Range Resources (RRC) 10-K 27 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 25, 2020	Jun. 30, 2019
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	RANGE RESOURCES CORPORATION
Entity Central Index Key	0000315852
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		254,715,325
Entity Public Float			$ 1,733,839,000
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity File Number	001-12209
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	34-1312571
Entity Address, Address Line One	100 Throckmorton Street
Entity Address, Address Line Two	Suite 1200
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	870-2601
Document Annual Report	true
Document Transition Report	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Interactive Data Current	Yes
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement to be furnished to stockholders in connection with its 2020 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates, are incorporated by reference in Part II, Item 5 and Part III, Items 10-14 of this report.
Title of 12(b) Security	Common Stock, $.01 par value
Trading Symbol	RRC
Security Exchange Name	NYSE

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents		$ 546	$ 545
Accounts receivable, less allowance for doubtful accounts of $8,784 and $6,118		272,900	490,723
Derivative assets		136,848	87,953
Other current assets		17,508	22,964
Total current assets		427,802	602,185
Derivative assets		706	4,842
Natural gas and oil properties, successful efforts method	[1]	10,213,737	13,085,206
Accumulated depletion and depreciation	[1]	(4,172,702)	(4,062,021)
Natural gas and oil properties, successful efforts method, net	[1]	6,041,035	9,023,185
Other property and equipment		102,083	111,908
Accumulated depreciation and amortization		(96,708)	(102,132)
Other Property and equipment, net		5,375	9,776
Operating lease right-of-use assets		62,053	0
Other assets		75,432	68,166
Total assets		6,612,403	9,708,154
Current liabilities:
Accounts payable		155,341	227,344
Asset retirement obligations		2,393	5,485
Accrued liabilities		356,392	475,848
Accrued interest		39,299	41,990
Derivative liabilities		13,119	4,144
Total current liabilities		566,544	754,811
Bank debt		464,319	932,018
Senior notes		2,659,844	2,856,166
Senior subordinated notes		48,774	48,677
Deferred tax liabilities		160,196	666,668
Derivative liabilities		949	3,462
Deferred compensation liabilities		64,070	67,542
Operating lease liabilities		41,068	0
Asset retirement obligations and other liabilities		259,151	319,379
Total liabilities		4,264,915	5,648,723
Commitments and contingencies
Stockholders' Equity
Preferred stock, $1 par 10,000,000 shares authorized, none issued and outstanding		0	0
Common stock, $0.01 par 475,000,000 shares authorized, 251,438,936 issued at December 31, 2019 and 249,519,687 issued at December 31, 2018		2,514	2,495
Common stock held in treasury, at cost, 1,808,133 shares at December 31, 2019 and 9,665 shares at December 31, 2018		(7,236)	(391)
Additional paid-in capital		5,659,832	5,628,447
Accumulated other comprehensive loss		(788)	(658)
Retained deficit		(3,306,834)	(1,570,462)
Total stockholders' equity		2,347,488	4,059,431
Total liabilities and stockholders' equity		$ 6,612,403	$ 9,708,154
[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement Of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 8,784	$ 6,118
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	475,000,000	475,000,000
Common stock, shares issued	251,438,936	249,519,687
Common stock held in treasury, shares	1,808,133	9,665

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues and other income:
Revenues and other income									$ 2,600,934	$ 3,333,837
Derivative fair value income (loss)	$ 18,491	$ 74,676	$ 195,245	$ (61,731)	$ 100,698	$ (34,591)	$ (103,290)	$ (14,009)	226,681	(51,192)	$ 213,350
Total revenues and other income	605,604	622,445	851,429	748,137	1,072,637	811,225	656,184	742,599	2,827,615	3,282,645	2,611,030
Costs and expenses:
Production and ad valorem taxes	8,963	7,805	9,889	11,310	16,656	9,427	10,140	9,926	37,967	46,149	42,882
Brokered natural gas and marketing	46,532	79,938	101,117	132,305	221,626	116,080	102,747	55,594	359,892	496,047	220,311
Exploration	9,350	11,013	8,109	8,211	10,600	8,299	7,499	7,719	36,683	34,117	53,662
Abandonment and impairment of unproved properties	1,193,711	16,202	12,770	12,659	441,750	6,549	54,922	11,773	1,235,342	514,994	269,725
General and administrative	42,793	41,047	50,631	46,638	50,090	43,722	47,583	68,417	181,109	209,812	233,406
Termination costs	6,481	819	2,206	0	0	(336)	0	(37)	9,506	(373)	3,770
Deferred compensation plan	960	(8,871)	(11,142)	3,581	(18,072)	223	6,615	(7,397)	(15,472)	(18,631)	(50,915)
Interest	44,024	46,997	51,727	51,537	49,161	54,801	53,862	52,385	194,285	210,209	195,679
Gain on early extinguishment of debt	(2,430)	(2,985)	0	0					(5,415)	0	0
Depletion, depreciation and amortization	130,869	137,751	141,505	138,718	147,909	164,266	161,026	162,266	548,843	635,467	624,992
Impairment of proved properties and other assets	1,095,634	0	0	0	0	0	15,302	7,312	1,095,634	22,614	63,679
Impairment of goodwill					1,641,197	0	0	0	0	1,641,197	0
Loss (gain) on the sale of assets	(407)	36,341	(5,867)	189	10,815	30	(156)	(23)	30,256	10,666	(23,716)
Total costs and expenses	2,909,783	697,245	696,145	741,030	2,905,843	738,549	764,538	650,685	5,044,203	5,059,615	2,528,910
(Loss) income before income taxes	(2,304,179)	(74,800)	155,284	7,107	(1,833,206)	72,676	(108,354)	91,914	(2,216,588)	(1,776,970)	82,120
Income tax (benefit) expense:
Current	2,068	4,079	0	0	0	0	0	0	6,147	0	17
Deferred	(500,927)	(51,298)	40,099	5,688	(68,784)	24,137	(28,518)	42,676	(506,438)	(30,489)	(251,043)
Total (benefit) expense for income taxes	(498,859)	(47,219)	40,099	5,688	(68,784)	24,137	(28,518)	42,676	(500,291)	(30,489)	(251,026)
Net (loss) income	$ (1,805,320)	$ (27,581)	$ 115,185	$ 1,419	$ (1,764,422)	$ 48,539	$ (79,836)	$ 49,238	$ (1,716,297)	$ (1,746,481)	$ 333,146
Net (loss) income per common share:
Basic	$ (7.27)	$ (0.11)	$ 0.46	$ 0.01	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ (6.92)	$ (7.10)	$ 1.34
Diluted	$ (7.27)	$ (0.11)	$ 0.46	$ 0.01	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ (6.92)	$ (7.10)	$ 1.34
Weighted average common shares outstanding:
Basic									247,970	246,171	245,091
Diluted									247,970	246,171	245,458
Natural Gas, NGLs and Oil Sales
Revenues and other income:
Revenues and other income	$ 545,438	$ 474,754	$ 563,579	$ 671,654	$ 756,627	$ 736,431	$ 661,390	$ 696,629	$ 2,255,425	$ 2,851,077	$ 2,176,287
Brokered Natural Gas, Marketing and Other
Revenues and other income:
Revenues and other income	41,675	73,015	92,605	138,214	215,312	109,385	98,084	59,979	345,509	482,760	221,393
Direct Operating
Costs and expenses:
Costs and expenses	33,792	35,276	33,981	33,227	35,395	30,926	35,088	38,122	136,276	139,531	134,252
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 299,511	$ 295,912	$ 301,219	$ 302,655	$ 298,716	$ 304,562	$ 269,910	$ 244,628	$ 1,199,297	$ 1,117,816	$ 761,183

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement Of Income And Comprehensive Income [Abstract]
Net (loss) income	$ (1,716,297)	$ (1,746,481)	$ 333,146
Postretirement benefits:
Actuarial (loss) gain	(532)	526	0
Prior service cost	0	0	(1,769)
Amortization of prior service costs	369	369	0
Income tax benefit (expense)	33	(221)	437
Total comprehensive (loss) income	$ (1,716,427)	$ (1,745,807)	$ 331,814

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities:
Net (loss) income	$ (1,716,297,000)	$ (1,746,481,000)	$ 333,146,000
Adjustments to reconcile net (loss) income to net cash provided from operating activities:
Deferred income tax benefit	(506,438,000)	(30,489,000)	(251,043,000)
Depletion, depreciation and amortization and impairment of proved properties	1,644,477,000	658,081,000	688,671,000
Impairment of goodwill	0	1,641,197,000	0
Exploration dry hole and impairment costs	(11,000)	4,000	9,172,000
Abandonment and impairment of unproved properties	1,235,342,000	514,994,000	269,725,000
Derivative fair value (income) loss	(226,681,000)	51,192,000	(213,350,000)
Cash settlements on derivative financial instruments	188,384,000	(131,522,000)	13,117,000
Allowance for bad debt	4,341,000	(1,000,000)	1,550,000
Amortization of deferred financing costs and other	6,455,000	2,515,000	5,445,000
Deferred and stock-based compensation	24,891,000	29,757,000	30,706,000
Loss (gain) on the sale of assets	30,256,000	10,666,000	(23,716,000)
Gain on early extinguishment of debt	(5,415,000)	0	0
Changes in working capital:
Accounts receivable	214,196,000	(142,381,000)	(102,866,000)
Inventory and other	4,520,000	138,000	(2,979,000)
Accounts payable	(60,374,000)	(4,274,000)	45,912,000
Accrued liabilities and other	(155,803,000)	138,293,000	12,764,000
Net cash provided from operating activities	681,843,000	990,690,000	816,254,000
Investing activities:
Additions to natural gas and oil properties	(687,277,000)	(960,916,000)	(1,148,613,000)
Additions to field service assets	(1,162,000)	(1,477,000)	(5,710,000)
Acreage purchases	(59,986,000)	(60,603,000)	(58,213,000)
Proceeds from disposal of assets	784,937,000	324,549,000	72,468,000
Purchases of marketable securities held by the deferred compensation plan	(19,039,000)	(46,177,000)	(88,167,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	22,005,000	49,190,000	89,178,000
Net cash provided from (used in) investing activities	39,478,000	(695,434,000)	(1,139,057,000)
Financing activities:
Borrowings on credit facilities	2,311,000,000	2,070,000,000	2,041,000,000
Repayments on credit facilities	(2,777,000,000)	(2,338,000,000)	(1,712,000,000)
Repayment of senior or senior subordinated notes	(195,432,000)	0	(500,000)
Dividends paid	(20,070,000)	(19,940,000)	(19,839,000)
Treasury stock purchases	(6,908,000)	0	0
Debt issuance costs	(4,446,000)	(8,220,000)	(403,000)
Taxes paid for shares withheld	(3,384,000)	(3,183,000)	(6,983,000)
Change in cash overdrafts	(25,747,000)	(5,563,000)	17,180,000
Proceeds from the sales of common stock held by the deferred compensation plan	667,000	9,747,000	4,482,000
Net cash (used in) provided from financing activities	(721,320,000)	(295,159,000)	322,937,000
Increase in cash and cash equivalents	1,000	97,000	134,000
Cash and cash equivalents at beginning of year	545,000	448,000	314,000
Cash and cash equivalents at end of year	$ 546,000	$ 545,000	$ 448,000

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Common stock held in treasury	Additional Paid-in Capital	Retained (deficit)/earnings	Accumulated other comprehensive loss
Beginning balance at Dec. 31, 2016	$ 5,408,368	$ 2,471	$ (1,209)	$ 5,524,423	$ (117,317)
Beginning balance Shares at Dec. 31, 2016		247,175,000
Issuance of common stock	2,987	$ 10		2,977
Issuance of common stock, shares		969,000
Stock-based compensation expense	50,942			50,942
Cash dividends paid ($0.08 per share)	(19,839)				(19,839)
Treasury stock issuance			610	(610)
Other comprehensive income (loss)	(1,332)					$ (1,332)
Net income (loss)	333,146				333,146
Ending balance at Dec. 31, 2017	5,774,272	$ 2,481	(599)	5,577,732	195,990	(1,332)
Ending balance Shares at Dec. 31, 2017		248,144,000
Issuance of common stock	13,696	$ 14		13,682
Issuance of common stock, shares		1,374,000
Issuance of common stock upon vesting of PSUs				31	(31)
Issuance of common stock upon vesting of PSUs, shares		2,000
Stock-based compensation expense	37,210			37,210
Cash dividends paid ($0.08 per share)	(19,940)				(19,940)
Treasury stock issuance			208	(208)
Other comprehensive income (loss)	674					674
Net income (loss)	(1,746,481)				(1,746,481)
Ending balance at Dec. 31, 2018	$ 4,059,431	$ 2,495	(391)	5,628,447	(1,570,462)	(658)
Ending balance Shares at Dec. 31, 2018	249,519,687	249,520,000
Issuance of common stock	$ 342	$ 19		323
Issuance of common stock, shares		1,919,000
Issuance of common stock upon vesting of PSUs				5	(5)
Stock-based compensation expense	31,120			31,120
Cash dividends paid ($0.08 per share)	(20,070)				(20,070)
Treasury stock issuance			63	(63)
Treasury stock repurchased	(6,908)		(6,908)
Other comprehensive income (loss)	(130)					(130)
Net income (loss)	(1,716,297)				(1,716,297)
Ending balance at Dec. 31, 2019	$ 2,347,488	$ 2,514	$ (7,236)	$ 5,659,832	$ (3,306,834)	$ (788)
Ending balance Shares at Dec. 31, 2019	251,438,936	251,439,000

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement Of Stockholders Equity [Abstract]
Cash dividends paid per share	$ 0.08	$ 0.08	$ 0.08

Summary of Organization and Nat

Summary of Organization and Nature of Business	12 Months Ended
	Dec. 31, 2019
Industry Specific Policies [Abstract]
Summary of Organization and Nature of Business	(1) Summary of Organization and Nature of Business Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”), crude oil and condensate company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and North Louisiana regions of the United States. Our objective is to build stockholder value through returns focused development of natural gas and oil properties, measured on a per share debt-adjusted basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC”.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	(2) Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The accompanying consolidated financial statements, including the notes, have been prepared in accordance with U.S. GAAP and include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation. Use of Estimates The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates and changes in these estimates are recorded when known. Estimated quantities of natural gas, NGLs, crude oil and condensate reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, NGLs, crude oil and condensate. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs, crude oil and condensate reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of natural gas, NGLs and crude oil and condensate that are ultimately recovered. See Note 18 for further detail. Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, valuation of derivative instruments and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates. Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs, crude oil and condensate in the United States. We consider our gathering, processing and marketing functions as integral to our natural gas, crude oil and condensate producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on a geographical or area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to optimize returns without regard to individual areas. Revenue Recognition, Accounts Receivable and Gas Imbalances Natural gas, NGLs and oil sales revenues are recognized when control of the product is transferred to the customer and collectability is reasonably assured. See a more detailed summary of our product types below. Natural Gas and NGLs Sales Under our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction. For those contracts that we have concluded that we are the principal, the ultimate third party is our customer and we recognize revenue on a gross basis, with gathering, compression, processing and transportation fees presented as an expense. Alternatively, for those contracts that we have concluded that we are the agent, the midstream processing entity is our customer and we recognize revenue based on the net amount of the proceeds received from the midstream processing entity. In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in kind at the tailgate of the midstream entity’s processing plant and subsequently market the product on our own. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser are presented as transportation, gathering, processing and compression expense. Oil Sales Our oil sales contracts are generally structured in one of the following ways: • We sell oil production at the wellhead and collect an agreed-upon index price, net of transportation incurred by the purchaser (that is, a netback arrangement). In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received. • We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation, gathering, processing and compression expense. Brokered Natural Gas, Marketing and Other We realize brokered margins as a result of buying natural gas or NGLs utilizing separate purchase transactions, generally with separate counterparties, and subsequently selling that natural gas or NGLs under our existing contracts to fill our contract commitments or use existing infrastructure contracts to economically fulfill available capacity. In these arrangements, we take control of the natural gas purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Our net brokered margin was a loss of $14.2 million in 2019 compared to a loss of $16.3 million in 2018 and a loss of $5.7 million in 2017. The recognition of gains or losses on derivative instruments is not considered revenue from contracts with customers. We may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales or in limited cases may use them for contracts we intend to physically settle but that do not meet all of the criteria to be treated as normal sales. Accounts Receivable Our accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties we operate. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. However, this concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. For receivables from joint interest owners, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $8.8 million at December 31, 2019 compared to $6.1 million at December 31, 2018. We recorded bad debt expense of $4.3 million in the year ended December 31, 2019 compared to income of $1.0 million in the year ended December 31, 2018 and expense of $1.6 million in the year ended December 31, 2017. Cash and Cash Equivalents Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows. Marketable Securities Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets. Natural Gas and Oil Properties Property Acquisition Costs . We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Depreciation, Depletion and Amortization . Depreciation, depletion and amortization of proved properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. In the year ended December 31, 2015, the fair value of our natural gas and oil properties in Northwest Pennsylvania was determined to be zero. As a result, any future adjustments to the asset retirement liability for these properties represents an impairment expense and we have elected to record such expense in depreciation, depletion and amortization. In the year ended December 31, 2019, additional expense of $213,000 was recorded related to these costs compared to $9.8 million of additional expense in the year ended December 31, 2018 and $158,000 of additional expense in the year ended December 31, 2017. As of December 31, 2019, we executed an agreement to sell these Northwest Pennsylvania assets, pending certain state governmental approval for change in operatorship. Impairments . Our proved natural gas and oil properties are reviewed for impairment annually and periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market-related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and possible reserves, as appropriate, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value as determined by discounted future net cash flows using a discount rate similar to that used by market participants, or comparable market value if available and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 11. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs and allocated probable and possible reserves value resulting from acquisitions. The costs are capitalized and evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management which could impact the number of drilling locations we intend to drill. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Information such as reservoir performance or future plans to develop acreage is also considered. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. In certain circumstances, our future plans to develop acreage may accelerate our impairment. A significant portion of our unproved property is related to probable and possible reserves whose recoverability is evaluated based on management’s expectations and ability to drill these locations. Unproved properties had a net book value of $868.2 million as of December 31, 2019 compared to $2.1 billion in 2018. Unproved properties as of December 31, 2019 are all within Pennsylvania. We have recorded abandonment and impairment expense related to unproved properties of $1.2 billion in the year ended December 31, 2019 compared to $515.0 million in 2018 and $269.7 million in 2017. Abandonment and impairment expense in 2019 includes $1.2 billion compared to $436.0 million in 2018 related to probable and possible reserves in North Louisiana where we no longer have the intent to drill. Dispositions . Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets. For additional information regarding our dispositions, see Note 4 . Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $5.0 million in the year ended December 31, 2019 compared to $6.0 million in the year ended December 31, 2018 and $7.7 million in the year ended December 31, 2017. Leases We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not have any finance leases. We capitalize our operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term of one year or less are not capitalized but are disclosed. Short-term lease costs exclude expenses related to leases with a lease term of one month or less. Our operating leases are reflected as operating lease ROU assets, accrued liabilities-current and operating lease liabilities on our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Our leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease liabilities and ROU assets only when we are the signatory to a contract as an operator of joint properties. Such lease liabilities and ROU assets are determined and disclosed based on gross contractual obligations. Our lease costs are also presented on a gross basis. Nature of Leases We lease certain office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below. Office Agreements and Subleases. We rent office space from third parties for our corporate and field locations. Our office agreements are typically structured with non-cancelable terms of one to fifteen years. We have concluded our office agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term. We also sublease some of our office space to third parties. All of our subleases have terms that end in 2020 or 2022. The sublease agreements are non-cancelable through the end of the term and both parties have substantive rights to terminate the lease when the term is complete. Our sublease agreements are not capitalized and are recorded as sublease income (as a component of lease costs) in the period the rent is received. As of December 31, 2019, these subleases total $3.1 million through the beginning of 2022. Field Equipment. We rent compressors and coolers from third parties in order to facilitate the downstream movement of our production to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one to two years and continue thereafter on a month-to-month basis subject to termination by either party with thirty days notice. We have concluded that our compressor and cooler rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. Vehicles. We rent our vehicle fleet for our drilling and operations personnel from a third party. Our vehicle agreements are non-cancelable for a minimum term of one year and a maximum term of four to eight years depending on the type of vehicle. However, we have assumed a term of three years based on the period covered by options to terminate that we are reasonably certain to exercise. We have concluded our vehicle commitments are operating leases. Other Equipment. We utilize a dedicated natural gas fueled, electric driven frac fleet to support our drilling activities. This arrangement is structured with a non-cancellable primary term of eighteen months, with two optional extension periods of six months each. We have concluded that this arrangement is an operating lease with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days’ notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig-by-rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the successful efforts method of accounting, these costs are capitalized as part of natural gas and oil properties on our consolidated balance sheets when paid. Transportation, Gathering and Processing Arrangements. We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the third party’s underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset. However, in limited circumstances, we do utilize substantially all of the capacity of a portion of the midstream system under our transportation, gathering and/or processing service contract. These arrangements require judgment to determine whether our capacity of the underlying midstream asset represents a lease. Under all of these arrangements, we have concluded that (i) the midstream entity maintains control of and has the ability to optimize and/or expand the underlying system throughout the duration of the contract term and (ii) the portion of the system or facility we utilize is highly integrated and interconnected to a broader system servicing a diverse set of customers. Consequently, the transportation, gathering and/or processing contract does not represent a lease of the underlying portion of the midstream system or facilities. We currently have not identified any of these commitments as leases. Discount Rate Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term in an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable. Practical Expedients and Accounting Policy Elections Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statements of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statements of operations in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” Other Assets Other assets at December 31, 2019 include $62.0 million of marketable securities held in our deferred compensation plans and $9.6 million of other investments including surface acreage. Other assets at December 31, 2018 include $57.3 million of marketable securities held in our deferred compensation plans and $9.1 million of other investments, including surface acreage. Stock-based Compensation Arrangements We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 12. Derivative Financial Instruments All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. All realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of operations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We also have collars which establish a minimum floor price and a predetermined ceiling price. We also have entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. Beginning in third quarter 2017, we entered into combined natural gas derivative instruments containing a fixed price swap and a sold option to extend the term or expand the volume (which we refer to as a swaption). The swap price is a fixed price determined at the time of the swaption contract. If the option is exercised, the contract will become a swap treated consistently with our fixed-price swaps. For additional information regarding our derivatives, see Note 10. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. During 2019, we did not materially modify any existing derivative contracts. Concentrations of Credit Risk As of December 31, 2019, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. The nature of our customer

