an increase ~~in drilling activity in Pennsylvania. These increases were~~of $33.8 million related to higher equivalent production volumes, partially offset by a decrease of ~~$2.4~~$8.6 million ~~in ad valorem taxes as a result of lower property values primarily in south Texas.~~

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

Depreciation, depletion and amortization decreased $23.2 million, primarily due to lower DD&A of $38.0 million, partially offset by higher amortization of unproved properties of $15.9 million in 2017. The decrease in DD&A was due to a decrease of $82.5 million due to a lower DD&A rate of ~~$0.73~~$0.42 per Mcfe for the first ~~nine~~six months of ~~2017~~2019 compared to ~~$0.89~~$0.44 per Mcfe for the first ~~nine~~six months of ~~2016, partially offset by a $44.5 million increase due to higher equivalent production volumes.~~2018. The lower DD&A rate was ~~primarily~~ due to positive reserve revisions ~~and the impairment of oil and gas properties and~~ related ~~pipeline assets in West Virginia and Virginia in 2016. The increase in amortization~~to our year end reserve estimation process. Amortization of unproved properties ~~is primarily~~decreased due to ~~the ongoing evaluation~~lower amortization rates as a result of ~~our unproved properties and an increase~~a decrease in ~~leasing activity.~~

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

exploratory activities.

General and administrative increased ~~$3.7~~$8.7 million primarily due to ~~$3.4 million higher employee-related expenses, $3.2 million of~~ higher stock-based compensation ~~expense~~cost of $10.7 million associated with certain of our market-based performance awards and ~~$3.2~~$2.1 million of severance costs ~~for employees terminated as a result~~incurred in the second quarter of ~~its sale of properties located in West Virginia, Virginia and Ohio.~~2019. These increases were partially offset by ~~$6.8~~$4.5 million of lower professional ~~services. The remaining changes in other general~~services and ~~administrative expenses were not individually significant.~~legal fees.

Earnings (Loss) on Equity Method Investments

~~The increase in loss~~Earnings on equity method investments ~~is the~~increased $8.3 million as a result of our proportionate share of net ~~earnings~~income from our equity method investments in ~~2017~~the first six months of 2019 compared to ~~2016.~~the first six months of 2018 primarily from our investment in Meade, which commenced operations in late 2018.

Loss on Sale of Assets

~~Loss on sale~~During the first six months of ~~assets increased $12.7 million due to~~2019, we recognized a net aggregate loss of $1.5 million. During the ~~Company's sale~~first six months of ~~certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio in the third quarter~~2018, we recognized a net aggregate loss of ~~2017.~~

~~Other Expense (Income)~~

~~Other income increased $6.2~~$40.5 million primarily due to the ~~curtailment gain on postretirement benefits as a result~~sale of ~~the termination of approximately 100 employees~~our Eagle Ford Shale oil and gas properties in ~~West Virginia, Virginia and Ohio.~~south Texas in February 2018.

Interest Expense, net

Interest expense, net ~~decreased $6.1~~decreased $16.6 million ~~primarily~~ due to ~~a $1.4~~$10.8 million ~~increase in~~lower interest ~~income and a $2.1 million decrease~~expense 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$237.0 million of our 6.51% weighted-average senior notes which matured in ~~May 2016~~July 2018 and ~~the repayment of $20.0~~$67.0 million of our ~~7.33% weighted-average~~9.78% senior notes that matured in ~~July 2016.~~

~~Loss on Debt Extinguishment~~

~~A $4.7~~December 2018 and $8.6 million ~~debt extinguishment loss was recognized in the second quarter of 2016~~lower interest expense related to ~~the premium paid for the repurchase of~~income tax reserves, partially offset by a ~~portion of our 6.51% weighted-average senior notes~~$2.0 million increase in ~~May 2016 and the write-off of a portion of the associated deferred financing costs due to early repayment.~~interest income.

Income Tax Expense ~~(Benefit)~~

Income tax expense increased ~~$157.2~~$81.2 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~~six months of ~~2017~~2019 and ~~2016~~2018 were ~~37.2%~~23.1% and ~~36.4%~~24.5%, respectively. The ~~increase in the~~ effective tax rate ~~is primarily~~was higher for the first six months of 2018 due to an increase in the blended state statutory tax rate as a result of changes in our state apportionment factors attributable 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 itemsFebruary 2018. There were no significant apportionment changes recorded during the first ~~nine~~six months of ~~2017 versus the first nine months of 2016.~~2019.

Forward-Looking Information

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A of the Form 10-K for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

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~~production, which can be volatile and unpredictable.

Derivative Instruments and Risk Management Activities

Our risk management strategy is designed to reduce the risk of commodity price volatility for our production in the natural gas ~~and crude oil~~ markets through the use of financial commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our financial 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 financial commodity derivatives. Please read the discussion below as well as Note 6 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivative ~~and risk management activities.~~instruments.

Periodically, we enter into financial commodity derivatives including collar, swap and basis swap agreements, to protect against exposure to commodity price declines related to our natural gas ~~and crude oil~~ production. Our credit agreement restricts our ability to enter into financial 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 financial 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 natural gas ~~and crude oil~~ futures.