Accounting Standards

Accounting Standards	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements And Changes In Accounting Principles [Abstract]
Accounting Standards	(3) Accounting Standards Recently Adopted Lease Accounting Standard In February 2016, an accounting standards update was issued that requires an entity to recognize a ROU asset and lease liability for all leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also required certain quantitative and qualitative disclosures about leasing arrangements. The new standard was effective for us in first quarter 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application effective on January 1, 2019. Consequently, upon transition, we recognized a ROU asset (or operating lease right-of-use asset) and a lease liability with no retained earnings impact. We are applying the following practical expedients as provided in the standards update which provide elections to: • not apply the recognition requirements 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); • not reassess whether a contract contains a lease, lease classification and initial direct costs; and • not reassess certain land easements in existence prior to January 1, 2019. Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standards update. Our adoption did not have a material impact on our consolidated balance sheet as of January 1, 2019, with the primary impact relating to the recognition of ROU assets and operating lease liabilities for operating leases which represents approximately a 1% change to total assets and total liabilities. The impact of adoption of this new standards update was as follows (in thousands): January 1, 2019 Adoption Reclassification (1) Total Adjustment Balance Sheet: Operating lease right-of-use assets $ 59,300 $ (7,925 ) $ 51,375 Accrued liabilities – current $ (14,811 ) $ — $ (14,811 ) Operating lease liabilities – long-term $ (44,489 ) $ — $ (44,489 ) Asset retirement obligations and other liabilities $ — $ 7,925 $ 7,925 (1) Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity. Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of the standards update. Pension Accounting Standard In March 2017, an accounting standards update was issued which provides additional guidance on the presentation of net benefit cost in the statement of operations. Employers are to present the service cost component of net periodic benefit cost in the same consolidated results of operations line item as other employee compensation costs arising from services rendered during the period. This new standards update was effective for annual reporting periods in first quarter 2018 and must be applied retrospectively. We adopted this standards update in first quarter 2018. The adoption did not impact our consolidated results of operations, financial position, cash flows or disclosures. We had no service cost recorded prior to 2018 due to the implementation of our post retirement benefit plan at the end of 2017. In 2019 and 2018, our service cost is recorded in general and administrative expense. Modification of Share – Based Awards In May 2017, an accounting standards update was issued which clarifies what constitutes a modification of a share-based award. This standards update was intended to provide clarity and reduce both diversity in practice and cost and complexity to a change to the terms or conditions of a share-based payment award. We adopted this standards update in first quarter 2018. The adoption of this standard did not have a material impact on our consolidated results of operations, financial position, cash flows or disclosures. Revenue Recognition Standard In May 2014, an accounting standards update was issued that superseded the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. This standard was effective for us in first quarter 2018 and we adopted the new standards update using the modified retrospective method to all open contracts as of January 1, 2018. Our implementation of this standard did not result in a cumulative-effect adjustment on date of adoption; however, our financial statement presentation related to revenue received from certain gas processing contracts changed. Based on previous accounting guidance, certain of our gas processing contracts were reported in revenue at a net price (net of processing costs) we receive. Upon adoption of this accounting standards update, these contracts are now reported as a gross price received at a delivery point and separate transportation, marketing and processing expense. Not Yet Adopted Financial Instruments – Credit Losses In June 2016, an accounting standards update was issued that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standards update requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standards update is effective for us in first quarter 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. We have evaluated the provisions of this accounting standards update and are assessing the impact, if any, it may have on our consolidated results of operations, financial position and financial disclosures. From the evaluation of our current credit portfolio, which includes receivables for commodity sales, joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoption of this standard will have a material impact on our financial statements. Fair Value Measurement In August 2018, an accounting standards update was issued which provides additional disclosure requirements for fair value measurements. This new standards update eliminates the requirement to disclose transfers between Level 1 and Level 2 of the fair value hierarchy and provides for additional disclosures for Level 3 fair value measurements. This new standards update is effective for us in first quarter 2020 and will be adopted on a prospective or retrospective basis depending on the changes that apply. We do not believe adoption of this standard will have a material impact on our financial disclosures.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Dispositions	(4) Dispositions We recognized a pretax net loss on the sale of assets of $30.3 million in the year ended December 31, 2019 compared to a pretax loss of $10.7 million in 2018 and a pretax gain of $23.7 million in 2017. The following describes the significant divestitures that are included in our consolidated results of operations for each of three years ended December 31, 2019, 2018 and 2017. 2019 Dispositions Pennsylvania. In third quarter 2019, we sold, in three separate transactions, a proportionately reduced 2.5% overriding royalty, primarily in our Washington County, Pennsylvania leases for gross proceeds of $750.0 million. We recorded a pretax loss of $36.5 million related to this sale which represents closing adjustments and transaction fees. In second quarter 2019, we sold natural gas and oil property, primarily representing over 20,000 unproved acres, for proceeds of $34.0 million and recognized a pretax gain of $5.9 million. Other. In 2019, we sold miscellaneous proved property, inventory, equipment and other assets for proceeds of $938,000 resulting in a pretax gain of $337,000. 2018 Dispositions Pennsylvania. In fourth quarter 2018, we sold a proportionately reduced 1% overriding royalty in our Washington County, Pennsylvania leases for gross proceeds of $300.0 million. We recorded a pretax loss of $10.2 million related to this sale which represents closing adjustments and transaction fees. Northern Oklahoma. In third quarter 2018, we sold properties in Northern Oklahoma for proceeds of $23.3 million and we recorded a pretax net loss of $39,000 related to this sale, after closing adjustments. Other. In 2018, we sold miscellaneous proved property, inventory and other assets for proceeds of $1.2 million, resulting in a pretax loss of $448,000. 2017 Dispositions Texas Panhandle. In fourth quarter 2017, we sold various properties in the Texas Panhandle for proceeds of $40.4 million and we recorded a pretax loss of $989,000 related to this sale, after closing adjustments. Western Oklahoma. In 2017, we sold certain properties in Oklahoma for proceeds of $30.8 million and we recorded a pretax gain of $23.8 million related to this sale, after closing adjustments and transaction fees. Other. In 2017, we sold miscellaneous unproved property, inventory and surface property for proceeds of $1.3 million resulting in a pretax gain of $870,000.

Revenues from Contracts with Cu

Revenues from Contracts with Customers	12 Months Ended
	Dec. 31, 2019
Revenue From Contract With Customer [Abstract]
Revenues from Contracts with Customers	(5) Revenues from Contracts with Customers Disaggregation of Revenue We have identified three material revenue streams in our business: natural gas sales, NGLs sales, crude oil and condensate sales. Brokered revenue attributable to each product sales type is included here because the volume of product that we purchase is subsequently sold to separate counterparties in accordance with existing sales contracts under which we also sell our production. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands): Year Ended December 31, 2019 2018 Natural gas sales $ 1,388,838 $ 1,663,832 NGLs sales 681,134 931,360 Oil sales 185,453 255,885 Total natural gas, NGLs and oil sales 2,255,425 2,851,077 Sales of purchased natural gas 332,006 459,634 Sales of purchased NGLs 1,661 9,017 Other marketing revenue 11,842 14,109 Total $ 2,600,934 $ 3,333,837 Principal versus Agent We engage in various types of transactions in which midstream entities process our wet gas and, in some scenarios, subsequently market the resulting NGLs and residue gas to third-party customers on our behalf. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. Transaction Price Allocated to Remaining Performance Obligations A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient allowed in the new revenue accounting standard that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have also utilized the practical expedient that states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration. Contract Balances Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $237.0 million at December 31, 2019 and $438.3 million at December 31, 2018. Prior−Period Performance Obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGLs sales may be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. We have internal controls in place for our estimation process and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	(6) Income Taxes Our income tax benefit was $500.3 million for the year ended December 31, 2019 compared to $30.5 million in 2018 and $251.0 million in 2017. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % Federal rate change — — (406.7 ) State 3.8 (0.3 ) (0.7 ) State rate and law change 1.8 0.9 (1.3 ) Non-deductible executive compensation — — 0.7 Valuation allowances (3.8 ) (0.4 ) 36.8 Equity compensation (0.2 ) (0.1 ) 30.2 Goodwill impairment — (19.4 ) — Other — — 0.3 Consolidated effective tax rate 22.6 % 1.7 % (305.7 %) Income tax (benefit) expense attributable to (loss) income before income taxes consists of the following (in thousands): 2019 2018 2017 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ (434,585 ) $ (434,585 ) $ — $ (25,322 ) $ (25,322 ) $ — $ (302,507 ) $ (302,507 ) U.S. state and local 6,147 (71,853 ) (65,706 ) — (5,167 ) (5,167 ) 17 51,464 51,481 Total $ 6,147 $ (506,438 ) $ (500,291 ) $ — $ (30,489 ) $ (30,489 ) $ 17 $ (251,043 ) $ (251,026 ) Significant components of deferred tax assets and liabilities are as follows: December 31, 2019 2018 (in thousands) Deferred tax assets: Net operating loss carryforward $ 581,324 $ 542,847 Deferred compensation 16,815 19,844 Equity compensation 7,188 8,152 AMT credits and other credits — 3,296 Asset retirement obligation 60,064 78,126 Interest expense carryover 18,035 19,444 Lease deferred tax assets 16,450 — Other 11,072 11,048 Valuation allowances: Federal (32,530 ) (18,975 ) State, net of federal benefit (158,296 ) (101,372 ) Total deferred tax assets 520,122 562,410 Deferred tax liabilities: Depreciation and depletion (639,581 ) (1,207,784 ) Cumulative mark-to-market gain (25,957 ) (21,294 ) Lease deferred tax liabilities (14,780 ) — Total deferred tax liabilities (680,318 ) (1,229,078 ) Net deferred tax liability $ (160,196 ) $ (666,668 ) At December 31, 2019, deferred tax liabilities exceeded deferred tax assets by $160.2 million. As of December 31, 2019, we have a state valuation allowance of $158.3 million related to state tax attributes in Louisiana, Oklahoma, Pennsylvania, Texas and West Virginia. As of December 31, 2019, we have federal valuation allowances of $32.5 million primarily related to our federal net operating loss carryforward, federal basis differences and charitable contribution carryforward. See the table below for activity related to these valuation allowances. The changes in our deferred tax asset valuation allowances are as follows (in thousands): 2019 2018 2017 Balance at the beginning of the year $ (120,347 ) $ (125,134 ) $ (107,174 ) Charged to provision for income taxes: State net operating loss carryforwards (25,710 ) (23,926 ) (11,612 ) Federal net operating loss carryforwards 13,780 11,716 15,385 Non-recoverable deferred tax assets (28,208 ) — — Other state valuation allowances (31,214 ) 16,380 (23,790 ) Other federal valuation allowances 346 494 (247 ) Other 527 123 2,304 Balance at the end of the year $ (190,826 ) $ (120,347 ) $ (125,134 ) At December 31, 2019, we had federal net operating loss (“NOL”) carryforwards of $2.1 billion. This includes $1.4 billion that expires between 2020 and 2037 and also includes $712.8 million of NOL carryforwards generated after 2017 that do not expire. We have state NOL carryforwards in Pennsylvania of $856.3 million that expire between 2027 and 2038 and in Louisiana, we have state NOL carryforwards of $561.1 million that expire between 2034 and 2039. We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana and Pennsylvania and file consolidated or unitary state income tax returns in Oklahoma, Texas and West Virginia. We are subject to U.S. federal income tax examinations for the years 2016 and after and we are subject to various state tax examinations for years 2015 and after. We have not extended the statute of limitation period in any income tax jurisdiction. Our policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of December 31, 2019. Throughout 2019 and 2018, our unrecognized tax benefits were not material.

Net Income (Loss) Per Common Sh

Net Income (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Net Income (Loss) Per Common Share	(7) Net Income (Loss) per Common Share Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common stockholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Diluted net income (loss) per share is calculated under both the two class method and the treasury stock method and the more dilutive of the two calculations is presented. The following table sets forth a reconciliation of net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts): Year Ended December 31, 2019 2018 2017 Net (loss) income, as reported $ (1,716,297 ) $ (1,746,481 ) $ 333,146 Participating basic earnings (a) (251 ) (245 ) (3,751 ) Basic net (loss) income attributed to common stockholders (1,716,548 ) (1,746,726 ) 329,395 Reallocation of participating earnings (a) — — 5 Diluted net (loss) income attributed to common stockholders $ (1,716,548 ) $ (1,746,726 ) $ 329,400 Net (loss) income per common share: Basic $ (6.92 ) $ (7.10 ) $ 1.34 Diluted $ (6.92 ) $ (7.10 ) $ 1.34 (a) Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses. The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands): Year Ended December 31, 2019 2018 2017 Denominator: Weighted average common shares outstanding – basic 247,970 246,171 245,091 Effect of dilutive securities: Director and employee restricted stock and performance-based equity awards — — 367 Weighted average common shares outstanding – diluted 247,970 246,171 245,458 Weighted average common shares – basic excludes 3.1 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for the period ending December 31, 2019 compared to 3.1 million shares for the period ending December 31, 2018 and 2.8 million shares for the period ending December 31, 2017. Due to our net loss for the years ended December 31, 2019 and 2018, we excluded all outstanding equity grants from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations. Equity grants of 702,000 for the year ended December 31, 2017 were outstanding but not included in the computations of diluted net income per share because the grant prices were greater than the average market price of the common shares and would be anti-dilutive to the computations. For purposes of calculating diluted weighted average common shares for the year ended December 31, 2017, nonvested restricted stock and performance based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

Indebtedness

Indebtedness	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Indebtedness	(8) Indebtedness We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at December 31, 2019 is shown parenthetically). The expenses of issuing debt are capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized during 2019, 2018, and 2017. December 31, 2019 December 31, 2018 Bank debt (3.0%) $ 477,000 $ 943,000 Senior notes 4.875% senior notes due 2025 750,000 750,000 5.00% senior notes due 2023 741,531 741,531 5.00% senior notes due 2022 511,886 580,032 5.75% senior notes due 2021 374,139 475,952 5.875% senior notes due 2022 297,617 329,244 Other senior notes due 2022 590 590 Total senior notes 2,675,763 2,877,349 Senior subordinated notes 5.00% senior subordinated notes due 2023 7,712 7,712 5.00% senior subordinated notes due 2022 19,054 19,054 5.75% senior subordinated notes due 2021 22,214 22,214 Total senior subordinated notes 48,980 48,980 Total debt 3,201,743 3,869,329 Unamortized premium 3,013 4,741 Unamortized debt issuance costs (31,819 ) (37,209 ) Total debt (net of debt issuance costs) $ 3,172,937 $ 3,836,861 Bank Debt In April 2018, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility has a maximum facility amount of $4.0 billion. As of December 31, 2019, the facility had a borrowing base of $3.0 billion and bank commitments of $2.4 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually by each May and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-seven financial institutions, with no one bank holding more than 7.0 % of the total facility. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. The commitment matures on April 13, 2023 . As of December 31, 2019, the outstanding balance under the bank credit facility was $ 477.0 million with $ 250.2 million of undrawn letters of credit leaving $ 1.7 b illion of borrowing capacity available under the commitment amount. During a non-investment grade period, borrowings under the bank facility can either be at the alternate base rate (“ABR,” as defined in the bank credit agreement) plus a spread ranging from 0.25 % to 1.25 % or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit agreement) plus a spread ranging from 1.25 % to 2.25 %. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to ABR loans or to convert all or any part of our ABR loans to LIBOR loans. The weighted average interest rate was 3.8 % for the year ended December 31, 2019 compared to 3.7 % for the year ended December 31, 2018 and 2.7 % for the year ended December 31, 2017. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30 % to 0.375 %. At December 31, 2019, the commitment fee was 0.30 %, the interest rate margin was % on our LIBOR loans and % on our ABR. At any time during which we have an investment grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and we have elected, at our discretion, to effect the investment grade rating period, certain collateral security requirements, including the borrowing base requirement and restrictive covenants will cease to apply, certain other restrictive covenants will become less restrictive and an additional financial covenant (as defined in the bank credit facility) will be temporarily imposed. During the investment grade period, borrowings under the bank credit facility can either be at the ABR plus a spread ranging from 0.125% to 0.75% or LIBOR Rate plus a spread ranging from 1.125% to 1.75% depending on our debt rating. The commitment fee paid on the undrawn balance ranges from 0.15% to 0.30%. We currently do not have an investment grade rating. New Senior Notes In January 2020, we issued $550.0 million aggregate principal amount of 9.25% senior notes due 2026 (the “9.25% Notes”) for an estimated net proceeds of $541.6 million after underwriting discounts and commissions of $8.4 million. The notes were issued at par. The 9.25% Notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S of the Securities Act of 1933, as amended (the “Securities Act”). Interest due on the 9.25% Notes is payable semi-annually in February and August and is unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors. On or after February 1, 2025, we may redeem the 9.25% Notes, in whole or in part and from time to time, at 100% of the principal amounts plus accrued and unpaid interest. We may redeem the notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indenture governing the 9.25% Notes. Upon occurrence of certain changes in control, we must offer to repurchase the 9.25% Notes. The 9.25% Notes are unsecured and are subordinated to all of our existing and future secured debt, rank equally with all of our existing and future unsecured debt and rank senior to all of our existing and future subordinated debt. On the closing of the 9.25% Notes, we used the proceeds to redeem $324.1 million of our 5.75% senior notes due 2021 and $175.9 million of our 5.875% senior notes due 2022 with the remainder applied to our borrowings under our bank credit facility. Early Extinguishment of Debt In third and fourth quarter 2019, we purchased in the open market $101.8 million principal amount of our 5.75% senior notes due 2021, $31.6 million principal amount of our 5.875% senior notes due 2022 and $68.1 In January 2020, we purchased for cash $500.0 million aggregate principal amount of our 5.75% senior notes due 2021 and our 5.875% senior notes due 2022. An early cash tender of $15.1 million was paid to note holders who tendered their notes within the ten business day early offer period. The cash tender offer and early cash tender premium were financed from the issuance of our new 9.25% Notes. See New Senior Notes Senior Notes and Senior Subordinated Notes If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior subordinated notes and our senior notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and are subordinated to existing and future senior debt that we or our subsidiary guarantors are permitted to incur. Guarantees Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our wholly-owned subsidiaries, which are directly or indirectly owned by Range, of our senior notes, our senior subordinated notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee: • in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or • if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture. Debt Covenants and Maturity Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2019. The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2019 (in thousands): Year Ended 2020 $ — 2021 396,353 2022 829,147 2023 1,226,243 2024 — Thereafter 750,000 $ 3,201,743

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(9) Asset Retirement Obligations Our asset retirement obligations (“ARO”) primarily represent the present value of the estimated amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well lives. The inputs are calculated based on historical data as well as current estimated costs. The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2019 and 2018 (in thousands): 2019 2018 Beginning of period $ 312,754 $ 276,855 Liabilities incurred 4,063 3,376 Acquisitions — 13,438 Liabilities settled (5,953 ) (5,052 ) Disposition of wells (82,576 ) (13,332 ) Accretion expense 15,658 25,456 Change in estimate 7,130 12,013 End of period 251,076 312,754 Less current portion (2,393 ) (5,485 ) Long-term asset retirement obligations (a) $ 248,683 $ 307,269 (a) Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.

Derivative Activities

Derivative Activities	12 Months Ended
	Dec. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Activities	(10) Derivative Activities We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize commodity swap, calls, swaptions or collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. Every derivative instrument is required to be recorded on our consolidated balance sheets as either an asset or a liability measured at its fair value. Their fair value, which is represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price (generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs), approximated a net derivative asset of $126.7 million at December 31, 2019. These contracts expire monthly through December 2021. The following table sets forth the derivative volumes by year as of December 31, 2019, excluding our basis and freight swaps which are discussed separately below: Period Contract Type Volume Hedged Weighted Natural Gas 2020 Swaps 1,000,984 Mmbtu/day $ 2.64 (1) 2021 Swaps 50,000 Mmbtu/day $ 2.62 (1) Crude Oil 2020 Swaps 7,995 bbls/day $ 58.27 (1) 2021 Swaps 1,000 bbls/day $ 55.00 (1) April-September, 2020 Calls 500 bbls/day $ 59.00 NGLs (NC4-Normal Butane) January-March, 2020 Swaps 659 bbls/day $ 0.73/gallon NGLs (C5-Natural Gasoline) January-March, 2020 Swaps 4,297 bbls/day $ 1.21/gallon (1) Basis Swap Contracts In addition to the swaps, collars and swaptions above, at December 31, 2019, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts settle monthly through December 2021 and include a total volume of 114,882,500 Mmbtu. The fair value of these contracts was a net derivative asset of $9.4 million on December 31, 2019. At December 31, 2019, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indexes. The contracts settle monthly in 2020. The fair value of these contracts was a net derivative liability of $14.1 million on December 31, 2019. Freight Swap Contracts In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at December 31, 2019, we had freight swap contracts which lock in the freight rate for a specific trade route on the Baltic Exchange. These contracts settle monthly and cover 4,000 metric tons per month in first quarter 2020, increasing to 14,000 metric tons per month for the remainder of 2020 and 10,000 metric tons per month in 2021 with a fair value net derivative asset of $1.5 million on December 31, 2019. Derivative Assets and Liabilities The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2019 and 2018 is summarized below (in thousands). As of December 31, 2019, we are conducting derivative activities with twenty counterparties, of which all but three are secured lenders in our bank credit facility. We believe all of these counterparties are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. December 31, 2019 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 134,364 $ (2,913 ) $ 131,451 –swaptions — (1,325 ) (1,325 ) –basis swaps 10,766 (1,092 ) 9,674 Crude oil –swaps 3,893 (4,794 ) (901 ) –swaptions — (1,597 ) (1,597 ) –calls — (349 ) (349 ) NGLs –C3 propane spread swaps 1,913 (1,913 ) — –NC4 butane swaps 167 — 167 –C5 natural gasoline swaps 60 (127 ) (67 ) Freight –swaps 1,529 (1,028 ) 501 $ 152,692 $ (15,138 ) $ 137,554 December 31, 2019 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (1,657 ) $ 2,913 $ 1,256 –swaptions (2,594 ) 1,325 (1,269 ) –basis swaps (1,371 ) 1,092 (279 ) Crude oil –swaps (4,814 ) 4,794 (20 ) –swaptions (2,254 ) 1,597 (657 ) –calls (349 ) 349 — NGLs –C3 propane spread swaps (16,040 ) 1,913 (14,127 ) –C5 natural gasoline swaps (127 ) 127 — Freight –swaps — 1,028 1,028 $ (29,206 ) $ 15,138 $ (14,068 ) December 31, 2018 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 20,834 $ (11,748 ) $ 9,086 –swaptions 5,200 (3,883 ) 1,317 –basis swaps 6,468 (2,822 ) 3,646 Crude oil –swaps 26,481 (651 ) 25,830 –collars 5,945 (707 ) 5,238 NGLs –C3 propane swaps 18,719 (589 ) 18,130 –C3 propane collars 8,538 — 8,538 –C3 propane spread swaps 8,984 (8,868 ) 116 –NC4 butane swaps 4,084 — 4,084 –C5 natural gasoline swaps 17,371 — 17,371 Freight –swaps — (561 ) (561 ) $ 122,624 $ (29,829 ) $ 92,795 December 31, 2018 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (18,332 ) $ 11,748 $ (6,584 ) –swaptions (7,972 ) 3,883 (4,089 ) –basis swaps (1,702 ) 2,822 1,120 Crude oil –swaps — 651 651 –collars — 707 707 NGLs –C3 propane swaps — 589 589 –C3 propane spread swaps (8,868 ) 8,868 — Freight –swaps (561 ) 561 — $ (37,435 ) $ 29,829 $ (7,606 ) The effects of our derivatives on our consolidated statements of operations for the last three years are summarized below (in thousands). Year Ended December 31, Derivative Fair Value (Loss) Income 2019 2018 2017 Commodity swaps $ 219,968 $ (57,950 ) $ 181,095 Swaptions 333 (6,556 ) 6,534 Collars (3,903 ) 17,583 18,132 Basis swaps 6,661 (1,104 ) (4,647 ) Puts — — 10,929 Calls (349 ) (2,653 ) 987 Freight swaps 3,971 (512 ) 320 Total $ 226,681 $ (51,192 ) $ 213,350

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	(11) Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows: • Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. • Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. • Level 3 – Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments using standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall value. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. When transfers between levels occur, it is our policy to assume the transfer occurred at the date of the event or change in circumstances that caused the transfer. Fair Values-Recurring We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands): Fair Value Measurements at December 31, 2019 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 62,009 $ — $ — $ 62,009 Derivatives –swaps — 131,886 — 131,886 –calls — (349 ) — (349 ) –basis swaps — (4,732 ) — (4,732 ) –freight swaps — 1,529 — 1,529 –swaptions — — (4,848 ) (4,848 ) Fair Value Measurements at December 31, 2018 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 57,293 $ — $ — $ 57,293 Derivatives –swaps — 69,156 — 69,156 –collars — 5,945 8,538 14,483 –basis swaps — 4,883 — 4,883 –freight swaps — (561 ) — (561 ) –swaptions — — (2,772 ) (2,772 ) Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2019 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. As of December 31, 2019, a portion of our natural gas derivative instruments contain swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a predetermined date. Derivatives in Level 3 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. Subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our swaptions. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Year Ended December 31, 2019 Balance at the beginning of period $ 5,766 Total gains (losses): Included in earnings — Settlements received (7,692 ) Transfers in and/or out of Level 3 (2,922 ) Balance at end of period $ (4,848 ) Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains/losses are included in deferred compensation plan expense in the accompanying consolidated statements of operations. For the year ended December 31, 2019, interest and dividends were $1.1 million and mark-to-market was a gain of $8.5 million. For the year ended December 31, 2018, interest and dividends were $1.1 million and mark-to-market was a loss of $7.9 million. For the year ended December 31, 2017, interest and dividends were $4.1 million and mark-to-market was a gain of $4.2 million. Fair Values-Non recurring Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying values of certain of our natural gas and oil properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value is generally measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. In some cases, we also considered the potential sale of these properties and comparable market value, if available. In fourth quarter 2019, there were indicators that the carrying value of our North Louisiana properties may be impaired due to a shift in business strategy employed by management and also the possibility of a divestiture of these assets. As a result of the impairment evaluation, where we used an income approach, also referred to as a discounted cash flow model, to assess fair value and we recorded an impairment of $1.1 billion. An additional guideline transaction market approach was also utilized to corroborate the estimated fair value. The expected future net cash flows used published future prices and were discounted using an annual rate of twelve percent to determine fair value. We have a gas processing agreement that extends through 2030 in North Louisiana where we must pay a quarterly deficiency payment if the minimum volume commitment is not met. In the event these properties are sold in the future and any or all of these charges are retained by us, we would recognize and accrue these future divestiture-related charges, which could be significant. For fourth quarter 2019, our deficiency charges were approximately $14.0 million. During 2018, we increased our interest in certain properties in our shallow legacy oil and natural gas assets in Northwest Pennsylvania for a minimal dollar amount for which the fair value was previously determined to be zero. As a result, in 2018 we recorded additional impairment of $15.3 million related to these properties. In early 2018, there were indicators that the carrying value of certain of our oil and gas properties in Oklahoma may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. We recorded non-cash impairment charges of $7.3 million related to these properties. We recorded non-cash impairment charges during the year ended 2017 of $63.7 million related to certain of our oil and gas properties in Oklahoma and the Texas Panhandle. The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands): Year Ended December 31, 2019 2018 2017 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ 370,500 $ 1,093,531 $ 32,516 $ 22,614 $ 85,597 $ 63,679 Fair Value-Goodwill During 2016, we recorded goodwill associated with a business acquisition, which represented the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. As of November 1, 2018, we performed our annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount. Based on the results of this assessment, we determined it was not likely that goodwill was impaired. However, since that qualitative assessment at November 1, 2018, our stock price declined significantly through December 31, 2018, at which time our stock price closed at $9.57 per share. At that time, we undertook a quantitative goodwill assessment. In this assessment, fair value is estimated based on a combination of a market capitalization and an income approach. The income approach is based on internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. The estimated market capitalization approach utilized a 20 day weighted average stock price and our common shares outstanding as of December 31, 2018. Management utilized the assistance of a third-party valuation expert to determine the fair value of our business. Two additional market approaches, the guideline public company multiple and the guideline transaction method were also utilized to corroborate the estimated fair value. As a result of this measurement, we recorded a $ 1.6 billion impairment of goodwill during fourth quarter 2018. Fair Values-Reported The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2019 and 2018 (in thousands): December 31, 2019 December 31, 2018 Carrying Fair Carrying Fair Assets: Commodity swaps, options and basis swaps $ 137,554 $ 137,554 $ 92,795 $ 92,795 Marketable securities (a) 62,009 62,009 57,293 57,293 (Liabilities): Commodity swaps, options and basis swaps (14,068 ) (14,068 ) (7,606 ) (7,606 ) Bank credit facility (b) (477,000 ) (477,000 ) (943,000 ) (943,000 ) 5.75% senior notes due 2021 (b) (374,139 ) (375,909 ) (475,952 ) (455,972 ) 5.00% senior notes due 2022 (b) (511,886 ) (501,582 ) (580,032 ) (519,343 ) 5.875% senior notes due 2022 (b) (297,617 ) (294,757 ) (329,244 ) (305,989 ) Other senior notes due 2022 (b) (590 ) (592 ) (590 ) (581 ) 5.00% senior notes due 2023 (b) (741,531 ) (683,291 ) (741,531 ) (654,683 ) 4.875% senior notes due 2025 (b) (750,000 ) (645,098 ) (750,000 ) (616,313 ) 5.75% senior subordinated notes due 2021 (b) (22,214 ) (21,539 ) (22,214 ) (21,638 ) 5.00% senior subordinated notes due 2022 (b) (19,054 ) (17,011 ) (19,054 ) (17,072 ) 5.00% senior subordinated notes due 2023 (b) (7,712 ) (7,654 ) (7,712 ) (6,690 ) Deferred compensation plan (c) (74,472 ) (74,472 ) (80,092 ) (80,092 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges. (b) The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs. (c) The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input. Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense.

Stock-based Compensation Plans

Stock-based Compensation Plans	12 Months Ended
	Dec. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-based Compensation Plans	(12) Stock-Based Compensation Plans Description of the Plans We have two active equity-based stock plans, our 2005 Equity Based Compensation Plan, which we refer to as the 2005 Plan and the new 2019 Equity-Based Compensation Plan, which was approved by our stockholders in May 2019. Under these plans, the compensation committee of the board of directors may grant, among other things, stock options, SARs, PSUs and restricted stock awards to non-employee directors and employees. Shares issued as a result of awards granted are generally new common shares but can be funded out of treasury shares, if available. Total Stock-Based Compensation Expense Stock-based compensation expense represents amortization of restricted stock and performance units. The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2019 (in thousands): 2019 2018 2017 (1) Direct operating expense $ 1,928 $ 2,109 $ 2,060 Brokered natural gas and marketing expense 1,856 1,452 1,437 Exploration expense 1,566 1,921 2,742 General and administrative expense 35,061 43,806 74,873 Termination costs 1,971 — 1,664 Total $ 42,382 $ 49,288 $ 82,776 (1) Includes $30.8 million accelerated vesting of equity grants. In fourth quarter 2017, the compensation committee approved a new post-retirement benefit plan (See Other Post Retirement Benefits Unlike the other forms of stock-based compensation expense mentioned above, the mark-to-market of the liability related to the vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not directly related to the functional expenses. Therefore, the liability related to the vested restricted stock held in our deferred compensation plans is not allocated to the functional categories and is reported as deferred compensation plan expense in the accompanying consolidated statements of operations. In 2019, we recorded $3.4 million additional tax expense for the tax effect of excess financial accounting expense over the corporate income tax deduction for equity compensation vested in the year compared to $3.6 million in 2018 and $5.3 million in 2017. Stock-Based Awards Restricted Stock Awards . We grant restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, generally vest over a three-year The compensation committee also grants restricted stock to certain employees and non-employee directors of the board of directors as part of their compensation. We also grant restricted stock to certain employees for retention purposes. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock (by the trustee) and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority of these shares are generally placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in stock. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we also may utilize treasury shares when available. Stock-Based Performance Units . We grant three types of performance share awards: two of which are based on performance conditions measured against internal performance metrics (Production Growth Awards or “PG-PSUs” and Reserve Growth Awards or “RG-PSUs”) and one based on market conditions measured based on Range’s performance relative to a predetermined peer group (TSR Award or “TSR-PSUs”). At grant date, each unit represents the value of one share of our common stock. These units are settled in stock and the amount of the payout is based on (1) the vesting percentage, which can be from zero to 200% based on the performance achieved and (2) the value of our common stock on the date vesting is determined by the compensation committee. Dividend equivalents may accrue during the performance period and would be paid in stock at the end of the performance period. The performance period is a three-year period. Restricted Stock – Equity Awards In 2019, we granted 2.8 million restricted stock Equity Awards to employees which generally vest over a three-year Restricted Stock – Liability Awards In 2019, we granted 1.2 million shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $10.16. These grants included 183,000 shares issued to non-employee directors, which vest immediately, and 1.0 million shares to employees with vesting generally over a three-year three-year three-year Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2016 765,971 $ 33.62 425,018 $ 43.48 Granted 888,326 32.61 543,438 25.91 Vested (698,563 ) 34.82 (908,912 ) 33.71 Forfeited (122,676 ) 32.91 (4,342 ) 31.10 Outstanding at December 31, 2017 833,058 31.64 55,202 32.26 Granted 1,834,883 16.98 891,350 15.30 Vested (1,037,501 ) 23.57 (738,073 ) 16.34 Forfeited (244,352 ) 21.59 (23,900 ) 19.76 Outstanding at December 31, 2018 1,386,088 20.04 184,579 15.65 Granted 2,792,438 10.59 1,214,038 10.16 Vested (1,608,075 ) 15.72 (987,491 ) 10.86 Forfeited (568,212 ) 13.03 — — Outstanding at December 31, 2019 2,002,239 $ 12.32 411,126 $ 10.94 Stock-B ased Performance Units Production Growth and Reserve Growth Awards. The PG-PSUs and RG-PSUs vest at the end of the three-year 31, 2019: Number of Weighted Outstanding at December 31, 2016 — $ — Units granted 122,921 25.53 Outstanding at December 31, 2017 122,921 25.53 Units granted ( a ) 440,938 15.22 Forfeited (b) (27,061 ) 23.03 Outstanding at December 31, 2018 536,798 15.61 Units granted (a) 345,202 10.32 Forfeited (427 ) 15.65 Outstanding at December 31, 2019 881,573 $ 11.70 (a) (b) first We recorded PG/RG-RSUs compensation expense of $3.8 million in the year ended December 31, 2019 compared to $5.4 million in the year ended December 31, 2018 and $1.8 million in the year ended December 31, 2017. Accelerated vesting compensation expense of $1.5 million is included in the year ended December 31, 2017. As of December 31, 2019, there was $933,000 of unrecognized compensation related these PSU awards to be recognized over a weighted average period of 1.0 years. TSR Awards. TSR-PSUs granted are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over a three-year performance period. The fair value of the TSR-PSUs is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The fair value is recognized as stock-based compensation expense over the three-year Year Ended December 31, 2019 2019 2018 2017 Risk-free interest rate 2.44 % 2.42 % 1.49 % Expected annual volatility 46 % 48 % 44 % Grant date fair value per unit $ 11.34 $ 18.51 $ 26.26 The following is a summary of our non-vested TSR – Weighted Outstanding at December 31, 2016 871,299 $ 55.29 Granted (a) 358,519 26.26 Vested and issued (b) (85,461 ) 86.23 Forfeited (134,515 ) 85.24 Outstanding at December 31, 2017 1,009,842 38.38 Granted (a) 329,486 18.51 Vested and issued (c) (73,985 ) 56.81 Forfeited (197,457 ) 55.46 Outstanding at December 31, 2018 1,067,886 27.81 Granted (a) 314,152 11.34 Vested and issued (d) (12,283 ) 30.47 Forfeited (376,303 ) 37.25 Outstanding at December 31, 2019 993,452 $ 19.00 (a) These (b ) th th (c) th th (d) th We recorded TSR-PSU compensation expense of $3.0 million in the year ended December 31, 2019 compared to $6.3 million in the year ended December 31, 2018 and $24.8 million in the year ended December 31, 2017. Accelerated vesting compensation expense of $13.0 million is included in the year ended December 31, 2017. As of December 31, 2019, there was $1.5 million of unrecognized compensation related to these PSU awards to be recognized over a weighted average period of 1.2 years. 401(k) Plan We maintain a 401(k) benefit plan that allows employees to contribute up to 75% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. We match up to 6% of salary in cash and vesting of those contributions is immediate. In 2019, we contributed $5.4 million to the 401(k) Plan compared to $5.8 million in 2018 and $5.1 million in 2017. Employees have a variety of investment options in the 401(k) benefit plan. Deferred Compensation Plan Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests over three years. The assets of the plans are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market gain of $15.5 million in 2019 compared to $18.6 million in 2018 and $50.9 million in 2017. The Rabbi Trust held 3.2 million shares (2.7 million of vested shares) of Range stock at December 31, 2019 compared to 2.6 million (2.4 million of vested shares) at December 31, 2018. Other Post Retirement Benefits Effective fourth quarter 2017, we implemented a post retirement benefit plan to assist in providing health care to officers who are active employees (including their spouses) and have met certain age and service requirements. These benefits are not funded in advance and are provided up to age 65 or on the date they become eligible for Medicare, subject to various cost-sharing features. The change in our post-retirement benefit obligation is as follows (in thousands): Change in Benefit Obligation: Benefit obligation at beginning of year $ 1,355 $ 1,769 Prior service cost — — Service cost 88 94 Interest cost 68 58 Actuarial loss (gain) 532 (526 ) Benefits paid (86 ) (40 ) Benefit obligation at end of year $ 1,957 $ 1,355 Amounts recognized in the consolidated balance sheet: Long-term liabilities $ 1,957 $ 1,355 Components of Net Periodic Post Retirement Benefit Cost: Service cost $ 88 $ 94 Interest cost 68 58 Amortization of prior service cost 369 369 Net periodic post retirement costs (recognized in general and administrative expense) $ 525 $ Other Changes in Benefit Obligations in Other Comprehensive Income (Loss): Net loss (gain) $ 532 $ (526 ) Prior service cost — — Amortization of prior service cost (369 ) (369 ) Total recognized in other comprehensive income (loss) $ 163 $ (895 ) Total recognized in net periodic benefit cost and other comprehensive income (loss) $ 688 $ (374 ) The following summarizes the assumptions used to determine the benefit obligation at December 31, 2019 and 2018: December 31, 2019 December 31, 2018 Weighted average assumptions used to determine benefit obligation: Discount rate 2.9 % 4.0 % Assumed weighted average healthcare cost trend rates: Initial healthcare trend rate 6.5 % 6.5 % Ultimate trend rate 4.5 % 5.0 % Year ultimate trend rate reached 2023 2028 The expected future benefit payments under our post retirement benefit plan for the next ten years is $1.1 million for the five year period 2020 through 2024 and $433,000 for the five year period 2025 through 2029. The estimated prior service cost that will be amortized from accumulated other comprehensive (loss) income into our statements of operations in 2020 is $369,000.

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Capital Stock	(13) Capital Stock We have authorized capital stock of 485.0 million shares, which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2017: Year Ended December 31, 2019 2018 2017 Beginning balance 249,510,022 248,129,430 247,144,356 Restricted stock grants 1,186,290 865,095 539,096 Restricted stock units vested 720,212 434,046 344,937 Performance stock units issued 12,747 76,149 85,461 Treasury shares (1,798,468 ) 5,302 15,580 Ending balance 249,630,803 249,510,022 248,129,430 Common Stock Dividends The board of directors declared quarterly dividends of $0.02 per common share for each of the four quarters of 2019, 2018 and 2017. In January 2020, we announced that the board has suspended the dividend. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and will depend on our financial condition, earnings, capital requirements, levels of indebtedness, our future business prospects and other matters our board of directors deem relevant. Our bank credit facility and our senior subordinated notes allow for the payment of common dividends, with certain limitations, as described in the indentures governing each of our notes. Stock Repurchase Program In October 2019, the board of directors approved a new stock purchase program to acquire up to $100 million of our outstanding stock. The following is a schedule of change in treasury shares since the beginning of 2017: Year Ended December 31, 2019 2018 2017 Beginning balance 9,665 14,967 30,547 Rabbi trust shares distributed and/or sold (1,532 ) (5,302 ) (15,580 ) Shares repurchased 1,800,000 — — Ending balance 1,808,133 9,665 14,967

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(14) Supplemental Cash Flow Information Year Ended December 31, 2019 2018 2017 (in thousands) Net cash provided from operating activities included: Income taxes refunded from taxing authorities $ — $ 7,521 $ 1,024 Interest paid (189,443 ) (207,433 ) (179,431 ) Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 11,193 $ 28,826 $ 20,245 (Decrease) increase in accrued capital expenditures (20,104 ) (119,021 ) 71,739

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	(15) Commitments and Contingencies Litigation We are the subject of, or party to, a number of pending or threatened legal actions and administrative proceedings arising in the ordinary course of our business including, but not limited to, royalty claims, contract claims and environmental claims. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. When deemed necessary, we established reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that include the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible we could incur additional losses with respect to those matters in which reserves have been established. We will continue to evaluate our litigation on a quarterly basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation. We have incurred and will continue to incur capital, operating and remediation expenditures as a result of environmental laws and regulations. As of December 31, 2019 and 2018, liabilities for remediation were not material. We are not aware of any environmental claims existing as of December 31, 2019 that have not been provided for or would otherwise have a material impact on our financial position or results of operations. Environmental liabilities normally involve estimates that are subject to revision until final resolution, settlement or remediation occurs. Lease Commitments The components of our total lease expense for the year ended December 31, 2019, the majority of which is included in general and administrative expense, are as follows (in thousands): Year Ended December 31, 2019 Operating lease cost $ 15,536 Variable lease expense (1) 6,916 Short-term lease expense (2) 2,965 Sublease income (3,496 ) Total lease expense $ 21,921 Short-term lease costs (3) $ 29,126 ( 1) Variable lease payments that are not dependent on an index or rate are not included in the lease liability or ROU assets. (2) Short-term lease expense represents expense related to leases with a contract term of one year or less. (3) These short-term lease costs are related to leases with a contract term of one year or less and the majority of which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our consolidated balance sheets and may fluctuate based on the number of drilling rigs being utilized. Supplemental cash flow information related to our operating leases is included in the table below (in thousands): Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities $ 18,700 ROU assets added in exchange for lease obligations (since adoption) $ 24,839 Supplemental balance sheet information related to our operating leases is included in the table below (in thousands): December 31, 2019 Operating lease ROU assets $ 62,053 Accrued liabilities – current $ (27,856 ) Operating lease liabilities – long-term $ (41,068 ) As part of our ongoing effort to reduce general and administrative expenses due to the lower commodity price environment, we announced the closing of our Houston office in fourth quarter 2019. We have recorded an impairment related to our Houston office lease ROU asset of $2.1 million which is included in impairment of proved property and other assets in our consolidated statements of operations for the year ended December 31, 2019. Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows: December 31, 2019 Weighted average remaining lease term 4.6 years Weighted average discount rate 6.0% Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating Leases 2020 $ 31,245 2021 14,252 2022 7,023 2023 6,500 2024 6,468 Thereafter 15,262 Total lease payments 80,750 Less effects of discounting (11,826 ) Total lease liability $ 68,924 Transportation, Gathering and Processing Contracts We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production from our properties in Pennsylvania and North Louisiana. Under these contracts, we are obligated to transport, process or gather minimum daily natural gas volumes, or pay for any deficiencies at a specified reservation fee rate. In some cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. See Note 11 for additional information regarding deficiencies in North Louisiana. As of December 31, 2019, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands): Transportation, (a) 2020 $ 945,392 2021 949,126 2022 905,920 2023 870,062 2024 853,457 Thereafter 5,154,987 $ 9,678,944 (a) In addition to the amounts included in the above table, we have entered into additional agreements which are contingent on certain pipeline modifications and/or construction for natural gas volumes of 25,000 mcf per day, which is expected to begin in 2022 and has a six-year Delivery Commitments We have various volume delivery commitments that are related to our Marcellus Shale and North Louisiana areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2019, our delivery commitments through 2031 were as follows: Year Ending December 31, Natural Gas Ethane and Propane (bbls per day) 2020 528,607 81,000 2021 491,313 65,932 2022 370,179 43,000 2023 167,970 35,000 2024-2028 100,000 35,000 2029 100,000 20,000 2030-2031 — 20,000 In addition to the amounts included in the above table, we have contracted with a pipeline company through 2035 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are contingent upon pipeline construction and/or modification, are for 3,000 bbls per day starting in 2021 and increasing to 10,000 bbls per day through 2035. In addition, we have agreements in place to deliver natural gas volumes from our Marcellus Shale wells, which are also contingent upon pipeline construction and/or modification, for 35,000 mcf per day starting in late 2020, increasing to 50,000 mcf per day in late 2021 and decreasing to 15,000 mcf per day in 2025 through 2026. Other We also have lease acreage that is generally subject to expiration if initial wells are not drilled within a specified period, generally between three and five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Termination Costs

Termination Costs	12 Months Ended
	Dec. 31, 2019
Restructuring And Related Activities [Abstract]
Termination Costs	( 16) Termination Costs As part of a continuing effort to reduce our general and administrative expenses due to the lower commodity price environment, additional accruals for severance of $7.5 million and accelerated vesting of stock-based compensation of $2.0 million were recorded in the year ended December 31, 2019. See Note 15 for information related to an impairment of an office lease. The following table details the accrued liability as of December 31, 2019 and December 31, 2018 (in thousands): 2019 2018 Beginning balance $ — $ 1,855 Accrued severance costs 7,535 (356 ) Accrued building rent — (17 ) Payments (2,843 ) (1,482 ) Ending balance $ 4,692 $ — The following summarizes our termination costs for three years ended December 31, 2019, 2018 and 2017 (in thousands): 2019 2018 2017 Severance costs $ 7,535 $ (356 ) $ 2,176 Building lease — (17 ) (70 ) Stock-based compensation 1,971 — 1,664 Total termination costs $ 9,506 $ (373 ) $ 3,770

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Data [Abstract]
Selected Quarterly Financial Data (Unaudited)	(1 7 ) Selected Quarterly Financial Data (Unaudited) The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. Fourth quarter 2019 includes proved and unproved impairment expense of $2.3 billion related to our North Louisiana assets. Fourth quarter 2018 includes goodwill impairment expense of $1.6 billion and unproved impairment expense of $441.8 million related to our North Louisiana assets. 2019 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 671,654 $ 563,579 $ 474,754 $ 545,438 $ 2,255,425 Derivative fair value (loss) income (61,731 ) 195,245 74,676 18,491 226,681 Brokered natural gas, marketing and other 138,214 92,605 73,015 41,675 345,509 Total revenue and other income 748,137 851,429 622,445 605,604 2,827,615 Costs and expenses: Direct operating 33,227 33,981 35,276 33,792 136,276 Transportation, gathering, processing and compression 302,655 301,219 295,912 299,511 1,199,297 Production and ad valorem taxes 11,310 9,889 7,805 8,963 37,967 Brokered natural gas and marketing 132,305 101,117 79,938 46,532 359,892 Exploration 8,211 8,109 11,013 9,350 36,683 Abandonment and impairment of unproved properties 12,659 12,770 16,202 1,193,711 1,235,342 General and administrative 46,638 50,631 41,047 42,793 181,109 Termination costs — 2,206 819 6,481 9,506 Deferred compensation plan 3,581 (11,142 ) (8,871 ) 960 (15,472 ) Interest 51,537 51,727 46,997 44,024 194,285 Gain on early extinguishment of debt — — (2,985 ) (2,430 ) (5,415 ) Depletion, depreciation and amortization 138,718 141,505 137,751 130,869 548,843 Impairment of proved properties and other — — — 1,095,634 1,095,634 Loss (gain) on sale of assets 189 (5,867 ) 36,341 (407 ) 30,256 Total costs and expenses 741,030 696,145 697,245 2,909,783 5,044,203 Income (loss) before income taxes 7,107 155,284 (74,800 ) (2,304,179 ) (2,216,588 ) Income tax expense (benefit): Current — — 4,079 2,068 6,147 Deferred 5,688 40,099 (51,298 ) (500,927 ) (506,438 ) 5,688 40,099 (47,219 ) (498,859 ) (500,291 ) Net income (loss) $ 1,419 $ 115,185 $ (27,581 ) $ (1,805,320 ) $ (1,716,297 ) Net income (loss) per common share: Basic $ 0.01 $ 0.46 $ (0.11 ) $ (7.27 ) $ (6.92 ) Diluted $ 0.01 $ 0.46 $ (0.11 ) $ (7.27 ) $ (6.92 ) 2018 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 696,629 $ 661,390 $ 736,431 $ 756,627 $ 2,851,077 Derivative fair value (loss) income (14,009 ) (103,290 ) (34,591 ) 100,698 (51,192 ) Brokered natural gas, marketing and other 59,979 98,084 109,385 215,312 482,760 Total revenue and other income 742,599 656,184 811,225 1,072,637 3,282,645 Costs and expenses: Direct operating 38,122 35,088 30,926 35,395 139,531 Transportation, gathering, processing and compression 244,628 269,910 304,562 298,716 1,117,816 Production and ad valorem taxes 9,926 10,140 9,427 16,656 46,149 Brokered natural gas and marketing 55,594 102,747 116,080 221,626 496,047 Exploration 7,719 7,499 8,299 10,600 34,117 Abandonment and impairment of unproved properties 11,773 54,922 6,549 441,750 514,994 General and administrative 68,417 47,583 43,722 50,090 209,812 Termination costs (37 ) — (336 ) — (373 ) Deferred compensation plan (7,397 ) 6,615 223 (18,072 ) (18,631 ) Interest 52,385 53,862 54,801 49,161 210,209 Depletion, depreciation and amortization 162,266 161,026 164,266 147,909 635,467 Impairment of proved properties and other 7,312 15,302 — — 22,614 Impairment of goodwill — — — 1,641,197 1,641,197 (Gain) loss on sale of assets (23 ) (156 ) 30 10,815 10,666 Total costs and expenses 650,685 764,538 738,549 2,905,843 5,059,615 Income (loss) before income taxes 91,914 (108,354 ) 72,676 (1,833,206 ) (1,776,970 ) Income tax expense (benefit): Current — — — — — Deferred 42,676 (28,518 ) 24,137 (68,784 ) (30,489 ) 42,676 (28,518 ) 24,137 (68,784 ) (30,489 ) Net income (loss) $ 49,238 $ (79,836 ) $ 48,539 $ (1,764,422 ) $ (1,746,481 ) Net income (loss) per common share: Basic $ 0.20 $ (0.32 ) $ 0.19 $ (7.15 ) $ (7.10 ) Diluted $ 0.20 $ (0.32 ) $ 0.19 $ (7.15 ) $ (7.10 )