As of ~~September~~June 30, ~~2017,~~2019, 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

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



			Swaps		Basis Swaps			Estimated Fair Value Asset (Liability) (In thousands)
			Swaps		Basis Swaps
Type of Contract	Volume (Mmbtu)	Contract Period	Weighted-Average ($/Mmbtu)		Weighted-Average ($/Mmbtu)
Natural gas (IFERC TRANSCO Z6 non-NY)	5,520,000	Jul. 2019 - Dec. 2019			$	0.41		$	2,988
Natural gas (IFERC TRANSCO Z6 non-NY)	18,450,000	Jul. 2019 - Oct. 2019	$	2.61				11,108
Natural gas (IFERC TRANSCO Leidy Line Receipts)	27,600,000	Jul. 2019 - Dec. 2019			$	(0.53	)	(1,469		)
Natural gas (NYMEX)	43,050,000	Jul. 2019 - Oct. 2019	$	2.85				23,604
Natural gas (NYMEX)	55,200,000	Jul. 2019 - Dec. 2019	$	2.82				24,984
								$	61,215

The amounts set forth in the table above represent our total unrealized derivative position at ~~September~~June 30, ~~2017~~2019 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~~six months of ~~2017,~~2019, 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~~31.7 Bcf, or 5%eight percent, of natural gas production at an average price of $2.59 per Mcf. Natural gas swaps covered 112.7 Bcf, or 27%, of natural gas production at an average price of ~~$3.23~~$3.72 per Mcf. Natural gas swaps covered 38.3 Bcf, or 8%, of natural gas production at an average price of $3.23 per Mcf. Crude oil collars with floor prices of $50.00 per Bbl and ceiling prices ranging from $56.25 to $56.50 per Bbl covered 1.4 Mmbbl, or 43%, of crude oil production at an average price of $50.77 per Bbl.

We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of natural ~~gas and crude oil.~~gas. 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:



	June 30, 2019				December 31, 2018
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	1,219,555	$	1,245,889	$	1,226,104	$	1,202,994

ITEM 4. Controls and Procedures

As of ~~September~~June 30, ~~2017,~~2019, 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”)~~Exchange Act). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company's internal control over financial reporting that occurred during the ~~third~~second quarter of ~~2017~~2019 that have materially affected, or are reasonably likely to materially effect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

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

Environmental Matters

On June 17, 2019, we received two proposed Consent Order and Agreements (“CO&A”) from the Pennsylvania Department of Environmental Protection (PaDEP) relating to gas migration allegations in areas surrounding several wells owned and operated by us in Susquehanna County, Pennsylvania. The allegations relating to these wells were initially raised by residents in the area in March and June 2017, respectively, in the form of complaints about their drinking water supply. Since then, we have been engaged with the PaDEP in investigating the incidents and have performed appropriate remediation efforts, including the provision of alternative sources of drinking water to the affected residents. We received Notices of Violation (“NOV”) from the PaDEP in June and November, 2017, respectively, for failure to prevent the migration of gas into fresh groundwater sources in the area surrounding these wells. With regard to the June 2017 NOV, we believe these water quality complaints have been resolved, and we are working with the PaDEP to reach agreement on the disposition of this matter. The proposed CO&A is the culmination of this effort and, if finalized, would result in the payment of a civil monetary penalty in an amount likely to exceed $100,000, up to approximately $215,000. We will continue to work with the PaDEP to finalize the CO&A, and to bring this matter to a close. With regard to the November 2017 NOV, The proposed CO&A, if finalized as drafted, would require Cabot to submit a detailed written remediation plan, continue water sampling and other investigative measures and restore or replace affected water supplies and would result in the payment of a civil monetary penalty in an amount likely to exceed $100,000, up to approximately $355,000. We will continue to work with the PaDEP to finalize the CO&A, and to complete the ongoing investigation and remediation.

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

ITEM 1A. Risk Factors

For additional information about the risk factors that affect us, see Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.

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

Issuer Purchases of Equity Securities

Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. The ~~maximum~~shares included in the table below were purchased on the open market and were held as treasury stock as of June 30, 2019.



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
April 2019⁽¹⁾	80,933	$	25.47	80,933	11,499,362
May 2019	2,250,000	$	25.44	2,250,000	9,249,362
June 2019	2,750,000	$	23.95	2,750,000	6,499,362
Total	5,080,933			5,080,933

⁽¹⁾ Shares were repurchased under a Rule 10b5-1 Plan that was in effect from April 1, 2019 to April 24, 2019.

In July 2019, our Board of Directors authorized an increase of 25.0 million shares to our Company’s share repurchase program. After this authorization, the total number of ~~remaining~~ shares ~~that may be purchased under the plan as of September 30, 2017 was 7.1~~available for repurchase is 31.5 million shares.

ITEM 6. Exhibits



Exhibit Number		Description

10.1		Second Amended and Restated Credit Agreement dated as of April 22, 2019, among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Joint Lead Arranger, Merrill Lynch, Pierce, Fenner & Smith, Incorporated, as Syndication Agent and Joint Lead Arranger, Bank of Montreal, The Bank of Nova Scotia, Houston Branch, Citibank N.A., Compass Bank, Toronto Dominion (New York) LLC, U.S. Bank National Association and Wells Fargo, N.A. as Co-Documentation Agent, and the Lenders party thereto. (Form 10-Q for the quarter ended March 31, 2019)

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.~~Document, The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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~~July 26, 2019	By:	/s/ DAN O. DINGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

~~October 30, 2017~~July 26, 2019	By:	/s/ SCOTT C. SCHROEDER
		Scott C. Schroeder
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

~~October 30, 2017~~July 26, 2019	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Vice President and ~~Controller~~Chief Accounting Officer
		(Principal Accounting Officer)

3532



	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



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



(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