Supplemental Information on Nat

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	(18) Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) Our natural gas and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States. Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2019 2018 2017 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 9,345,557 $ 10,974,929 $ 10,572,453 Unproved properties 868,180 2,110,277 2,644,000 Total 10,213,737 13,085,206 13,216,453 Accumulated depreciation, depletion and amortization (4,172,702 ) (4,062,021 ) (3,649,716 ) Net capitalized costs $ 6,041,035 $ 9,023,185 $ 9,566,737 (a) Costs Incurred for Property Acquisition, Exploration (a) December 31, 2019 2018 2017 (in thousands) Acquisitions Acreage purchases $ 57,324 $ 62,390 $ 62,075 Oil and gas properties — 1,683 18,269 Development 666,984 834,552 1,177,526 Exploration: Drilling — 1,380 2,030 Expense 35,117 32,196 50,920 Stock-based compensation expense 1,566 1,921 2,742 Gas gathering facilities: Development 3,583 10,218 15,097 Subtotal 764,574 944,340 1,328,659 Asset retirement obligations 11,193 28,826 20,245 Total costs incurred $ 775,767 $ 973,166 $ 1,348,904 (a) Reserve Audit All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2019, Wright & Company, Inc., an independent petroleum consultant, conducted an audit of our 2019 reserves in Appalachia. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2019, our consultant audited approximately 90% of our proved reserves. Copies of the summary reserve reports prepared by our independent petroleum consultant is included as an exhibit to this Annual Report on Form 10-K. The technical professional at our independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished during the reserves audit process. Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve differences. The reserve auditor estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared lease-by-lease, field-by-field or area-by-area basis, some of our estimates may be greater and some may be less than the estimates of our reserve auditor. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis. Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum consultants have been less than 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than thirty-five years of engineering experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions. Estimated Quantities of Proved Oil and Gas Reserves Reserves of natural gas, NGLs, crude oil and condensate are estimated by our petroleum engineering staff and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, production taxes and other economic factors. The SEC defines proved reserves as those volumes of natural gas, NGLs, crude oil and condensate that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated when such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating each location is scheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time. The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts. The average realized prices used at December 31, 2019 to estimate reserve information were $49.24 per barrel of oil, $17.32 per barrel of NGLs and $2.38 per mcf for gas using a benchmark (NYMEX) of $55.73 per barrel and $2.58 per Mmbtu. The average realized prices used at December 31, 2018 to estimate reserve information were $59.96 per barrel of oil, $25.22 per barrel of NGLs and $2.98 per mcf for gas using a benchmark (NYMEX) of $65.55 per barrel and $3.10 per Mmbtu. The average realized prices used at December 31, 2017 to estimate reserve information were $45.73 per barrel of oil, $17.84 per barrel of NGLs and $2.60 per mcf for gas using a benchmark (NYMEX) of $51.19 per barrel and $2.98 per Mmbtu. Natural Gas NGLs Crude Oil and Condensate Natural Gas (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: Balance, December 31, 2016 7,870,416 630,066 70,252 12,072,322 Revisions 70,222 83,338 (10,555 ) 506,919 Extensions, discoveries and additions 2,866,103 87,572 15,997 3,487,519 Purchases 7,738 330 66 10,116 Property sales (60,278 ) (2,356 ) (1,121 ) (81,133 ) Production (490,552 ) (35,686 ) (4,785 ) (733,382 ) Balance, December 31, 2017 10,263,649 763,264 69,854 15,262,361 Revisions 178,595 84,993 7,197 731,735 Extensions, discoveries and additions 2,269,427 128,436 17,309 3,143,898 Purchases — — — — Property sales (135,884 ) (16,774 ) (4,276 ) (262,180 ) Production (548,085 ) (38,325 ) (4,228 ) (803,408 ) Balance, December 31, 2018 12,027,702 921,594 85,856 18,072,406 Revisions 33,122 57,311 (12,320 ) 303,068 Extensions, discoveries and additions 959,901 26,505 7,057 1,161,274 Property sales (327,634 ) (28,324 ) (2,371 ) (511,811 ) Production (578,114 ) (38,850 ) (3,690 ) (833,354 ) Balance, December 31, 2019 12,114,977 938,236 74,532 18,191,583 Proved developed reserves: December 31, 2017 5,437,674 448,258 36,808 8,348,074 December 31, 2018 6,451,012 512,318 38,658 9,756,870 December 31, 2019 6,486,211 535,007 34,369 9,902,468 Proved undeveloped reserves: December 31, 2017 4,825,975 315,006 33,046 6,914,287 December 31, 2018 5,576,690 409,276 47,198 8,315,536 December 31, 2019 5,628,766 403,229 40,163 8,289,115 (a) Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices. During 2019, we added approximately 1.2 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 83% of the 2019 reserve additions are attributable to natural gas. Included in 2019 proved reserves is a total of 475.0 Mmbbls of ethane reserves (2,102 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 303 Bcfe include positive performance revisions of 922.2 Bcfe which were partially offset by 601.3 Bcfe reclassified to unproved and negative pricing revisions of 17.8 Bcfe. During 2018, we added approximately 3.1 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 72% of the 2019 reserve additions are attributable to natural gas. Included in 2018 proved reserves is a total of 468.9 Mmbbls of ethane reserves (2,075 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 732 Bcfe include positive pricing and performance revisions of 957 Bcfe and unproved recoveries of 154 Bcfe which were partially offset by 379 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. During 2017, we added approximately 3.5 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 82% of the 2017 reserve additions are attributable to natural gas. Included in 2017 proved reserves is a total of 360.6 Mmbbls of ethane reserves (1,596 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 507 Bcfe include positive performance revisions of 532 Bcfe, improved recoveries of 597 Bcfe, positive pricing revisions of 46 Bcfe partially offset by 668 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. Purchases of reserves in 2017 reflects reserves added in North Louisiana. The following details the changes in proved undeveloped reserves for 2019 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2018 8,315,536 Undeveloped reserves transferred to developed (1,215,684 ) Revisions (a) 265,947 Sales (214,637 ) Extension and discoveries 1,137,953 Ending proved undeveloped reserves at December 31, 2019 8,289,115 (a) During 2019, we spent approximately $340.4 million in development costs related to proved undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $2.9 billion over the next five years. As of December 31, 2019, we have 86 Bcfe that have been reported for more than five years from their original date of booking, all of which are in the process of being drilled and are expected to turn to sales in 2020. All of our recorded proved undeveloped drilling locations are scheduled to be drilled within five years of initial disclosure. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2024. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following summarizes the policies we used in the preparation of the accompanying natural gas, NGLs, crude oil and condensate reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas, NGLs and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers. The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas, NGLs, crude oil and condensate, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: 1. Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions. 2. For the years ended 2019, 2018 and 2017, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year. 3. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves. 4. The resulting future net cash flows are discounted to present value by applying a discount rate of 10%. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas, NGLs and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflows are net of third-party transportation, gathering and compression expense. As of December 31, 2019 2018 (in thousands) Future cash inflows $ 48,718,733 $ 64,287,737 Future costs: Production (23,320,477 ) (25,626,373 ) Development (a) (3,219,349 ) (3,824,936 ) Future net cash flows before income taxes 22,178,907 34,836,428 Future income tax expense (4,179,297 ) (7,285,274 ) Total future net cash flows before 10% discount 17,999,610 27,551,154 10% annual discount (11,371,037 ) (16,435,560 ) Standardized measure of discounted future net cash flows $ 6,628,573 $ 11,115,594 (a) The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2019 2018 2017 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ (6,560,107 ) $ 2,959,488 $ 2,615,825 Revisions in quantities (12,741 ) 667,763 445,667 Changes in future development and abandonment costs 104,585 (686,632 ) (814,215 ) Net change in income taxes 1,125,639 (1,075,867 ) (706,531 ) Accretion of discount 1,317,349 814,725 372,743 Purchases of reserves in place — — 6,173 Additions to proved reserves from extensions, discoveries and improved recovery 552,710 2,543,296 2,128,135 Natural gas, NGLs and oil sales, net of production costs (881,883 ) (1,547,580 ) (1,237,970 ) Actual development costs incurred during the period 676,520 851,188 1,202,618 Sales of reserves in place (688,937 ) (226,953 ) (32,946 ) Timing and other (120,156 ) (349,048 ) (266,214 ) Net change for the year (4,487,021 ) 3,950,380 3,713,285 Beginning of year 11,115,594 7,165,214 3,451,929 End of year $ 6,628,573 $ 11,115,594 $ 7,165,214

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation The accompanying consolidated financial statements, including the notes, have been prepared in accordance with U.S. GAAP and include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation.
Use of Estimates	Use of Estimates The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates and changes in these estimates are recorded when known. Estimated quantities of natural gas, NGLs, crude oil and condensate reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, NGLs, crude oil and condensate. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs, crude oil and condensate reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of natural gas, NGLs and crude oil and condensate that are ultimately recovered. See Note 18 for further detail. Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, valuation of derivative instruments and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Business Segment Information	Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs, crude oil and condensate in the United States. We consider our gathering, processing and marketing functions as integral to our natural gas, crude oil and condensate producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on a geographical or area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to optimize returns without regard to individual areas.
Revenue Recognition, Accounts Receivable and Gas Imbalances	Revenue Recognition, Accounts Receivable and Gas Imbalances Natural gas, NGLs and oil sales revenues are recognized when control of the product is transferred to the customer and collectability is reasonably assured. See a more detailed summary of our product types below. Natural Gas and NGLs Sales Under our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction. For those contracts that we have concluded that we are the principal, the ultimate third party is our customer and we recognize revenue on a gross basis, with gathering, compression, processing and transportation fees presented as an expense. Alternatively, for those contracts that we have concluded that we are the agent, the midstream processing entity is our customer and we recognize revenue based on the net amount of the proceeds received from the midstream processing entity. In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in kind at the tailgate of the midstream entity’s processing plant and subsequently market the product on our own. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser are presented as transportation, gathering, processing and compression expense. Oil Sales Our oil sales contracts are generally structured in one of the following ways: • We sell oil production at the wellhead and collect an agreed-upon index price, net of transportation incurred by the purchaser (that is, a netback arrangement). In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received. • We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation, gathering, processing and compression expense. Brokered Natural Gas, Marketing and Other We realize brokered margins as a result of buying natural gas or NGLs utilizing separate purchase transactions, generally with separate counterparties, and subsequently selling that natural gas or NGLs under our existing contracts to fill our contract commitments or use existing infrastructure contracts to economically fulfill available capacity. In these arrangements, we take control of the natural gas purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Our net brokered margin was a loss of $14.2 million in 2019 compared to a loss of $16.3 million in 2018 and a loss of $5.7 million in 2017. The recognition of gains or losses on derivative instruments is not considered revenue from contracts with customers. We may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales or in limited cases may use them for contracts we intend to physically settle but that do not meet all of the criteria to be treated as normal sales. Accounts Receivable Our accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties we operate. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. However, this concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. For receivables from joint interest owners, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $8.8 million at December 31, 2019 compared to $6.1 million at December 31, 2018. We recorded bad debt expense of $4.3 million in the year ended December 31, 2019 compared to income of $1.0 million in the year ended December 31, 2018 and expense of $1.6 million in the year ended December 31, 2017.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows.
Marketable Securities	Marketable Securities Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets.
Natural Gas and Oil Properties	Natural Gas and Oil Properties Property Acquisition Costs . We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Depreciation, Depletion and Amortization . Depreciation, depletion and amortization of proved properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. In the year ended December 31, 2015, the fair value of our natural gas and oil properties in Northwest Pennsylvania was determined to be zero. As a result, any future adjustments to the asset retirement liability for these properties represents an impairment expense and we have elected to record such expense in depreciation, depletion and amortization. In the year ended December 31, 2019, additional expense of $213,000 was recorded related to these costs compared to $9.8 million of additional expense in the year ended December 31, 2018 and $158,000 of additional expense in the year ended December 31, 2017. As of December 31, 2019, we executed an agreement to sell these Northwest Pennsylvania assets, pending certain state governmental approval for change in operatorship. Impairments . Our proved natural gas and oil properties are reviewed for impairment annually and periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market-related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and possible reserves, as appropriate, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value as determined by discounted future net cash flows using a discount rate similar to that used by market participants, or comparable market value if available and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 11. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs and allocated probable and possible reserves value resulting from acquisitions. The costs are capitalized and evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management which could impact the number of drilling locations we intend to drill. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Information such as reservoir performance or future plans to develop acreage is also considered. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. In certain circumstances, our future plans to develop acreage may accelerate our impairment. A significant portion of our unproved property is related to probable and possible reserves whose recoverability is evaluated based on management’s expectations and ability to drill these locations. Unproved properties had a net book value of $868.2 million as of December 31, 2019 compared to $2.1 billion in 2018. Unproved properties as of December 31, 2019 are all within Pennsylvania. We have recorded abandonment and impairment expense related to unproved properties of $1.2 billion in the year ended December 31, 2019 compared to $515.0 million in 2018 and $269.7 million in 2017. Abandonment and impairment expense in 2019 includes $1.2 billion compared to $436.0 million in 2018 related to probable and possible reserves in North Louisiana where we no longer have the intent to drill. Dispositions . Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets. For additional information regarding our dispositions, see Note 4 .
Other Property and Equipment	Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $5.0 million in the year ended December 31, 2019 compared to $6.0 million in the year ended December 31, 2018 and $7.7 million in the year ended December 31, 2017.
Leases	Leases We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not have any finance leases. We capitalize our operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term of one year or less are not capitalized but are disclosed. Short-term lease costs exclude expenses related to leases with a lease term of one month or less. Our operating leases are reflected as operating lease ROU assets, accrued liabilities-current and operating lease liabilities on our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Our leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease liabilities and ROU assets only when we are the signatory to a contract as an operator of joint properties. Such lease liabilities and ROU assets are determined and disclosed based on gross contractual obligations. Our lease costs are also presented on a gross basis. Nature of Leases We lease certain office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below. Office Agreements and Subleases. We rent office space from third parties for our corporate and field locations. Our office agreements are typically structured with non-cancelable terms of one to fifteen years. We have concluded our office agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term. We also sublease some of our office space to third parties. All of our subleases have terms that end in 2020 or 2022. The sublease agreements are non-cancelable through the end of the term and both parties have substantive rights to terminate the lease when the term is complete. Our sublease agreements are not capitalized and are recorded as sublease income (as a component of lease costs) in the period the rent is received. As of December 31, 2019, these subleases total $3.1 million through the beginning of 2022. Field Equipment. We rent compressors and coolers from third parties in order to facilitate the downstream movement of our production to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one to two years and continue thereafter on a month-to-month basis subject to termination by either party with thirty days notice. We have concluded that our compressor and cooler rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. Vehicles. We rent our vehicle fleet for our drilling and operations personnel from a third party. Our vehicle agreements are non-cancelable for a minimum term of one year and a maximum term of four to eight years depending on the type of vehicle. However, we have assumed a term of three years based on the period covered by options to terminate that we are reasonably certain to exercise. We have concluded our vehicle commitments are operating leases. Other Equipment. We utilize a dedicated natural gas fueled, electric driven frac fleet to support our drilling activities. This arrangement is structured with a non-cancellable primary term of eighteen months, with two optional extension periods of six months each. We have concluded that this arrangement is an operating lease with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days’ notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig-by-rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the successful efforts method of accounting, these costs are capitalized as part of natural gas and oil properties on our consolidated balance sheets when paid. Transportation, Gathering and Processing Arrangements. We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the third party’s underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset. However, in limited circumstances, we do utilize substantially all of the capacity of a portion of the midstream system under our transportation, gathering and/or processing service contract. These arrangements require judgment to determine whether our capacity of the underlying midstream asset represents a lease. Under all of these arrangements, we have concluded that (i) the midstream entity maintains control of and has the ability to optimize and/or expand the underlying system throughout the duration of the contract term and (ii) the portion of the system or facility we utilize is highly integrated and interconnected to a broader system servicing a diverse set of customers. Consequently, the transportation, gathering and/or processing contract does not represent a lease of the underlying portion of the midstream system or facilities. We currently have not identified any of these commitments as leases. Discount Rate Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term in an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable. Practical Expedients and Accounting Policy Elections Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statements of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statements of operations in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases”
Other Assets	Other Assets Other assets at December 31, 2019 include $62.0 million of marketable securities held in our deferred compensation plans and $9.6 million of other investments including surface acreage. Other assets at December 31, 2018 include $57.3 million of marketable securities held in our deferred compensation plans and $9.1 million of other investments, including surface acreage.
Stock-based Compensation Arrangements	Stock-based Compensation Arrangements We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 12.
Derivative Financial Instruments	Derivative Financial Instruments All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. All realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of operations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We also have collars which establish a minimum floor price and a predetermined ceiling price. We also have entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. Beginning in third quarter 2017, we entered into combined natural gas derivative instruments containing a fixed price swap and a sold option to extend the term or expand the volume (which we refer to as a swaption). The swap price is a fixed price determined at the time of the swaption contract. If the option is exercised, the contract will become a swap treated consistently with our fixed-price swaps. For additional information regarding our derivatives, see Note 10. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. During 2019, we did not materially modify any existing derivative contracts.
Concentrations of Credit Risk	Concentrations of Credit Risk As of December 31, 2019, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. The nature of our customer’s businesses may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. We do not anticipate a material impact on our financial results due to non-performance by third parties. For the years ended December 31, 2019, 2018 and 2017, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production. We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set-off receivables owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative contracts have a margin requirement or collateral provision that would require us to fund or post additional collateral prior to the scheduled cash settlement date. At December 31, 2019, our derivative counterparties included twenty financial institutions and commodity traders, of which all but three are secured lenders in our bank credit facility. At December 31, 2019, our net derivative liability includes a payable to the counterparties not included in our bank credit facility totaling $6.7 million, which includes a payable to one counterparty of $12.6 million and a receivable from the remaining two counterparties of $5.9 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set-off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance.
Asset Retirement Obligations	Asset Retirement Obligations The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future and federal and state regulatory requirements. We are required to operate and maintain our natural gas pipeline systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, these assets have indeterminate lives. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 9 for additional information.
Contingencies	Contingencies We are subject to legal proceedings, claims, and liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 15 for a more detailed discussion regarding our contingencies.
Environmental Costs	Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed.
Deferred Taxes	Deferred Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors may include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. All deferred taxes are classified as long-term on the balance sheets.
Treasury Stock	Treasury Stock Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
Accounting Standards	Recently Adopted Lease Accounting Standard In February 2016, an accounting standards update was issued that requires an entity to recognize a ROU asset and lease liability for all leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also required certain quantitative and qualitative disclosures about leasing arrangements. The new standard was effective for us in first quarter 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application effective on January 1, 2019. Consequently, upon transition, we recognized a ROU asset (or operating lease right-of-use asset) and a lease liability with no retained earnings impact. We are applying the following practical expedients as provided in the standards update which provide elections to: • not apply the recognition requirements 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); • not reassess whether a contract contains a lease, lease classification and initial direct costs; and • not reassess certain land easements in existence prior to January 1, 2019. Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standards update. Our adoption did not have a material impact on our consolidated balance sheet as of January 1, 2019, with the primary impact relating to the recognition of ROU assets and operating lease liabilities for operating leases which represents approximately a 1% change to total assets and total liabilities. The impact of adoption of this new standards update was as follows (in thousands): January 1, 2019 Adoption Reclassification (1) Total Adjustment Balance Sheet: Operating lease right-of-use assets $ 59,300 $ (7,925 ) $ 51,375 Accrued liabilities – current $ (14,811 ) $ — $ (14,811 ) Operating lease liabilities – long-term $ (44,489 ) $ — $ (44,489 ) Asset retirement obligations and other liabilities $ — $ 7,925 $ 7,925 (1) Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity. Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of the standards update. Pension Accounting Standard In March 2017, an accounting standards update was issued which provides additional guidance on the presentation of net benefit cost in the statement of operations. Employers are to present the service cost component of net periodic benefit cost in the same consolidated results of operations line item as other employee compensation costs arising from services rendered during the period. This new standards update was effective for annual reporting periods in first quarter 2018 and must be applied retrospectively. We adopted this standards update in first quarter 2018. The adoption did not impact our consolidated results of operations, financial position, cash flows or disclosures. We had no service cost recorded prior to 2018 due to the implementation of our post retirement benefit plan at the end of 2017. In 2019 and 2018, our service cost is recorded in general and administrative expense. Modification of Share – Based Awards In May 2017, an accounting standards update was issued which clarifies what constitutes a modification of a share-based award. This standards update was intended to provide clarity and reduce both diversity in practice and cost and complexity to a change to the terms or conditions of a share-based payment award. We adopted this standards update in first quarter 2018. The adoption of this standard did not have a material impact on our consolidated results of operations, financial position, cash flows or disclosures. Revenue Recognition Standard In May 2014, an accounting standards update was issued that superseded the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. This standard was effective for us in first quarter 2018 and we adopted the new standards update using the modified retrospective method to all open contracts as of January 1, 2018. Our implementation of this standard did not result in a cumulative-effect adjustment on date of adoption; however, our financial statement presentation related to revenue received from certain gas processing contracts changed. Based on previous accounting guidance, certain of our gas processing contracts were reported in revenue at a net price (net of processing costs) we receive. Upon adoption of this accounting standards update, these contracts are now reported as a gross price received at a delivery point and separate transportation, marketing and processing expense. Not Yet Adopted Financial Instruments – Credit Losses In June 2016, an accounting standards update was issued that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standards update requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standards update is effective for us in first quarter 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. We have evaluated the provisions of this accounting standards update and are assessing the impact, if any, it may have on our consolidated results of operations, financial position and financial disclosures. From the evaluation of our current credit portfolio, which includes receivables for commodity sales, joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoption of this standard will have a material impact on our financial statements. Fair Value Measurement In August 2018, an accounting standards update was issued which provides additional disclosure requirements for fair value measurements. This new standards update eliminates the requirement to disclose transfers between Level 1 and Level 2 of the fair value hierarchy and provides for additional disclosures for Level 3 fair value measurements. This new standards update is effective for us in first quarter 2020 and will be adopted on a prospective or retrospective basis depending on the changes that apply. We do not believe adoption of this standard will have a material impact on our financial disclosures.

Accounting Standards (Tables)

Accounting Standards (Tables)	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements And Changes In Accounting Principles [Abstract]
Schedule of Impact of Adoption of New Lease Accounting Standard	The impact of adoption of this new standards update was as follows (in thousands): January 1, 2019 Adoption Reclassification (1) Total Adjustment Balance Sheet: Operating lease right-of-use assets $ 59,300 $ (7,925 ) $ 51,375 Accrued liabilities – current $ (14,811 ) $ — $ (14,811 ) Operating lease liabilities – long-term $ (44,489 ) $ — $ (44,489 ) Asset retirement obligations and other liabilities $ — $ 7,925 $ 7,925 (1)

Revenues from Contracts with _2

Revenues from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue From Contract With Customer [Abstract]
Disaggregation of Revenue by Identified Revenue Stream	Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands): Year Ended December 31, 2019 2018 Natural gas sales $ 1,388,838 $ 1,663,832 NGLs sales 681,134 931,360 Oil sales 185,453 255,885 Total natural gas, NGLs and oil sales 2,255,425 2,851,077 Sales of purchased natural gas 332,006 459,634 Sales of purchased NGLs 1,661 9,017 Other marketing revenue 11,842 14,109 Total $ 2,600,934 $ 3,333,837

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax	Our income tax benefit was $500.3 million for the year ended December 31, 2019 compared to $30.5 million in 2018 and $251.0 million in 2017. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % Federal rate change — — (406.7 ) State 3.8 (0.3 ) (0.7 ) State rate and law change 1.8 0.9 (1.3 ) Non-deductible executive compensation — — 0.7 Valuation allowances (3.8 ) (0.4 ) 36.8 Equity compensation (0.2 ) (0.1 ) 30.2 Goodwill impairment — (19.4 ) — Other — — 0.3 Consolidated effective tax rate 22.6 % 1.7 % (305.7 %)
Income Tax (Benefit) Expense Attributable to (Loss) Income Before Income Taxes	Income tax (benefit) expense attributable to (loss) income before income taxes consists of the following (in thousands): 2019 2018 2017 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ (434,585 ) $ (434,585 ) $ — $ (25,322 ) $ (25,322 ) $ — $ (302,507 ) $ (302,507 ) U.S. state and local 6,147 (71,853 ) (65,706 ) — (5,167 ) (5,167 ) 17 51,464 51,481 Total $ 6,147 $ (506,438 ) $ (500,291 ) $ — $ (30,489 ) $ (30,489 ) $ 17 $ (251,043 ) $ (251,026 )
Significant Components of Deferred Tax Assets and Liabilities	Significant components of deferred tax assets and liabilities are as follows: December 31, 2019 2018 (in thousands) Deferred tax assets: Net operating loss carryforward $ 581,324 $ 542,847 Deferred compensation 16,815 19,844 Equity compensation 7,188 8,152 AMT credits and other credits — 3,296 Asset retirement obligation 60,064 78,126 Interest expense carryover 18,035 19,444 Lease deferred tax assets 16,450 — Other 11,072 11,048 Valuation allowances: Federal (32,530 ) (18,975 ) State, net of federal benefit (158,296 ) (101,372 ) Total deferred tax assets 520,122 562,410 Deferred tax liabilities: Depreciation and depletion (639,581 ) (1,207,784 ) Cumulative mark-to-market gain (25,957 ) (21,294 ) Lease deferred tax liabilities (14,780 ) — Total deferred tax liabilities (680,318 ) (1,229,078 ) Net deferred tax liability $ (160,196 ) $ (666,668 )
Changes in Deferred Tax Asset Valuation Allowances	The changes in our deferred tax asset valuation allowances are as follows (in thousands): 2019 2018 2017 Balance at the beginning of the year $ (120,347 ) $ (125,134 ) $ (107,174 ) Charged to provision for income taxes: State net operating loss carryforwards (25,710 ) (23,926 ) (11,612 ) Federal net operating loss carryforwards 13,780 11,716 15,385 Non-recoverable deferred tax assets (28,208 ) — — Other state valuation allowances (31,214 ) 16,380 (23,790 ) Other federal valuation allowances 346 494 (247 ) Other 527 123 2,304 Balance at the end of the year $ (190,826 ) $ (120,347 ) $ (125,134 )

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Computations of Basic and Diluted Income (Loss) Per Common Share	Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common stockholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Diluted net income (loss) per share is calculated under both the two class method and the treasury stock method and the more dilutive of the two calculations is presented. The following table sets forth a reconciliation of net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts): Year Ended December 31, 2019 2018 2017 Net (loss) income, as reported $ (1,716,297 ) $ (1,746,481 ) $ 333,146 Participating basic earnings (a) (251 ) (245 ) (3,751 ) Basic net (loss) income attributed to common stockholders (1,716,548 ) (1,746,726 ) 329,395 Reallocation of participating earnings (a) — — 5 Diluted net (loss) income attributed to common stockholders $ (1,716,548 ) $ (1,746,726 ) $ 329,400 Net (loss) income per common share: Basic $ (6.92 ) $ (7.10 ) $ 1.34 Diluted $ (6.92 ) $ (7.10 ) $ 1.34 (a) Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.
Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding	The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands): Year Ended December 31, 2019 2018 2017 Denominator: Weighted average common shares outstanding – basic 247,970 246,171 245,091 Effect of dilutive securities: Director and employee restricted stock and performance-based equity awards — — 367 Weighted average common shares outstanding – diluted 247,970 246,171 245,458

Indebtedness (Tables)

Indebtedness (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt Outstanding	We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at December 31, 2019 is shown parenthetically). The expenses of issuing debt are capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized during 2019, 2018, and 2017. December 31, 2019 December 31, 2018 Bank debt (3.0%) $ 477,000 $ 943,000 Senior notes 4.875% senior notes due 2025 750,000 750,000 5.00% senior notes due 2023 741,531 741,531 5.00% senior notes due 2022 511,886 580,032 5.75% senior notes due 2021 374,139 475,952 5.875% senior notes due 2022 297,617 329,244 Other senior notes due 2022 590 590 Total senior notes 2,675,763 2,877,349 Senior subordinated notes 5.00% senior subordinated notes due 2023 7,712 7,712 5.00% senior subordinated notes due 2022 19,054 19,054 5.75% senior subordinated notes due 2021 22,214 22,214 Total senior subordinated notes 48,980 48,980 Total debt 3,201,743 3,869,329 Unamortized premium 3,013 4,741 Unamortized debt issuance costs (31,819 ) (37,209 ) Total debt (net of debt issuance costs) $ 3,172,937 $ 3,836,861
Schedule for Long-Term Debt Outstanding	The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2019 (in thousands): Year Ended 2020 $ — 2021 396,353 2022 829,147 2023 1,226,243 2024 — Thereafter 750,000 $ 3,201,743

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2019 and 2018 (in thousands): 2019 2018 Beginning of period $ 312,754 $ 276,855 Liabilities incurred 4,063 3,376 Acquisitions — 13,438 Liabilities settled (5,953 ) (5,052 ) Disposition of wells (82,576 ) (13,332 ) Accretion expense 15,658 25,456 Change in estimate 7,130 12,013 End of period 251,076 312,754 Less current portion (2,393 ) (5,485 ) Long-term asset retirement obligations (a) $ 248,683 $ 307,269 (a)

Derivative Activities (Tables)

Derivative Activities (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Volumes Hedged and Average Hedge Prices	The following table sets forth the derivative volumes by year as of December 31, 2019, excluding our basis and freight swaps which are discussed separately below: Period Contract Type Volume Hedged Weighted Natural Gas 2020 Swaps 1,000,984 Mmbtu/day $ 2.64 (1) 2021 Swaps 50,000 Mmbtu/day $ 2.62 (1) Crude Oil 2020 Swaps 7,995 bbls/day $ 58.27 (1) 2021 Swaps 1,000 bbls/day $ 55.00 (1) April-September, 2020 Calls 500 bbls/day $ 59.00 NGLs (NC4-Normal Butane) January-March, 2020 Swaps 659 bbls/day $ 0.73/gallon NGLs (C5-Natural Gasoline) January-March, 2020 Swaps 4,297 bbls/day $ 1.21/gallon (1)
Combined Fair Value of Derivatives, by Consolidated Balance Sheets	The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2019 and 2018 is summarized below (in thousands). As of December 31, 2019, we are conducting derivative activities with twenty counterparties, of which all but three are secured lenders in our bank credit facility. We believe all of these counterparties are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. December 31, 2019 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 134,364 $ (2,913 ) $ 131,451 –swaptions — (1,325 ) (1,325 ) –basis swaps 10,766 (1,092 ) 9,674 Crude oil –swaps 3,893 (4,794 ) (901 ) –swaptions — (1,597 ) (1,597 ) –calls — (349 ) (349 ) NGLs –C3 propane spread swaps 1,913 (1,913 ) — –NC4 butane swaps 167 — 167 –C5 natural gasoline swaps 60 (127 ) (67 ) Freight –swaps 1,529 (1,028 ) 501 $ 152,692 $ (15,138 ) $ 137,554 December 31, 2019 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (1,657 ) $ 2,913 $ 1,256 –swaptions (2,594 ) 1,325 (1,269 ) –basis swaps (1,371 ) 1,092 (279 ) Crude oil –swaps (4,814 ) 4,794 (20 ) –swaptions (2,254 ) 1,597 (657 ) –calls (349 ) 349 — NGLs –C3 propane spread swaps (16,040 ) 1,913 (14,127 ) –C5 natural gasoline swaps (127 ) 127 — Freight –swaps — 1,028 1,028 $ (29,206 ) $ 15,138 $ (14,068 ) December 31, 2018 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 20,834 $ (11,748 ) $ 9,086 –swaptions 5,200 (3,883 ) 1,317 –basis swaps 6,468 (2,822 ) 3,646 Crude oil –swaps 26,481 (651 ) 25,830 –collars 5,945 (707 ) 5,238 NGLs –C3 propane swaps 18,719 (589 ) 18,130 –C3 propane collars 8,538 — 8,538 –C3 propane spread swaps 8,984 (8,868 ) 116 –NC4 butane swaps 4,084 — 4,084 –C5 natural gasoline swaps 17,371 — 17,371 Freight –swaps — (561 ) (561 ) $ 122,624 $ (29,829 ) $ 92,795 December 31, 2018 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (18,332 ) $ 11,748 $ (6,584 ) –swaptions (7,972 ) 3,883 (4,089 ) –basis swaps (1,702 ) 2,822 1,120 Crude oil –swaps — 651 651 –collars — 707 707 NGLs –C3 propane swaps — 589 589 –C3 propane spread swaps (8,868 ) 8,868 — Freight –swaps (561 ) 561 — $ (37,435 ) $ 29,829 $ (7,606 )
Effects of Derivatives on Consolidated Statements of Operations	The effects of our derivatives on our consolidated statements of operations for the last three years are summarized below (in thousands). Year Ended December 31, Derivative Fair Value (Loss) Income 2019 2018 2017 Commodity swaps $ 219,968 $ (57,950 ) $ 181,095 Swaptions 333 (6,556 ) 6,534 Collars (3,903 ) 17,583 18,132 Basis swaps 6,661 (1,104 ) (4,647 ) Puts — — 10,929 Calls (349 ) (2,653 ) 987 Freight swaps 3,971 (512 ) 320 Total $ 226,681 $ (51,192 ) $ 213,350

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value	We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands): Fair Value Measurements at December 31, 2019 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 62,009 $ — $ — $ 62,009 Derivatives –swaps — 131,886 — 131,886 –calls — (349 ) — (349 ) –basis swaps — (4,732 ) — (4,732 ) –freight swaps — 1,529 — 1,529 –swaptions — — (4,848 ) (4,848 ) Fair Value Measurements at December 31, 2018 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 57,293 $ — $ — $ 57,293 Derivatives –swaps — 69,156 — 69,156 –collars — 5,945 8,538 14,483 –basis swaps — 4,883 — 4,883 –freight swaps — (561 ) — (561 ) –swaptions — — (2,772 ) (2,772 )
Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy	The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Year Ended December 31, 2019 Balance at the beginning of period $ 5,766 Total gains (losses): Included in earnings — Settlements received (7,692 ) Transfers in and/or out of Level 3 (2,922 ) Balance at end of period $ (4,848 )
Value of Assets Measured at Fair Value on Nonrecurring Basis	The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands): Year Ended December 31, 2019 2018 2017 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ 370,500 $ 1,093,531 $ 32,516 $ 22,614 $ 85,597 $ 63,679
Carrying Amounts and Fair Values of Financial Instruments	The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2019 and 2018 (in thousands): December 31, 2019 December 31, 2018 Carrying Fair Carrying Fair Assets: Commodity swaps, options and basis swaps $ 137,554 $ 137,554 $ 92,795 $ 92,795 Marketable securities (a) 62,009 62,009 57,293 57,293 (Liabilities): Commodity swaps, options and basis swaps (14,068 ) (14,068 ) (7,606 ) (7,606 ) Bank credit facility (b) (477,000 ) (477,000 ) (943,000 ) (943,000 ) 5.75% senior notes due 2021 (b) (374,139 ) (375,909 ) (475,952 ) (455,972 ) 5.00% senior notes due 2022 (b) (511,886 ) (501,582 ) (580,032 ) (519,343 ) 5.875% senior notes due 2022 (b) (297,617 ) (294,757 ) (329,244 ) (305,989 ) Other senior notes due 2022 (b) (590 ) (592 ) (590 ) (581 ) 5.00% senior notes due 2023 (b) (741,531 ) (683,291 ) (741,531 ) (654,683 ) 4.875% senior notes due 2025 (b) (750,000 ) (645,098 ) (750,000 ) (616,313 ) 5.75% senior subordinated notes due 2021 (b) (22,214 ) (21,539 ) (22,214 ) (21,638 ) 5.00% senior subordinated notes due 2022 (b) (19,054 ) (17,011 ) (19,054 ) (17,072 ) 5.00% senior subordinated notes due 2023 (b) (7,712 ) (7,654 ) (7,712 ) (6,690 ) Deferred compensation plan (c) (74,472 ) (74,472 ) (80,092 ) (80,092 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges. (b) The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs. (c) The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input.

Stock-based Compensation Plans

Stock-based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Allocation of Stock-Based Compensation by Functional Category	The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2019 (in thousands): 2019 2018 2017 (1) Direct operating expense $ 1,928 $ 2,109 $ 2,060 Brokered natural gas and marketing expense 1,856 1,452 1,437 Exploration expense 1,566 1,921 2,742 General and administrative expense 35,061 43,806 74,873 Termination costs 1,971 — 1,664 Total $ 42,382 $ 49,288 $ 82,776 (1) Includes $30.8 million accelerated vesting of equity grants.
Restricted Stock and Restricted Stock Units Outstanding	The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2019: Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2016 765,971 $ 33.62 425,018 $ 43.48 Granted 888,326 32.61 543,438 25.91 Vested (698,563 ) 34.82 (908,912 ) 33.71 Forfeited (122,676 ) 32.91 (4,342 ) 31.10 Outstanding at December 31, 2017 833,058 31.64 55,202 32.26 Granted 1,834,883 16.98 891,350 15.30 Vested (1,037,501 ) 23.57 (738,073 ) 16.34 Forfeited (244,352 ) 21.59 (23,900 ) 19.76 Outstanding at December 31, 2018 1,386,088 20.04 184,579 15.65 Granted 2,792,438 10.59 1,214,038 10.16 Vested (1,608,075 ) 15.72 (987,491 ) 10.86 Forfeited (568,212 ) 13.03 — — Outstanding at December 31, 2019 2,002,239 $ 12.32 411,126 $ 10.94
Schedule of Share Based Payment Award TSR - Performance Stock Awards Valuation Assumptions	The following assumptions were used to estimate the fair value of the TSR-PSUs granted during the years ended December 31, 2019, 2018 and 2017: Year Ended December 31, 2019 2019 2018 2017 Risk-free interest rate 2.44 % 2.42 % 1.49 % Expected annual volatility 46 % 48 % 44 % Grant date fair value per unit $ 11.34 $ 18.51 $ 26.26
Summary of Change in Post Retirement Benefit Obligation	The change in our post-retirement benefit obligation is as follows (in thousands): Change in Benefit Obligation: Benefit obligation at beginning of year $ 1,355 $ 1,769 Prior service cost — — Service cost 88 94 Interest cost 68 58 Actuarial loss (gain) 532 (526 ) Benefits paid (86 ) (40 ) Benefit obligation at end of year $ 1,957 $ 1,355 Amounts recognized in the consolidated balance sheet: Long-term liabilities $ 1,957 $ 1,355 Components of Net Periodic Post Retirement Benefit Cost: Service cost $ 88 $ 94 Interest cost 68 58 Amortization of prior service cost 369 369 Net periodic post retirement costs (recognized in general and administrative expense) $ 525 $ Other Changes in Benefit Obligations in Other Comprehensive Income (Loss): Net loss (gain) $ 532 $ (526 ) Prior service cost — — Amortization of prior service cost (369 ) (369 ) Total recognized in other comprehensive income (loss) $ 163 $ (895 ) Total recognized in net periodic benefit cost and other comprehensive income (loss) $ 688 $ (374 )
Summary of Assumptions Used to Determine Benefit Obligation	The following summarizes the assumptions used to determine the benefit obligation at December 31, 2019 and 2018: December 31, 2019 December 31, 2018 Weighted average assumptions used to determine benefit obligation: Discount rate 2.9 % 4.0 % Assumed weighted average healthcare cost trend rates: Initial healthcare trend rate 6.5 % 6.5 % Ultimate trend rate 4.5 % 5.0 % Year ultimate trend rate reached 2023 2028
Performance-based PG-PSUs and RG-PSUs
Summary of Non-Vested Awards Activities	The following is a summary of our non-vested PG/RG-PSUs awards outstanding at December Number of Weighted Outstanding at December 31, 2016 — $ — Units granted 122,921 25.53 Outstanding at December 31, 2017 122,921 25.53 Units granted ( a ) 440,938 15.22 Forfeited (b) (27,061 ) 23.03 Outstanding at December 31, 2018 536,798 15.61 Units granted (a) 345,202 10.32 Forfeited (427 ) 15.65 Outstanding at December 31, 2019 881,573 $ 11.70 (a) (b) first
Performance Based TSR - PSUs
Summary of Non-Vested Awards Activities	The following is a summary of our non-vested TSR – Weighted Outstanding at December 31, 2016 871,299 $ 55.29 Granted (a) 358,519 26.26 Vested and issued (b) (85,461 ) 86.23 Forfeited (134,515 ) 85.24 Outstanding at December 31, 2017 1,009,842 38.38 Granted (a) 329,486 18.51 Vested and issued (c) (73,985 ) 56.81 Forfeited (197,457 ) 55.46 Outstanding at December 31, 2018 1,067,886 27.81 Granted (a) 314,152 11.34 Vested and issued (d) (12,283 ) 30.47 Forfeited (376,303 ) 37.25 Outstanding at December 31, 2019 993,452 $ 19.00 (a) These (b ) th th (c) th th (d) th

Capital Stock (Tables)

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Schedule of Changes in Number of Common Shares Outstanding	The following is a schedule of changes in the number of common shares outstanding since the beginning of 2017: Year Ended December 31, 2019 2018 2017 Beginning balance 249,510,022 248,129,430 247,144,356 Restricted stock grants 1,186,290 865,095 539,096 Restricted stock units vested 720,212 434,046 344,937 Performance stock units issued 12,747 76,149 85,461 Treasury shares (1,798,468 ) 5,302 15,580 Ending balance 249,630,803 249,510,022 248,129,430
Schedule of Change in Treasury Shares	The following is a schedule of change in treasury shares since the beginning of 2017: Year Ended December 31, 2019 2018 2017 Beginning balance 9,665 14,967 30,547 Rabbi trust shares distributed and/or sold (1,532 ) (5,302 ) (15,580 ) Shares repurchased 1,800,000 — — Ending balance 1,808,133 9,665 14,967

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Year Ended December 31, 2019 2018 2017 (in thousands) Net cash provided from operating activities included: Income taxes refunded from taxing authorities $ — $ 7,521 $ 1,024 Interest paid (189,443 ) (207,433 ) (179,431 ) Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 11,193 $ 28,826 $ 20,245 (Decrease) increase in accrued capital expenditures (20,104 ) (119,021 ) 71,739

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments And Contingencies Disclosure [Abstract]
Schedule of Components of Lease Expense	The components of our total lease expense for the year ended December 31, 2019, the majority of which is included in general and administrative expense, are as follows (in thousands): Year Ended December 31, 2019 Operating lease cost $ 15,536 Variable lease expense (1) 6,916 Short-term lease expense (2) 2,965 Sublease income (3,496 ) Total lease expense $ 21,921 Short-term lease costs (3) $ 29,126 ( 1) Variable lease payments that are not dependent on an index or rate are not included in the lease liability or ROU assets. (2) Short-term lease expense represents expense related to leases with a contract term of one year or less. (3) These short-term lease costs are related to leases with a contract term of one year or less and the majority of which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our consolidated balance sheets and may fluctuate based on the number of drilling rigs being utilized.
Supplemental Cash Flow Information Related to Operating Leases	Supplemental cash flow information related to our operating leases is included in the table below (in thousands): Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities $ 18,700 ROU assets added in exchange for lease obligations (since adoption) $ 24,839
Supplemental Balance Sheet Information Related to Operating Leases	Supplemental balance sheet information related to our operating leases is included in the table below (in thousands): December 31, 2019 Operating lease ROU assets $ 62,053 Accrued liabilities – current $ (27,856 ) Operating lease liabilities – long-term $ (41,068 )
Schedule of Weighted Average Remaining Lease Term and Weighted Average Discount Rate for Operating Leases	Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows: December 31, 2019 Weighted average remaining lease term 4.6 years Weighted average discount rate 6.0%
Schedule of Lease Liabilities with Enforceable Contract Terms are Greater Than One year Mature	Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating Leases 2020 $ 31,245 2021 14,252 2022 7,023 2023 6,500 2024 6,468 Thereafter 15,262 Total lease payments 80,750 Less effects of discounting (11,826 ) Total lease liability $ 68,924
Schedule of Future Minimum Transportation Fees Due	We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production from our properties in Pennsylvania and North Louisiana. Under these contracts, we are obligated to transport, process or gather minimum daily natural gas volumes, or pay for any deficiencies at a specified reservation fee rate. In some cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. See Note 11 for additional information regarding deficiencies in North Louisiana. As of December 31, 2019, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands): Transportation, (a) 2020 $ 945,392 2021 949,126 2022 905,920 2023 870,062 2024 853,457 Thereafter 5,154,987 $ 9,678,944 (a)
Future Delivery Commitments	We have various volume delivery commitments that are related to our Marcellus Shale and North Louisiana areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2019, our delivery commitments through 2031 were as follows: Year Ending December 31, Natural Gas Ethane and Propane (bbls per day) 2020 528,607 81,000 2021 491,313 65,932 2022 370,179 43,000 2023 167,970 35,000 2024-2028 100,000 35,000 2029 100,000 20,000 2030-2031 — 20,000

Termination Costs (Tables)

Termination Costs (Tables)	12 Months Ended
	Dec. 31, 2019
Restructuring And Related Activities [Abstract]
Termination Costs Included in Accrued Liabilities in Consolidated Balance Sheet	See Note 15 for information related to an impairment of an office lease. The following table details the accrued liability as of December 31, 2019 and December 31, 2018 (in thousands): 2019 2018 Beginning balance $ — $ 1,855 Accrued severance costs 7,535 (356 ) Accrued building rent — (17 ) Payments (2,843 ) (1,482 ) Ending balance $ 4,692 $ —
Summary of Termination Costs	The following summarizes our termination costs for three years ended December 31, 2019, 2018 and 2017 (in thousands): 2019 2018 2017 Severance costs $ 7,535 $ (356 ) $ 2,176 Building lease — (17 ) (70 ) Stock-based compensation 1,971 — 1,664 Total termination costs $ 9,506 $ (373 ) $ 3,770

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Data [Abstract]
Selected Quarterly Financial Data	The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. Fourth quarter 2019 includes proved and unproved impairment expense of $2.3 billion related to our North Louisiana assets. Fourth quarter 2018 includes goodwill impairment expense of $1.6 billion and unproved impairment expense of $441.8 million related to our North Louisiana assets. 2019 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 671,654 $ 563,579 $ 474,754 $ 545,438 $ 2,255,425 Derivative fair value (loss) income (61,731 ) 195,245 74,676 18,491 226,681 Brokered natural gas, marketing and other 138,214 92,605 73,015 41,675 345,509 Total revenue and other income 748,137 851,429 622,445 605,604 2,827,615 Costs and expenses: Direct operating 33,227 33,981 35,276 33,792 136,276 Transportation, gathering, processing and compression 302,655 301,219 295,912 299,511 1,199,297 Production and ad valorem taxes 11,310 9,889 7,805 8,963 37,967 Brokered natural gas and marketing 132,305 101,117 79,938 46,532 359,892 Exploration 8,211 8,109 11,013 9,350 36,683 Abandonment and impairment of unproved properties 12,659 12,770 16,202 1,193,711 1,235,342 General and administrative 46,638 50,631 41,047 42,793 181,109 Termination costs — 2,206 819 6,481 9,506 Deferred compensation plan 3,581 (11,142 ) (8,871 ) 960 (15,472 ) Interest 51,537 51,727 46,997 44,024 194,285 Gain on early extinguishment of debt — — (2,985 ) (2,430 ) (5,415 ) Depletion, depreciation and amortization 138,718 141,505 137,751 130,869 548,843 Impairment of proved properties and other — — — 1,095,634 1,095,634 Loss (gain) on sale of assets 189 (5,867 ) 36,341 (407 ) 30,256 Total costs and expenses 741,030 696,145 697,245 2,909,783 5,044,203 Income (loss) before income taxes 7,107 155,284 (74,800 ) (2,304,179 ) (2,216,588 ) Income tax expense (benefit): Current — — 4,079 2,068 6,147 Deferred 5,688 40,099 (51,298 ) (500,927 ) (506,438 ) 5,688 40,099 (47,219 ) (498,859 ) (500,291 ) Net income (loss) $ 1,419 $ 115,185 $ (27,581 ) $ (1,805,320 ) $ (1,716,297 ) Net income (loss) per common share: Basic $ 0.01 $ 0.46 $ (0.11 ) $ (7.27 ) $ (6.92 ) Diluted $ 0.01 $ 0.46 $ (0.11 ) $ (7.27 ) $ (6.92 ) 2018 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 696,629 $ 661,390 $ 736,431 $ 756,627 $ 2,851,077 Derivative fair value (loss) income (14,009 ) (103,290 ) (34,591 ) 100,698 (51,192 ) Brokered natural gas, marketing and other 59,979 98,084 109,385 215,312 482,760 Total revenue and other income 742,599 656,184 811,225 1,072,637 3,282,645 Costs and expenses: Direct operating 38,122 35,088 30,926 35,395 139,531 Transportation, gathering, processing and compression 244,628 269,910 304,562 298,716 1,117,816 Production and ad valorem taxes 9,926 10,140 9,427 16,656 46,149 Brokered natural gas and marketing 55,594 102,747 116,080 221,626 496,047 Exploration 7,719 7,499 8,299 10,600 34,117 Abandonment and impairment of unproved properties 11,773 54,922 6,549 441,750 514,994 General and administrative 68,417 47,583 43,722 50,090 209,812 Termination costs (37 ) — (336 ) — (373 ) Deferred compensation plan (7,397 ) 6,615 223 (18,072 ) (18,631 ) Interest 52,385 53,862 54,801 49,161 210,209 Depletion, depreciation and amortization 162,266 161,026 164,266 147,909 635,467 Impairment of proved properties and other 7,312 15,302 — — 22,614 Impairment of goodwill — — — 1,641,197 1,641,197 (Gain) loss on sale of assets (23 ) (156 ) 30 10,815 10,666 Total costs and expenses 650,685 764,538 738,549 2,905,843 5,059,615 Income (loss) before income taxes 91,914 (108,354 ) 72,676 (1,833,206 ) (1,776,970 ) Income tax expense (benefit): Current — — — — — Deferred 42,676 (28,518 ) 24,137 (68,784 ) (30,489 ) 42,676 (28,518 ) 24,137 (68,784 ) (30,489 ) Net income (loss) $ 49,238 $ (79,836 ) $ 48,539 $ (1,764,422 ) $ (1,746,481 ) Net income (loss) per common share: Basic $ 0.20 $ (0.32 ) $ 0.19 $ (7.15 ) $ (7.10 ) Diluted $ 0.20 $ (0.32 ) $ 0.19 $ (7.15 ) $ (7.10 )

Supplemental Information on N_2

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization	Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2019 2018 2017 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 9,345,557 $ 10,974,929 $ 10,572,453 Unproved properties 868,180 2,110,277 2,644,000 Total 10,213,737 13,085,206 13,216,453 Accumulated depreciation, depletion and amortization (4,172,702 ) (4,062,021 ) (3,649,716 ) Net capitalized costs $ 6,041,035 $ 9,023,185 $ 9,566,737 (a)
Costs Incurred for Property Acquisition, Exploration and Development	Costs Incurred for Property Acquisition, Exploration (a) December 31, 2019 2018 2017 (in thousands) Acquisitions Acreage purchases $ 57,324 $ 62,390 $ 62,075 Oil and gas properties — 1,683 18,269 Development 666,984 834,552 1,177,526 Exploration: Drilling — 1,380 2,030 Expense 35,117 32,196 50,920 Stock-based compensation expense 1,566 1,921 2,742 Gas gathering facilities: Development 3,583 10,218 15,097 Subtotal 764,574 944,340 1,328,659 Asset retirement obligations 11,193 28,826 20,245 Total costs incurred $ 775,767 $ 973,166 $ 1,348,904 (a)
Proved Developed and Undeveloped Reserves	Natural Gas NGLs Crude Oil and Condensate Natural Gas (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: Balance, December 31, 2016 7,870,416 630,066 70,252 12,072,322 Revisions 70,222 83,338 (10,555 ) 506,919 Extensions, discoveries and additions 2,866,103 87,572 15,997 3,487,519 Purchases 7,738 330 66 10,116 Property sales (60,278 ) (2,356 ) (1,121 ) (81,133 ) Production (490,552 ) (35,686 ) (4,785 ) (733,382 ) Balance, December 31, 2017 10,263,649 763,264 69,854 15,262,361 Revisions 178,595 84,993 7,197 731,735 Extensions, discoveries and additions 2,269,427 128,436 17,309 3,143,898 Purchases — — — — Property sales (135,884 ) (16,774 ) (4,276 ) (262,180 ) Production (548,085 ) (38,325 ) (4,228 ) (803,408 ) Balance, December 31, 2018 12,027,702 921,594 85,856 18,072,406 Revisions 33,122 57,311 (12,320 ) 303,068 Extensions, discoveries and additions 959,901 26,505 7,057 1,161,274 Property sales (327,634 ) (28,324 ) (2,371 ) (511,811 ) Production (578,114 ) (38,850 ) (3,690 ) (833,354 ) Balance, December 31, 2019 12,114,977 938,236 74,532 18,191,583 Proved developed reserves: December 31, 2017 5,437,674 448,258 36,808 8,348,074 December 31, 2018 6,451,012 512,318 38,658 9,756,870 December 31, 2019 6,486,211 535,007 34,369 9,902,468 Proved undeveloped reserves: December 31, 2017 4,825,975 315,006 33,046 6,914,287 December 31, 2018 5,576,690 409,276 47,198 8,315,536 December 31, 2019 5,628,766 403,229 40,163 8,289,115 (a) Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.
Changes in Proved Undeveloped Reserves	The following details the changes in proved undeveloped reserves for 2019 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2018 8,315,536 Undeveloped reserves transferred to developed (1,215,684 ) Revisions (a) 265,947 Sales (214,637 ) Extension and discoveries 1,137,953 Ending proved undeveloped reserves at December 31, 2019 8,289,115 (a)
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflows are net of third-party transportation, gathering and compression expense. As of December 31, 2019 2018 (in thousands) Future cash inflows $ 48,718,733 $ 64,287,737 Future costs: Production (23,320,477 ) (25,626,373 ) Development (a) (3,219,349 ) (3,824,936 ) Future net cash flows before income taxes 22,178,907 34,836,428 Future income tax expense (4,179,297 ) (7,285,274 ) Total future net cash flows before 10% discount 17,999,610 27,551,154 10% annual discount (11,371,037 ) (16,435,560 ) Standardized measure of discounted future net cash flows $ 6,628,573 $ 11,115,594 (a)
Changes in Discounted Future Net Cash Flows	The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2019 2018 2017 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ (6,560,107 ) $ 2,959,488 $ 2,615,825 Revisions in quantities (12,741 ) 667,763 445,667 Changes in future development and abandonment costs 104,585 (686,632 ) (814,215 ) Net change in income taxes 1,125,639 (1,075,867 ) (706,531 ) Accretion of discount 1,317,349 814,725 372,743 Purchases of reserves in place — — 6,173 Additions to proved reserves from extensions, discoveries and improved recovery 552,710 2,543,296 2,128,135 Natural gas, NGLs and oil sales, net of production costs (881,883 ) (1,547,580 ) (1,237,970 ) Actual development costs incurred during the period 676,520 851,188 1,202,618 Sales of reserves in place (688,937 ) (226,953 ) (32,946 ) Timing and other (120,156 ) (349,048 ) (266,214 ) Net change for the year (4,487,021 ) 3,950,380 3,713,285 Beginning of year 11,115,594 7,165,214 3,451,929 End of year $ 6,628,573 $ 11,115,594 $ 7,165,214

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)

3 Months Ended

12 Months Ended

Dec. 31, 2019USD ($)

Sep. 30, 2019USD ($)

Jun. 30, 2019USD ($)

Mar. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Sep. 30, 2018USD ($)

Jun. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2019USD ($)CounterpartyCustomer

Dec. 31, 2018USD ($)Customer

Dec. 31, 2017USD ($)Customer

Dec. 31, 2015USD ($)

Summary Of Significant Accounting Policies [Line Items]

Net brokered margin gain (loss)

$ (14,200,000)

$ (16,300,000)

$ (5,700,000)

Allowance for doubtful accounts on accounts receivable

$ 8,784,000

$ 6,118,000

8,784,000

6,118,000

Bad debt (income) expense

4,341,000

(1,000,000)

1,550,000

Net book value of unproved properties

[1]

868,180,000

2,110,277,000

868,180,000

2,110,277,000

2,644,000,000

Abandonment and impairment of unproved properties

1,193,711,000

$ 16,202,000

$ 12,770,000

$ 12,659,000

441,750,000

$ 6,549,000

$ 54,922,000

$ 11,773,000

1,235,342,000

514,994,000

269,725,000

Depreciation expense

$ 5,000,000

6,000,000

$ 7,700,000

Lease, practical expedients, package [true false]

true

Marketable securities held in deferred compensation plans

62,000,000

57,300,000

$ 62,000,000

57,300,000

Other investments including surface acreage

9,600,000

$ 9,100,000

$ 9,600,000

$ 9,100,000

Number of customers accounted more than 10% of total oil and gas revenues | Customer

1

1

1

Number of counterparties | Counterparty

3

Number of financial institutions included in counter parties | Counterparty

20

Number of counterparties amount payable | Counterparty

1

Number of counterparties amount receivable | Counterparty

2

Counterparties not in Facility

Summary Of Significant Accounting Policies [Line Items]

Net derivative liability

6,700,000

$ 6,700,000

One Counterparty

Summary Of Significant Accounting Policies [Line Items]

Net derivative liability

12,600,000

12,600,000

Two Counterparties

Summary Of Significant Accounting Policies [Line Items]

Derivative amount receivable

$ 5,900,000

$ 5,900,000

Maximum

Summary Of Significant Accounting Policies [Line Items]

Short-term leases initial term

1 year

Lessee, operating lease, contract term

1 month

1 month

Pennsylvania

Summary Of Significant Accounting Policies [Line Items]

Net book value of unproved properties

$ 868,200,000

$ 868,200,000

North Louisiana

Summary Of Significant Accounting Policies [Line Items]

Abandonment and impairment of unproved properties

1,200,000,000

$ 436,000,000

Natural Gas and Oil Properties | Northwest Pennsylvania

Summary Of Significant Accounting Policies [Line Items]

Fair Value

$ 0

Adjustments of the asset retirement liability additional expense

$ 213,000

$ 9,800,000

$ 158,000

Other property and equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

3 years

Other property and equipment | Maximum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

10 years

Office Space

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating sublease, option to terminate

All of our subleases have terms that end in 2020 or 2022. The sublease agreements are non-cancelable through the end of the term and both parties have substantive rights to terminate the lease when the term is complete.

Expected subleases through beginning of 2022

$ 3,100,000

$ 3,100,000

Office Space | Minimum

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating lease, contract term

1 year

1 year

Office Space | Maximum

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating lease, contract term

15 years

15 years

Field Equipment

Summary Of Significant Accounting Policies [Line Items]

Lessee, Operating Lease, Option to Extend

Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one to two years and continue thereafter on a month-to-month basis subject to termination by either party with thirty days notice.

Lessee Operating Lease Notice Period for Renewal

30 days

Field Equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating lease, contract term

1 year

1 year

Field Equipment | Maximum

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating lease, contract term

2 years

2 years

Vehicle Fleet

Summary Of Significant Accounting Policies [Line Items]

Lessee Operating Lease Notice Period for Renewal

3 years

Lessee operating lease contract of team description

Our vehicle agreements are non-cancelable for a minimum term of one year and a maximum term of four to eight years depending on the type of vehicle. However, we have assumed a term of three years based on the period covered by options to terminate that we are reasonably certain to exercise.

Vehicle Fleet | Minimum

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating lease, contract term

1 year

1 year

Lessee, operating lease, non-cancelable maximum contract term, depending on type of vehicle

4 years

Vehicle Fleet | Maximum

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating lease, non-cancelable maximum contract term, depending on type of vehicle

8 years

Other Equipment

Summary Of Significant Accounting Policies [Line Items]

Lessee, operating lease, contract term

18 months

18 months

Lessee, Operating Lease, Option to Extend

This arrangement is structured with a non-cancellable primary term of eighteen months, with two optional extension periods of six months

Lessee, operating lease, option to extend

true

Lessee, operating lease, option to extend, term

6 months

Lessee, operating lease, existence of option to terminate

true

[1]

Includes capitalized asset retirement costs and the associated accumulated amortization.

Accounting Standards - Addition

Accounting Standards - Additional Information (Detail)	Jan. 01, 2019
Accounting Standards Update 2016-02
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Impact of lease accounting standard recognition to total assets and total liabilities	1.00%

Accounting Standards - Schedule

Accounting Standards - Schedule of Impact of Adoption of New Lease Accounting Standard (Detail) - USD ($) $ in Thousands		Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operating lease right-of-use assets		$ 62,053		$ 0
Accrued liabilities		356,392		475,848
Operating lease liabilities – long-term		41,068		0
Asset retirement obligations and other liabilities		$ 259,151		$ 319,379
Accounting Standards Update 2016-02
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operating lease right-of-use assets			$ 51,375
Accrued liabilities			(14,811)
Operating lease liabilities – long-term			(44,489)
Asset retirement obligations and other liabilities			7,925
Accounting Standards Update 2016-02 | Before Adoption
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operating lease right-of-use assets			59,300
Accrued liabilities			(14,811)
Operating lease liabilities – long-term			(44,489)
Asset retirement obligations and other liabilities			0
Accounting Standards Update 2016-02 | Reclassification
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operating lease right-of-use assets	[1]		(7,925)
Accrued liabilities	[1]		0
Operating lease liabilities – long-term	[1]		0
Asset retirement obligations and other liabilities	[1]		$ 7,925
[1]	As of December 31, 2018, we had $7.9 million of operating lease liabilities recorded as part of purchase price accounting for building leases acquired because we did not expect to occupy the space or receive payments from our subleases. Lease incentives related to other buildings were also included. Upon adoption of the new standards update, these leases were included as part of our adoption. The ROU asset is reduced because we do not expect to use the asset.

Accounting Standards - Schedu_2

Accounting Standards - Schedule of Impact of Adoption of New Lease Accounting Standard (Parenthetical) (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operating lease liabilities	$ 68,924
Accounting Standards Update 2016-02
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operating lease liabilities		$ 7,900

Dispositions - Additional Infor

Dispositions - Additional Information (Detail)	3 Months Ended									12 Months Ended
	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)a	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets	$ 407,000	$ (36,341,000)	$ 5,867,000	$ (189,000)	$ (10,815,000)	$ (30,000)	$ 156,000	$ 23,000		$ (30,256,000)	$ (10,666,000)	$ 23,716,000
Miscellaneous Proved, Unproved Properties and Surface Acreage
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets										337,000	(448,000)	870,000
Proceeds from sale of oil and gas properties										$ 938,000	$ 1,200,000	1,300,000
Northern Oklahoma
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets						(39,000)
Proceeds from sale of oil and gas properties						$ 23,300,000
Texas Panhandle Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets									$ (989,000)
Proceeds from sale of oil and gas properties									$ 40,400,000
Western Oklahoma Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets												23,800,000
Proceeds from sale of oil and gas properties												$ 30,800,000
Pennsylvania
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets		$ (36,500,000)	5,900,000		$ (10,200,000)
Percentage of royalty disposed		2.50%			1.00%						1.00%
Proceeds from sale of oil and gas properties		$ 750,000,000	$ 34,000,000		$ 300,000,000
Pennsylvania | Natural Gas and Oil Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Number of acres sold | a			20,000

Revenues from Contracts with _3

Revenues from Contracts with Customers - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)Stream	Dec. 31, 2018USD ($)
Disaggregation of Revenue [Line Items]
Number of revenue streams | Stream	3
Revenue Contract with Customer
Disaggregation of Revenue [Line Items]
Accounts receivable | $	$ 237	$ 438.3

Revenues from Contracts with _4

Revenues from Contracts with Customers - Disaggregation of Revenue by Identified Revenue Stream (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Total Revenue									$ 2,600,934	$ 3,333,837
Natural Gas, NGLs and Oil Sales
Disaggregation of Revenue [Line Items]
Total Revenue	$ 545,438	$ 474,754	$ 563,579	$ 671,654	$ 756,627	$ 736,431	$ 661,390	$ 696,629	2,255,425	2,851,077	$ 2,176,287
Natural Gas, NGLs and Oil Sales | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue									1,388,838	1,663,832
Natural Gas, NGLs and Oil Sales | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue									681,134	931,360
Natural Gas, NGLs and Oil Sales | Oil sales
Disaggregation of Revenue [Line Items]
Total Revenue									185,453	255,885
Brokered Natural Gas, Marketing and Other
Disaggregation of Revenue [Line Items]
Total Revenue	$ 41,675	$ 73,015	$ 92,605	$ 138,214	$ 215,312	$ 109,385	$ 98,084	$ 59,979	345,509	482,760	$ 221,393
Brokered Natural Gas, Marketing and Other | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue									332,006	459,634
Brokered Natural Gas, Marketing and Other | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue									1,661	9,017
Brokered Natural Gas, Marketing and Other | Other marketing revenue
Disaggregation of Revenue [Line Items]
Total Revenue									$ 11,842	$ 14,109

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Income tax benefit	$ (498,859,000)	$ (47,219,000)	$ 40,099,000	$ 5,688,000	$ (68,784,000)	$ 24,137,000	$ (28,518,000)	$ 42,676,000	$ (500,291,000)	$ (30,489,000)	$ (251,026,000)
Deferred tax liabilities	160,196,000				666,668,000				160,196,000	666,668,000
Accrued interest or penalties related to tax amounts	0								$ 0
Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2020
Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2037
State
Income Taxes [Line Items]
Valuation allowances	158,296,000				101,372,000				$ 158,296,000	101,372,000
Federal
Income Taxes [Line Items]
Valuation allowances	32,530,000				$ 18,975,000				32,530,000	$ 18,975,000
Federal and State
Income Taxes [Line Items]
Net operating loss carryforwards	2,100,000,000								2,100,000,000
Net operating loss carryforward subject to expiration	1,400,000,000								1,400,000,000
Net operating loss carryforward not subject to expiration	712,800,000								712,800,000
Pennsylvania
Income Taxes [Line Items]
Net operating loss carryforwards	856,300,000								$ 856,300,000
Pennsylvania | Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2027
Pennsylvania | Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2038
Louisiana
Income Taxes [Line Items]
Net operating loss carryforwards	$ 561,100,000								$ 561,100,000
Louisiana | Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2034
Louisiana | Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2039

Income Taxes - Reconciliation B

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effective Income Tax Rate Continuing Operations Tax Rate Reconciliation [Abstract]
Federal statutory tax rate	21.00%	21.00%	35.00%
Federal rate change	0.00%	0.00%	(406.70%)
State	3.80%	(0.30%)	(0.70%)
State rate and law change	1.80%	0.90%	(1.30%)
Non-deductible executive compensation	0.00%	0.00%	0.70%
Valuation allowances	(3.80%)	(0.40%)	36.80%
Equity compensation	(0.20%)	(0.10%)	30.20%
Goodwill impairment	0.00%	(19.40%)	0.00%
Other	0.00%	0.00%	0.30%
Consolidated effective tax rate	22.60%	1.70%	(305.70%)

Income Taxes - Income Tax (Bene

Income Taxes - Income Tax (Benefit) Expense Attributable to (Loss) Income Before Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Components Of Income Tax Expense Benefit Continuing Operations [Abstract]
U.S. federal, Current									$ 0	$ 0	$ 0
U.S. state and local, Current									6,147	0	17
Total, Current	$ 2,068	$ 4,079	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	6,147	0	17
U.S. federal, Deferred									(434,585)	(25,322)	(302,507)
U.S. state and local, Deferred									(71,853)	(5,167)	51,464
Total, Deferred	(500,927)	(51,298)	40,099	5,688	(68,784)	24,137	(28,518)	42,676	(506,438)	(30,489)	(251,043)
U.S. federal, Total									(434,585)	(25,322)	(302,507)
U.S. state and local, Total									(65,706)	(5,167)	51,481
Total (benefit) expense for income taxes	$ (498,859)	$ (47,219)	$ 40,099	$ 5,688	$ (68,784)	$ 24,137	$ (28,518)	$ 42,676	$ (500,291)	$ (30,489)	$ (251,026)

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Net operating loss carryforward	$ 581,324	$ 542,847
Deferred compensation	16,815	19,844
Equity compensation	7,188	8,152
AMT credits and other credits	0	3,296
Asset retirement obligation	60,064	78,126
Interest expense carryover	18,035	19,444
Lease deferred tax assets	16,450	0
Other	11,072	11,048
Valuation allowances:
Total deferred tax assets	520,122	562,410
Deferred tax liabilities:
Depreciation and depletion	(639,581)	(1,207,784)
Cumulative mark-to-market gain	(25,957)	(21,294)
Lease deferred tax liabilities	(14,780)	0
Total deferred tax liabilities	(680,318)	(1,229,078)
Net deferred tax liability	(160,196)	(666,668)
Federal
Valuation allowances:
Valuation allowances	(32,530)	(18,975)
State, net of federal benefit
Valuation allowances:
Valuation allowances	$ (158,296)	$ (101,372)

Income Taxes - Changes in Defer

Income Taxes - Changes in Deferred Tax Asset Valuation Allowances (Detail) - Valuation Allowance of Deferred Tax Assets - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Balance at the beginning of the year	$ (120,347)	$ (125,134)	$ (107,174)
Charged to provision for income taxes:
Non-recoverable deferred tax assets	(28,208)	0	0
Other state valuation allowances	(31,214)	16,380	(23,790)
Other federal valuation allowances	346	494	(247)
Other	527	123	2,304
Balance at the end of the year	(190,826)	(120,347)	(125,134)
State
Charged to provision for income taxes:
Net operating loss carryforwards	(25,710)	(23,926)	(11,612)
Federal
Charged to provision for income taxes:
Net operating loss carryforwards	$ 13,780	$ 11,716	$ 15,385

Net Income (Loss) Per Common _3

Net Income (Loss) Per Common Share - Computations of Basic and Diluted Income (Loss) Per Common Share (Detail) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share Reconciliation [Abstract]
Net (loss) income		$ (1,805,320)	$ (27,581)	$ 115,185	$ 1,419	$ (1,764,422)	$ 48,539	$ (79,836)	$ 49,238	$ (1,716,297)	$ (1,746,481)	$ 333,146
Participating basic earnings	[1]									(251)	(245)	(3,751)
Basic net (loss) income attributed to common stockholders										(1,716,548)	(1,746,726)	329,395
Reallocation of participating earnings	[1]									0	0	5
Diluted net (loss) income attributed to common stockholders										$ (1,716,548)	$ (1,746,726)	$ 329,400
Net (loss) income per common share:
Basic		$ (7.27)	$ (0.11)	$ 0.46	$ 0.01	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ (6.92)	$ (7.10)	$ 1.34
Diluted		$ (7.27)	$ (0.11)	$ 0.46	$ 0.01	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ (6.92)	$ (7.10)	$ 1.34
[1]	Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

Net Income (Loss) Per Common _4

Net Income (Loss) Per Common Share - Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Denominator:
Weighted average common shares outstanding – basic	247,970	246,171	245,091
Effect of dilutive securities:
Director and employee restricted stock and performance-based equity awards	0	0	367
Weighted average common shares outstanding – diluted	247,970	246,171	245,458

Net Income (Loss) Per Common _5

Net Income (Loss) Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Grants
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation			702,000
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	3,100,000	3,100,000	2,800,000

Indebtedness - Additional Infor

Indebtedness - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0	$ 0	$ 0

Indebtedness - Debt Outstanding

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Senior notes	$ 2,675,763	$ 2,877,349
Senior subordinated notes	48,980	48,980
Total debt	3,201,743	3,869,329
Unamortized premium	3,013	4,741
Unamortized debt issuance costs	(31,819)	(37,209)
Total debt (net of debt issuance costs)	3,172,937	3,836,861
3.0% Bank Debt | Notes Payable to Banks
Debt Instrument [Line Items]
Bank debt (3.0%)	477,000	943,000
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Senior notes	750,000	750,000
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes	741,531	741,531
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes	511,886	580,032
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Senior notes	374,139	475,952
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes	297,617	329,244
Other Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes	590	590
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Senior subordinated notes	7,712	7,712
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Senior subordinated notes	19,054	19,054
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Senior subordinated notes	$ 22,214	$ 22,214

Indebtedness - Debt Outstandi_2

Indebtedness - Debt Outstanding (Parenthetical) (Detail)	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate on notes	4.875%		4.875%
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%		5.00%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.875%	5.875%	5.875%
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%		5.00%
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%		5.00%
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%		5.75%
Notes Payable to Banks | 3.0% Bank Debt
Debt Instrument [Line Items]
Bank debt percentage	3.00%		3.00%

Indebtedness - Bank Debt - Addi

Indebtedness - Bank Debt - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019USD ($)CommercialBank	Dec. 31, 2018USD ($)	Dec. 31, 2017
Debt Instrument [Line Items]
Bank debt	$ 464,319,000	$ 932,018,000
Bank Credit Facility
Debt Instrument [Line Items]
Bank credit facility, maximum amount	4,000,000,000
Bank credit facility, borrowing base	3,000,000,000
Bank commitments	$ 2,400,000,000
Number of commercial banks included in current bank group | CommercialBank	27
Percentage holding of commercial banks, Maximum	7.00%
Maturity date of loan	Apr. 13, 2023
Bank debt	$ 477,000,000
Undrawn letters of credit	250,200,000
Borrowing capacity available under the commitment amount	$ 1,700,000,000
Weighted average interest rate on the bank credit facility	3.80%	3.70%	2.70%
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility | Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin	0.25%
Bank Credit Facility | LIBOR Rate
Debt Instrument [Line Items]
Interest rate margin	1.25%
Bank Credit Facility | Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility | Minimum | Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.15%
Bank Credit Facility | Minimum | Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	0.25%
Bank Credit Facility | Minimum | Alternate Base Rate | Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.125%
Bank Credit Facility | Minimum | LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Bank Credit Facility | Minimum | LIBOR Rate | Credit Facility
Debt Instrument [Line Items]
Base rate on debt	1.125%
Bank Credit Facility | Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.375%
Bank Credit Facility | Maximum | Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility | Maximum | Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Bank Credit Facility | Maximum | Alternate Base Rate | Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.75%
Bank Credit Facility | Maximum | LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	2.25%
Bank Credit Facility | Maximum | LIBOR Rate | Credit Facility
Debt Instrument [Line Items]
Base rate on debt	1.75%

Indebtedness - New Senior Notes

Indebtedness - New Senior Notes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Subsequent Event
Debt Instrument [Line Items]
Interest rate on notes	9.25%
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount		100.00%
9.25% Senior Notes Due 2026 | Subsequent Event
Debt Instrument [Line Items]
Aggregate principal amount	$ 550
Interest rate on notes	9.25%
Debt instrument maturity year	2026
Net proceeds after underwriting discounts	$ 541.6
Net proceeds after commissions	$ 8.4
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes		5.75%	5.75%	5.75%
5.75% Senior Notes Due 2021 | Subsequent Event
Debt Instrument [Line Items]
Interest rate on notes	5.75%
Repayments of senior notes	$ 324.1
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes		5.875%	5.875%	5.875%
5.875% Senior Notes Due 2022 | Subsequent Event
Debt Instrument [Line Items]
Interest rate on notes	5.875%
Repayments of senior notes	$ 175.9

Indebtedness - Early Extinguish

Indebtedness - Early Extinguishment of Debt - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Jan. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Subsequent Event
Debt Instrument [Line Items]
Interest rate on notes	9.25%
Repayment of notes by early cash tender premium amount	$ 15.1
Early cash tender offer period	10 days
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Extinguishment of debt, principal amount		$ 101.8	$ 101.8
Interest rate on notes		5.75%	5.75%	5.75%
5.75% Senior Notes Due 2021 | Subsequent Event
Debt Instrument [Line Items]
Interest rate on notes	5.75%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Extinguishment of debt, principal amount		$ 31.6	$ 31.6
Interest rate on notes		5.875%	5.875%	5.875%
5.875% Senior Notes Due 2022 | Subsequent Event
Debt Instrument [Line Items]
Interest rate on notes	5.875%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Extinguishment of debt, principal amount		$ 68.1	$ 68.1
Interest rate on notes		5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021 and 5.875% Senior Notes Due 2022 | Subsequent Event
Debt Instrument [Line Items]
Cash tender principal amount	$ 500

Indebtedness - Senior Subordina

Indebtedness - Senior Subordinated Notes - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019
Subordinated Debt
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount	101.00%

Indebtedness - Guarantees and D

Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2019
Debt Instrument [Line Items]
Debt instrument, covenant compliance	Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2019.
Minimum
Debt Instrument [Line Items]
Ratio of debt to EBITDAX	250.00%
Current ratio	100.00%
Present value of proved reserves to total debt	150.00%

Indebtedness - Schedule for Lon

Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) $ in Thousands	Dec. 31, 2019USD ($)
Debt Disclosure [Abstract]
2020	$ 0
2021	396,353
2022	829,147
2023	1,226,243
2024	0
Thereafter	750,000
Total debt	$ 3,201,743

Asset Retirement Obligations -

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Beginning of period		$ 312,754	$ 276,855
Liabilities incurred		4,063	3,376
Acquisitions		0	13,438
Liabilities settled		(5,953)	(5,052)
Disposition of wells		(82,576)	(13,332)
Accretion expense		15,658	25,456
Change in estimate		7,130	12,013
End of period		251,076	312,754
Less current portion		(2,393)	(5,485)
Long-term asset retirement obligations	[1]	$ 248,683	$ 307,269
[1]	In fourth quarter 2019, we entered into an agreement to sell our legacy assets in Northwest Pennsylvania. Final approval from the state governmental authorities for a change in operatorship is expected by mid-2020, at which time we will reduce this liability by approximately $125.5 million and recognize a gain on sale of these assets

Asset Retirement Obligations _2

Asset Retirement Obligations - Asset Retirement Obligations (Parenthetical) (Detail) $ in Millions	3 Months Ended
	Dec. 31, 2019USD ($)
Northwest Pennsylvania
Asset Retirement Obligations [Line Items]
Liability released upon approval of authorities	$ 125.5

Derivative Activities - Additio

Derivative Activities - Additional Information (Detail) $ in Millions	Dec. 31, 2019USD ($)t_per_MMMBTU
Derivatives Excluding Basis Swaps And Freight Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 126.7
Commodity | Natural Gas Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 9.4
Volume Hedged | MMBTU	114,882,500
Commodity | Propane Spread Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 14.1
Freight | Swaps | Level 2
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 1.5
Freight | Swaps | Contracts Settle in First Quarter 2020 | Level 2
Derivative [Line Items]
Volume Hedged | t_per_M	4,000
Freight | Swaps | Contracts Settle for Remainder of 2020 | Level 2
Derivative [Line Items]
Volume Hedged | t_per_M	14,000
Freight | Swaps | Contracts Settle in 2021 | Level 2
Derivative [Line Items]
Volume Hedged | t_per_M	10,000

Derivative Activities - Derivat

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail)	Dec. 31, 2019MMBTU / dbbl / d$ / MMBTU$ / bbl$ / gal
2020 Commodity Contract | Swaps | Natural Gas
Derivative [Line Items]
Volume Hedged | MMBTU / d	1,000,984
Weighted Average Hedge Price | $ / MMBTU	2.64	[1]
2020 Commodity Contract | Swaps | Crude Oil
Derivative [Line Items]
Volume Hedged	7,995
Weighted Average Hedge Price | $ / bbl	58.27	[1]
2021 Commodity Contract | Swaps | Natural Gas
Derivative [Line Items]
Volume Hedged | MMBTU / d	50,000
Weighted Average Hedge Price | $ / MMBTU	2.62	[1]
2021 Commodity Contract | Swaps | Crude Oil
Derivative [Line Items]
Volume Hedged	1,000
Weighted Average Hedge Price | $ / bbl	55	[1]
April-September, 2020 Commodity Contract | Calls | Crude Oil
Derivative [Line Items]
Volume Hedged	500
Weighted Average Hedge Price | $ / bbl	59
January-March, 2020 Commodity Contract | Swaps | NGLs (NC4-Normal Butane)
Derivative [Line Items]
Volume Hedged	659
Weighted Average Hedge Price | $ / gal	0.73
January-March, 2020 Commodity Contract | Swaps | NGLs (C5-Natural Gasoline)
Derivative [Line Items]
Volume Hedged	4,297
Weighted Average Hedge Price | $ / gal	1.21
[1]	We also sold natural gas call swaptions of 140,000 Mmbtu/day for March-December 2020 at a weighted average price of $2.53 and 100,000 Mmbtu per day for 2021 at a weighted average price of $2.69. In addition, we sold call swaptions of 3,000 bbls per day for 2021 at a weighted average price of $56.50.

Derivative Activities - Deriv_2

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - Call Swaptions	Dec. 31, 2019MMBTU / dbbl / d$ / MMBTU$ / bbl
2020 Commodity Contract | Natural Gas
Derivative [Line Items]
Volume Hedged | MMBTU / d	140,000
Weighted average price of hedge | $ / MMBTU	2.53
2021 Commodity Contract | Natural Gas
Derivative [Line Items]
Volume Hedged | MMBTU / d	100,000
Weighted average price of hedge | $ / MMBTU	2.69
2021 Commodity Contract | Crude Oil
Derivative [Line Items]
Volume Hedged | bbl / d	3,000
Weighted average price of hedge | $ / bbl	56.50

Derivative Activities - Schedul

Derivative Activities - Schedule of Additional Information Related to Master Netting Arrangements with Derivative Counterparties (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 152,692	$ 122,624
Gross Amounts Offset in the Balance Sheet	(15,138)	(29,829)
Net Amounts of Assets Presented in the Balance Sheet	137,554	92,795
Gross Amounts of Recognized (Liabilities)	(29,206)	(37,435)
Gross Amounts Offset in the Balance Sheet	15,138	29,829
Net Amounts of (Liabilities) Presented in the Balance Sheet	(14,068)	(7,606)
Commodity | Swaps | Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	134,364	20,834
Gross Amounts Offset in the Balance Sheet	(2,913)	(11,748)
Net Amounts of Assets Presented in the Balance Sheet	131,451	9,086
Gross Amounts of Recognized (Liabilities)	(1,657)	(18,332)
Gross Amounts Offset in the Balance Sheet	2,913	11,748
Net Amounts of (Liabilities) Presented in the Balance Sheet	1,256	(6,584)
Commodity | Swaps | Crude Oil
Derivative [Line Items]
Gross Amounts of Recognized Assets	3,893	26,481
Gross Amounts Offset in the Balance Sheet	(4,794)	(651)
Net Amounts of Assets Presented in the Balance Sheet	(901)	25,830
Gross Amounts of Recognized (Liabilities)	(4,814)	0
Gross Amounts Offset in the Balance Sheet	4,794	651
Net Amounts of (Liabilities) Presented in the Balance Sheet	(20)	651
Commodity | Swaps | NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets		18,719
Gross Amounts Offset in the Balance Sheet		(589)
Net Amounts of Assets Presented in the Balance Sheet		18,130
Gross Amounts of Recognized (Liabilities)		0
Gross Amounts Offset in the Balance Sheet		589
Net Amounts of (Liabilities) Presented in the Balance Sheet		589
Commodity | Swaps | NGLs (C4- Butane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	167	4,084
Gross Amounts Offset in the Balance Sheet	0	0
Net Amounts of Assets Presented in the Balance Sheet	167	4,084
Commodity | Swaps | NGLs (C5-Natural Gasoline)
Derivative [Line Items]
Gross Amounts of Recognized Assets	60	17,371
Gross Amounts Offset in the Balance Sheet	(127)	0
Net Amounts of Assets Presented in the Balance Sheet	(67)	17,371
Gross Amounts of Recognized (Liabilities)	(127)
Gross Amounts Offset in the Balance Sheet	127
Net Amounts of (Liabilities) Presented in the Balance Sheet	0
Commodity | Swaptions | Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	0	5,200
Gross Amounts Offset in the Balance Sheet	(1,325)	(3,883)
Net Amounts of Assets Presented in the Balance Sheet	(1,325)	1,317
Gross Amounts of Recognized (Liabilities)	(2,594)	(7,972)
Gross Amounts Offset in the Balance Sheet	1,325	3,883
Net Amounts of (Liabilities) Presented in the Balance Sheet	(1,269)	(4,089)
Commodity | Swaptions | Crude Oil
Derivative [Line Items]
Gross Amounts of Recognized Assets	0
Gross Amounts Offset in the Balance Sheet	(1,597)
Net Amounts of Assets Presented in the Balance Sheet	(1,597)
Gross Amounts of Recognized (Liabilities)	(2,254)
Gross Amounts Offset in the Balance Sheet	1,597
Net Amounts of (Liabilities) Presented in the Balance Sheet	(657)
Commodity | Basis Swaps | Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	10,766	6,468
Gross Amounts Offset in the Balance Sheet	(1,092)	(2,822)
Net Amounts of Assets Presented in the Balance Sheet	9,674	3,646
Gross Amounts of Recognized (Liabilities)	(1,371)	(1,702)
Gross Amounts Offset in the Balance Sheet	1,092	2,822
Net Amounts of (Liabilities) Presented in the Balance Sheet	(279)	1,120
Commodity | Spread Swaps | NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	1,913	8,984
Gross Amounts Offset in the Balance Sheet	(1,913)	(8,868)
Net Amounts of Assets Presented in the Balance Sheet	0	116
Gross Amounts of Recognized (Liabilities)	(16,040)	(8,868)
Gross Amounts Offset in the Balance Sheet	1,913	8,868
Net Amounts of (Liabilities) Presented in the Balance Sheet	(14,127)	0
Commodity | Collars | Crude Oil
Derivative [Line Items]
Gross Amounts of Recognized Assets		5,945
Gross Amounts Offset in the Balance Sheet		(707)
Net Amounts of Assets Presented in the Balance Sheet		5,238
Gross Amounts of Recognized (Liabilities)		0
Gross Amounts Offset in the Balance Sheet		707
Net Amounts of (Liabilities) Presented in the Balance Sheet		707
Commodity | Collars | NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets		8,538
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet		8,538
Commodity | Calls | Crude Oil
Derivative [Line Items]
Gross Amounts of Recognized Assets	0
Gross Amounts Offset in the Balance Sheet	(349)
Net Amounts of Assets Presented in the Balance Sheet	(349)
Gross Amounts of Recognized (Liabilities)	(349)
Gross Amounts Offset in the Balance Sheet	349
Net Amounts of (Liabilities) Presented in the Balance Sheet	0
Freight | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	1,529	0
Gross Amounts Offset in the Balance Sheet	(1,028)	(561)
Net Amounts of Assets Presented in the Balance Sheet	501	(561)
Gross Amounts of Recognized (Liabilities)	0	(561)
Gross Amounts Offset in the Balance Sheet	1,028	561
Net Amounts of (Liabilities) Presented in the Balance Sheet	$ 1,028	$ 0

Derivative Activities - Effects

Derivative Activities - Effects of Derivatives on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Fair Value (Loss) Income	$ 18,491	$ 74,676	$ 195,245	$ (61,731)	$ 100,698	$ (34,591)	$ (103,290)	$ (14,009)	$ 226,681	$ (51,192)	$ 213,350
Swaptions
Derivative [Line Items]
Derivative Fair Value (Loss) Income									333	(6,556)	6,534
Collars
Derivative [Line Items]
Derivative Fair Value (Loss) Income									(3,903)	17,583	18,132
Basis Swaps
Derivative [Line Items]
Derivative Fair Value (Loss) Income									6,661	(1,104)	(4,647)
Puts
Derivative [Line Items]
Derivative Fair Value (Loss) Income									0	0	10,929
Calls
Derivative [Line Items]
Derivative Fair Value (Loss) Income									(349)	(2,653)	987
Commodity | Swaps
Derivative [Line Items]
Derivative Fair Value (Loss) Income									219,968	(57,950)	181,095
Freight | Swaps
Derivative [Line Items]
Derivative Fair Value (Loss) Income									$ 3,971	$ (512)	$ 320

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	$ 62,009	$ 57,293
Fair Value, Inputs, Level 1 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	62,009	57,293
Level 2 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	0	0
Fair Value, Inputs, Level 3 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	0	0
Swaps | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	131,886	69,156
Swaps | Freight | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	1,529	(561)
Swaps | Fair Value, Inputs, Level 1 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Swaps | Fair Value, Inputs, Level 1 | Freight | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Swaps | Level 2 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	131,886	69,156
Swaps | Level 2 | Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	1,500
Swaps | Level 2 | Freight | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	1,529	(561)
Swaps | Fair Value, Inputs, Level 3 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Swaps | Fair Value, Inputs, Level 3 | Freight | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Calls | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(349)
Calls | Fair Value, Inputs, Level 1 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0
Calls | Level 2 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(349)
Calls | Fair Value, Inputs, Level 3 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0
Collars | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		14,483
Collars | Fair Value, Inputs, Level 1 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Collars | Level 2 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		5,945
Collars | Fair Value, Inputs, Level 3 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		8,538
Basis Swaps | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(4,732)	4,883
Basis Swaps | Fair Value, Inputs, Level 1 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Basis Swaps | Level 2 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(4,732)	4,883
Basis Swaps | Fair Value, Inputs, Level 3 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Swaptions | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(4,848)	(2,772)
Swaptions | Fair Value, Inputs, Level 1 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Swaptions | Level 2 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Swaptions | Fair Value, Inputs, Level 3 | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	$ (4,848)	$ (2,772)

Fair Value Measurements - Recon

Fair Value Measurements - Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy (Detail) - Fair Value, Inputs, Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at the beginning of period	$ 5,766
Total gains (losses) included in earnings	0
Settlements received	(7,692)
Transfers in and/or out of Level 3	(2,922)
Balance at end of period	$ (4,848)

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail)	3 Months Ended					12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)$ / shares	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends						$ 1,100,000	$ 1,100,000	$ 4,100,000
Mark-to-market gain (loss)						8,500,000	$ (7,900,000)	4,200,000
Deficiency charges	$ 14,000,000
Closing stock price | $ / shares		$ 9.57					$ 9.57
Impairment of goodwill		$ 1,641,197,000	$ 0	$ 0	$ 0	$ 0	$ 1,641,197,000	0
Discount Rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Annual discount rate	12					12
North Louisiana
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties	$ 1,100,000,000
Pennsylvania
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, fair value		$ 0					0
Oklahoma
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties					$ 7,300,000		$ 15,300,000
Oklahoma And Texas Panhandle
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties								$ 63,700,000

Fair Value Measurements - Value

Fair Value Measurements - Value of Assets Measured at Fair Value on Nonrecurring Basis (Detail) - Fair Value, Measurements, Nonrecurring - Natural Gas and Oil Properties - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, fair value	$ 370,500	$ 32,516	$ 85,597
Impairment on natural gas and oil properties	$ 1,093,531	$ 22,614	$ 63,679

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Assets:
Marketable securities held in deferred compensation plans		$ 62,000	$ 57,300
Carrying Value
Assets:
Commodity swaps, options and basis swaps		137,554	92,795
Marketable securities held in deferred compensation plans	[1]	62,009	57,293
(Liabilities):
Commodity swaps, options and basis swaps		(14,068)	(7,606)
Bank credit facility	[2]	(477,000)	(943,000)
Deferred compensation plan	[3]	(74,472)	(80,092)
Fair Value
Assets:
Commodity swaps, options and basis swaps		137,554	92,795
Marketable securities held in deferred compensation plans	[1]	62,009	57,293
(Liabilities):
Commodity swaps, options and basis swaps		(14,068)	(7,606)
Bank credit facility	[2]	(477,000)	(943,000)
Deferred compensation plan	[3]	(74,472)	(80,092)
5.75% Senior Notes Due 2021 | Carrying Value
(Liabilities):
Senior notes	[2]	(374,139)	(475,952)
5.75% Senior Notes Due 2021 | Fair Value
(Liabilities):
Senior notes	[2]	(375,909)	(455,972)
5.00% Senior Notes Due 2022 | Carrying Value
(Liabilities):
Senior notes	[2]	(511,886)	(580,032)
5.00% Senior Notes Due 2022 | Fair Value
(Liabilities):
Senior notes	[2]	(501,582)	(519,343)
5.875% Senior Notes Due 2022 | Carrying Value
(Liabilities):
Senior notes	[2]	(297,617)	(329,244)
5.875% Senior Notes Due 2022 | Fair Value
(Liabilities):
Senior notes	[2]	(294,757)	(305,989)
Other Senior Notes Due 2022 | Carrying Value
(Liabilities):
Senior notes	[2]	(590)	(590)
Other Senior Notes Due 2022 | Fair Value
(Liabilities):
Senior notes	[2]	(592)	(581)
5.00% Senior Notes Due 2023 | Carrying Value
(Liabilities):
Senior notes	[2]	(741,531)	(741,531)
5.00% Senior Notes Due 2023 | Fair Value
(Liabilities):
Senior notes	[2]	(683,291)	(654,683)
4.875% Senior Notes Due 2025 | Carrying Value
(Liabilities):
Senior notes	[2]	(750,000)	(750,000)
4.875% Senior Notes Due 2025 | Fair Value
(Liabilities):
Senior notes	[2]	(645,098)	(616,313)
5.75% Senior Subordinated Notes Due 2021 | Carrying Value
(Liabilities):
Subordinated debt	[2]	(22,214)	(22,214)
5.75% Senior Subordinated Notes Due 2021 | Fair Value
(Liabilities):
Subordinated debt	[2]	(21,539)	(21,638)
5.00% Senior Subordinated Notes Due 2022 | Carrying Value
(Liabilities):
Subordinated debt	[2]	(19,054)	(19,054)
5.00% Senior Subordinated Notes Due 2022 | Fair Value
(Liabilities):
Subordinated debt	[2]	(17,011)	(17,072)
5.00% Senior Subordinated Notes Due 2023 | Carrying Value
(Liabilities):
Subordinated debt	[2]	(7,712)	(7,712)
5.00% Senior Subordinated Notes Due 2023 | Fair Value
(Liabilities):
Subordinated debt	[2]	$ (7,654)	$ (6,690)
[1]	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.
[2]	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.
[3]	The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input.

Fair Value Measurements - Car_2

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Parenthetical) (Detail)	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
5.75% Senior Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%
5.00% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%
5.875% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.875%	5.875%	5.875%
5.00% Senior Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%		5.00%
4.875% Senior Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	4.875%		4.875%
5.75% Senior Subordinated Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.75%		5.75%
5.00% Senior Subordinated Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%		5.00%
5.00% Senior Subordinated Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%		5.00%

Stock-based Compensation Plan_2

Stock-based Compensation Plans - Additional Information (Detail) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2019USD ($)

Sep. 30, 2019USD ($)

Jun. 30, 2019USD ($)

Mar. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Sep. 30, 2018USD ($)

Jun. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2019USD ($)Plans

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Active equity-based stock plans | Plans

2

Income tax benefit

$ (498,859)

$ (47,219)

$ 40,099

$ 5,688

$ (68,784)

$ 24,137

$ (28,518)

$ 42,676

$ (500,291)

$ (30,489)

$ (251,026)

Equity Compensation

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Income tax benefit

$ 3,400

$ 3,600

5,300

Officers

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Accelerated vesting of equity grants

$ 30,800

$ 30,800

Vesting period

1 year

Stock-based Compensation Plan_3

Stock-based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	[1]
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 42,382	$ 49,288	$ 82,776
Termination Costs
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,971	0	1,664
Direct Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,928	2,109	2,060
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,856	1,452	1,437
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,566	1,921	2,742
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 35,061	$ 43,806	$ 74,873
[1]	Includes $30.8 million accelerated vesting of equity grants.

Stock-based Compensation Plan_4

Stock-based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017
Officers
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Accelerated vesting of equity grants	$ 30.8	$ 30.8

Stock-based Compensation Plan_5

Stock-based Compensation Plans - Additional Information 1 (Detail)	12 Months Ended
	Dec. 31, 2019Awardshares	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	3
Performance Share | Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of share value each unit represents at grant date | shares	1
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	2
Performance-based PG-PSUs and RG-PSUs | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Performance-based PG-PSUs and RG-PSUs | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	1
Performance Based TSR - PSUs | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%	0.00%	0.00%
Performance Based TSR - PSUs | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%	200.00%	150.00%

Stock-based Compensation Plan_6

Stock-based Compensation Plans - Additional Information 2 (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation related to Awards	$ 933,000
Weighted average period	1 year
Proceeds from the sales of common stock held by the deferred compensation plan	$ 667,000	$ 9,747,000	$ 4,482,000
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	2,792,438	1,834,883	888,326
Vesting period	3 years
Stock-based compensation expense	$ 22,500,000	$ 24,200,000	$ 23,400,000
Unrecognized compensation related to Awards	$ 24,900,000
Weighted average period	1 year 8 months 12 days
Granted, weighted average grant date fair value	$ 10.59	$ 16.98	$ 32.61
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	1,214,038	891,350	543,438
Stock-based compensation expense	$ 9,300,000	$ 11,700,000	$ 30,400,000
Unrecognized compensation related to Awards	$ 4,500,000
Weighted average period	1 year 6 months
Granted, weighted average grant date fair value	$ 10.16	$ 15.30	$ 25.91
Accelerated vesting of equity grants			$ 15,400,000
Restricted Stock Liability Awards | Non-Employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	183,000	146,000	90,000
Restricted Stock Liability Awards | Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	1,000,000	745,000	453,000
Vesting period	3 years	3 years	3 years

Stock-based Compensation Plan_7

Stock-based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	1,386,088	833,058	765,971
Granted	2,792,438	1,834,883	888,326
Vested	(1,608,075)	(1,037,501)	(698,563)
Forfeited	(568,212)	(244,352)	(122,676)
Outstanding, Ending Balance	2,002,239	1,386,088	833,058
Outstanding, Beginning Balance, weighted average grant date fair value	$ 20.04	$ 31.64	$ 33.62
Granted, weighted average grant date fair value	10.59	16.98	32.61
Vested, weighted average grant date fair value	15.72	23.57	34.82
Forfeited, weighted average grant date fair value	13.03	21.59	32.91
Outstanding, Ending Balance, weighted average grant date fair value	$ 12.32	$ 20.04	$ 31.64
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	184,579	55,202	425,018
Granted	1,214,038	891,350	543,438
Vested	(987,491)	(738,073)	(908,912)
Forfeited	0	(23,900)	(4,342)
Outstanding, Ending Balance	411,126	184,579	55,202
Outstanding, Beginning Balance, weighted average grant date fair value	$ 15.65	$ 32.26	$ 43.48
Granted, weighted average grant date fair value	10.16	15.30	25.91
Vested, weighted average grant date fair value	10.86	16.34	33.71
Forfeited, weighted average grant date fair value	0	19.76	31.10
Outstanding, Ending Balance, weighted average grant date fair value	$ 10.94	$ 15.65	$ 32.26

Stock-based Compensation Plan_8

Stock-based Compensation Plans - Additional Information 3 (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation related to Awards	$ 933,000
Weighted average period	1 year
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Stock-based compensation expense	$ 3,800,000	$ 5,400,000	$ 1,800,000
Accelerated vesting of equity grants			1,500,000
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Stock-based compensation expense	$ 3,000,000	$ 6,300,000	24,800,000
Accelerated vesting of equity grants			$ 13,000,000
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation related to Awards	$ 1,500,000
Weighted average period	1 year 2 months 12 days

Stock-based Compensation Plan_9

Stock-based Compensation Plans - PG/RG-PSUs Activities (Detail) - Performance-based PG-PSUs and RG-PSUs - $ / shares	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	536,798		122,921		0
Granted	345,202	[1]	440,938	[1]	122,921
Forfeited	(427)		(27,061)	[2]
Outstanding, Ending Balance	881,573		536,798		122,921
Outstanding, Beginning Balance, weighted average grant date fair value	$ 15.61		$ 25.53		$ 0
Granted, weighted average grant date fair value	10.32	[1]	15.22	[1]	25.53
Forfeited, weighted average grant date fair value	15.65		23.03	[2]
Outstanding, Ending Balance, weighted average grant date fair value	$ 11.70		$ 15.61		$ 25.53
[1]	Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 200% depending on achievement of specifically identified performance targets.
[2]	The first

Stock-based Compensation Pla_10

Stock-based Compensation Plans - PG/RG-PSUs Activities (Parenthetical) (Detail) - Performance-based PG-PSUs and RG-PSUs - Tranche	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total Number of tranches in PSU		3
Number of tranches forfeited		1
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%

Stock-based Compensation Pla_11

Stock-based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of TSR - Performance Awards (Detail) - Performance Based TSR - PSUs - $ / shares		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate		2.44%	2.42%	1.49%
Expected annual volatility		46.00%	48.00%	44.00%
Grant date fair value per unit	[1]	$ 11.34	$ 18.51	$ 26.26
[1]	These

Stock-based Compensation Pla_12

Stock-based Compensation Plans - TSR - PSUs Activities (Detail) - Performance Based TSR - PSUs - $ / shares		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Summary of Performance Share Unit Awards outstanding, Number of Units
Outstanding, Beginning Balance		1,067,886		1,009,842		871,299
Granted	[1]	314,152		329,486		358,519
Vested and issued		(12,283)	[2]	(73,985)	[3]	(85,461)	[4]
Forfeited		(376,303)		(197,457)		(134,515)
Outstanding, Ending Balance		993,452		1,067,886		1,009,842
Summary of Performance Share Unit Awards outstanding, Weighted Average Grant Date Fair Value
Outstanding, Beginning Balance, weighted average grant date fair value		$ 27.81		$ 38.38		$ 55.29
Granted, weighted average grant date fair value	[1]	11.34		18.51		26.26
Vested, weighted average grant date fair value		30.47	[2]	56.81	[3]	86.23	[4]
Forfeited, weighted average grant date fair value		37.25		55.46		85.24
Outstanding, Ending Balance, weighted average grant date fair value		$ 19		$ 27.81		$ 38.38
[1]	These
[2]	Includes 12,283 TSR-PSUs awards issued related to 2016 performance where the return on our common stock was in the 20 th
[3]	Includes 73,985 TSR-PSUs awards issued related to the 2015 performance period where the return on our common stock was the 46 th th
[4]	Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67 th th

Stock-based Compensation Pla_13

Stock-based Compensation Plans - TSR - PSUs Activities (Parenthetical) (Detail) - Performance Based TSR - PSUs - shares	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares vested and issued related to performance period number of common stock	12,283	[1]	73,985	[2]	85,461	[3]
February 2014 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Return on common stock percentile					67.00%
May 2014 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Return on common stock percentile					56.00%
February 2015 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Return on common stock percentile			46.00%
May 2015 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Return on common stock percentile			36.00%
February 2016 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Return on common stock percentile	20.00%
May 2016 Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of awards forfeited	100.00%
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares on performance units granted	0.00%		0.00%		0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares on performance units granted	200.00%		200.00%		150.00%
[1]	Includes 12,283 TSR-PSUs awards issued related to 2016 performance where the return on our common stock was in the 20 th
[2]	Includes 73,985 TSR-PSUs awards issued related to the 2015 performance period where the return on our common stock was the 46 th th
[3]	Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67 th th

Stock-based Compensation Pla_14

Stock-based Compensation Plans - Additional Information 4 (Detail) - USD ($) $ in Thousands, shares in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Compensation And Retirement Disclosure [Abstract]
Maximum percentage of employees contribution									75.00%
Maximum percentage of employers contribution in cash									6.00%
Employer contribution									$ 5,400	$ 5,800	$ 5,100
Deferred compensation plan vesting period									3 years
Deferred compensation plan	$ (960)	$ 8,871	$ 11,142	$ (3,581)	$ 18,072	$ (223)	$ (6,615)	$ 7,397	$ 15,472	$ 18,631	$ 50,915
Shares held in rabbi trust total	3.2				2.6				3.2	2.6
Vested shares held in rabbi trust	2.7				2.4				2.7	2.4

Stock-based Compensation Pla_15

Stock-based Compensation Plans - Summary of Change in Post Retirement Benefit Obligation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Changes in Benefit Obligations in Other Comprehensive Income (Loss):
Net loss (gain)	$ 532	$ (526)	$ 0
Prior service cost	0	0	1,769
Amortization of prior service cost	(369)	(369)	0
Other Post Retirement Benefits
Change in Benefit Obligation:
Benefit obligation at beginning of year	1,355	1,769
Prior service cost	0	0
Service cost	88	94
Interest cost	68	58
Actuarial loss (gain)	532	(526)
Benefits paid	(86)	(40)
Benefit obligation at end of year	1,957	1,355	$ 1,769
Amounts recognized in the consolidated balance sheet:
Long-term liabilities	1,957	1,355
Components of Net Periodic Post Retirement Benefit Cost:
Service cost	88	94
Interest cost	68	58
Amortization of prior service cost	369	369
Net periodic post retirement costs (recognized in general and administrative expense)	525	521
Other Changes in Benefit Obligations in Other Comprehensive Income (Loss):
Net loss (gain)	532	(526)
Prior service cost	0	0
Amortization of prior service cost	(369)	(369)
Total recognized in other comprehensive income (loss)	163	(895)
Total recognized in net periodic benefit cost and other comprehensive income (loss)	$ 688	$ (374)

Stock-based Compensation Pla_16

Stock-based Compensation Plans - Summary of Assumptions Used to Determine Benefit Obligation (Detail) - Other Post Retirement Benefits	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Weighted average assumptions used to determine benefit obligation:
Discount rate	2.90%	4.00%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate	6.50%	6.50%
Ultimate trend rate	4.50%	5.00%
Year ultimate trend rate reached	2023	2028

Stock-based Compensation Pla_17

Stock-based Compensation Plans - Additional Information 5 (Detail) - Other Post Retirement Benefits	Dec. 31, 2019USD ($)
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments for the five year period 2020 through 2024	$ 1,100,000
Expected future benefit payments for the five year period 2025 through 2029	433,000
Estimated prior service cost amortized from accumulated other comprehensive (loss) income into statements of operation in 2020	$ 369,000

Capital Stock - Additional Info

Capital Stock - Additional Information (Detail) - USD ($)	3 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Oct. 31, 2019
Class Of Stock Disclosures [Abstract]
Authorized capital stock	485,000,000			485,000,000
Common stock, shares authorized	475,000,000			475,000,000
Preferred stock, shares authorized	10,000,000			10,000,000
Common dividends declared per share	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02
Maximum
Class Of Stock Disclosures [Abstract]
New stock purchase program, approved amount												$ 100,000,000

Capital Stock - Schedule of Cha

Capital Stock - Schedule of Changes in Number of Common Shares Outstanding (Detail) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class Of Stock [Line Items]
Beginning balance	249,510,022	248,129,430	247,144,356
Restricted stock grants	1,186,290	865,095	539,096
Treasury shares issued		5,302	15,580
Treasury shares repurchased	(1,798,468)
Ending balance	249,630,803	249,510,022	248,129,430
Restricted Stock
Class Of Stock [Line Items]
Restricted stock units vested	720,212	434,046	344,937
Performance Share
Class Of Stock [Line Items]
Performance stock units issued	12,747	76,149	85,461

Capital Stock - Schedule of C_2

Capital Stock - Schedule of Change in Treasury Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stockholders Equity Note [Abstract]
Beginning balance	9,665	14,967	30,547
Rabbi trust shares distributed and/or sold	(1,532)	(5,302)	(15,580)
Shares repurchased	1,800,000	0	0
Ending balance	1,808,133	9,665	14,967

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net cash provided from operating activities included:
Income taxes refunded from taxing authorities		$ 0	$ 7,521	$ 1,024
Interest paid		(189,443)	(207,433)	(179,431)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	[1]	11,193	28,826	20,245
(Decrease) increase in accrued capital expenditures		$ (20,104)	$ (119,021)	$ 71,739
[1]	Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Components of Lease Expense (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Commitments And Contingencies Disclosure [Line Items]
Operating lease cost	$ 15,536
Variable lease expense	6,916	[1]
Short-term lease expense / costs	2,965	[2]
Sublease income	(3,496)
Total lease expense	21,921
Natural Gas and Oil Properties
Commitments And Contingencies Disclosure [Line Items]
Short-term lease expense / costs	$ 29,126	[3]
[1]	Variable lease payments that are not dependent on an index or rate are not included in the lease liability or ROU assets.
[2]	Short-term lease expense represents expense related to leases with a contract term of one year or less.
[3]	These short-term lease costs are related to leases with a contract term of one year or less and the majority of which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our consolidated balance sheets and may fluctuate based on the number of drilling rigs being utilized.

Commitments and Contingencies_2

Commitments and Contingencies - Supplemental Cash Flow Information Related to Operating Leases (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Commitments And Contingencies Disclosure [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 18,700
ROU assets added in exchange for lease obligations (since adoption)	$ 24,839

Commitments and Contingencies_3

Commitments and Contingencies - Supplemental Balance Sheet Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Operating lease right-of-use assets	$ 62,053	$ 0
Accrued liabilities – current	(27,856)
Operating lease liabilities – long-term	$ (41,068)	$ 0

Commitments and Contingencies_4

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)bbl / dMcf / d
Commitments And Contingencies Disclosure [Line Items]
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
2021
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day | bbl / d	3,000
2035
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day | bbl / d	10,000
Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	25,000
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	6 years
Natural Gas | Late 2020
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	35,000
Natural Gas | Late 2021
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	50,000
Natural Gas | 2025 Through 2026
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	15,000
Impairment of Proved Property and Other Assets
Commitments And Contingencies Disclosure [Line Items]
Impairment of ROU Asset | $	$ 2.1

Commitments and Contingencies_5

Commitments and Contingencies - Schedule of Weighted Average Remaining Lease Term and Weighted Average Discount Rate for Operating Leases (Detail)	Dec. 31, 2019
Lessee Disclosure [Abstract]
Weighted average remaining lease term	4 years 7 months 6 days
Weighted average discount rate	6.00%

Commitments and Contingencies_6

Commitments and Contingencies - Schedule of Lease Liabilities with Enforceable Contract Terms are Greater Than One year Mature (Detail) $ in Thousands	Dec. 31, 2019USD ($)
Commitments And Contingencies Disclosure [Abstract]
2020	$ 31,245
2021	14,252
2022	7,023
2023	6,500
2024	6,468
Thereafter	15,262
Total lease payments	80,750
Less effects of discounting	(11,826)
Operating lease liabilities	$ 68,924

Commitments and Contingencies_7

Commitments and Contingencies - Schedule of Future Minimum Transportation Fees Due (Detail) $ in Thousands	Dec. 31, 2019USD ($)	[1]
Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]
2020	$ 945,392
2021	949,126
2022	905,920
2023	870,062
2024	853,457
Thereafter	5,154,987
Transportation, Gathering and Processing Contracts	$ 9,678,944
[1]	The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced.

Commitments and Contingencies_8

Commitments and Contingencies - Future Delivery Commitments (Detail)	12 Months Ended
	Dec. 31, 2019MMBTU / dbbl / d
2020 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	528,607
2020 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	81,000
2021 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	491,313
2021 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	65,932
2022 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	370,179
2022 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	43,000
2023 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	167,970
2023 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	35,000
2024 - 2028 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	100,000
2024 - 2028 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	35,000
2029 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	100,000
2029 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000
2030 - 2031 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	0
2030 - 2031 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000

Termination Costs - Additional

Termination Costs - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring And Related Activities [Abstract]
Accrued severance costs	$ 7,535	$ (356)	$ 2,176
Stock-based compensation expense (gain)	$ 1,971	$ 0	$ 1,664

Termination Costs - Termination

Termination Costs - Termination Costs Included in Accrued Liabilities in Consolidated Balance Sheet - (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	$ 0	$ 1,855
Accrued severance costs	7,535	(356)	$ 2,176
Accrued building rent	0	(17)
Payments	(2,843)	(1,482)
Ending balance	$ 4,692	$ 0	$ 1,855

Termination Costs - Summary of

Termination Costs - Summary of Termination Costs (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restructuring And Related Activities [Abstract]
Severance costs									$ 7,535	$ (356)	$ 2,176
Building lease									0	(17)	(70)
Stock-based compensation									1,971	0	1,664
Total termination costs	$ 6,481	$ 819	$ 2,206	$ 0	$ 0	$ (336)	$ 0	$ (37)	$ 9,506	$ (373)	$ 3,770

Selected Quarterly Financial _3

Selected Quarterly Financial Data (Unaudited) - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Line Items]
Proved and unproved impairment expense	$ 1,095,634	$ 0	$ 0	$ 0	$ 0	$ 0	$ 15,302	$ 7,312	$ 1,095,634	$ 22,614	$ 63,679
Goodwill impairment expense					1,641,197	0	0	0	0	1,641,197	0
Unproved impairment expense	1,193,711	$ 16,202	$ 12,770	$ 12,659	$ 441,750	$ 6,549	$ 54,922	$ 11,773	$ 1,235,342	$ 514,994	$ 269,725
North Louisiana Assets
Selected Quarterly Financial Information [Line Items]
Proved and unproved impairment expense	$ 2,300,000

Selected Quarterly Financial _4

Selected Quarterly Financial Data (Unaudited) - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues and other income:
Revenues and other income									$ 2,600,934	$ 3,333,837
Derivative fair value (loss) income	$ 18,491	$ 74,676	$ 195,245	$ (61,731)	$ 100,698	$ (34,591)	$ (103,290)	$ (14,009)	226,681	(51,192)	$ 213,350
Total revenues and other income	605,604	622,445	851,429	748,137	1,072,637	811,225	656,184	742,599	2,827,615	3,282,645	2,611,030
Costs and expenses:
Production and ad valorem taxes	8,963	7,805	9,889	11,310	16,656	9,427	10,140	9,926	37,967	46,149	42,882
Brokered natural gas and marketing	46,532	79,938	101,117	132,305	221,626	116,080	102,747	55,594	359,892	496,047	220,311
Exploration	9,350	11,013	8,109	8,211	10,600	8,299	7,499	7,719	36,683	34,117	53,662
Abandonment and impairment of unproved properties	1,193,711	16,202	12,770	12,659	441,750	6,549	54,922	11,773	1,235,342	514,994	269,725
General and administrative	42,793	41,047	50,631	46,638	50,090	43,722	47,583	68,417	181,109	209,812	233,406
Termination costs	6,481	819	2,206	0	0	(336)	0	(37)	9,506	(373)	3,770
Deferred compensation plan	960	(8,871)	(11,142)	3,581	(18,072)	223	6,615	(7,397)	(15,472)	(18,631)	(50,915)
Interest	44,024	46,997	51,727	51,537	49,161	54,801	53,862	52,385	194,285	210,209	195,679
Gain on early extinguishment of debt	(2,430)	(2,985)	0	0					(5,415)	0	0
Depletion, depreciation and amortization	130,869	137,751	141,505	138,718	147,909	164,266	161,026	162,266	548,843	635,467	624,992
Impairment of proved properties and other	1,095,634	0	0	0	0	0	15,302	7,312	1,095,634	22,614	63,679
Impairment of goodwill					1,641,197	0	0	0	0	1,641,197	0
Loss (gain) on sale of assets	(407)	36,341	(5,867)	189	10,815	30	(156)	(23)	30,256	10,666	(23,716)
Total costs and expenses	2,909,783	697,245	696,145	741,030	2,905,843	738,549	764,538	650,685	5,044,203	5,059,615	2,528,910
(Loss) income before income taxes	(2,304,179)	(74,800)	155,284	7,107	(1,833,206)	72,676	(108,354)	91,914	(2,216,588)	(1,776,970)	82,120
Income tax expense (benefit):
Current	2,068	4,079	0	0	0	0	0	0	6,147	0	17
Deferred	(500,927)	(51,298)	40,099	5,688	(68,784)	24,137	(28,518)	42,676	(506,438)	(30,489)	(251,043)
Total (benefit) expense for income taxes	(498,859)	(47,219)	40,099	5,688	(68,784)	24,137	(28,518)	42,676	(500,291)	(30,489)	(251,026)
Net (loss) income	$ (1,805,320)	$ (27,581)	$ 115,185	$ 1,419	$ (1,764,422)	$ 48,539	$ (79,836)	$ 49,238	$ (1,716,297)	$ (1,746,481)	$ 333,146
Net income (loss) per common share:
Basic	$ (7.27)	$ (0.11)	$ 0.46	$ 0.01	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ (6.92)	$ (7.10)	$ 1.34
Diluted	$ (7.27)	$ (0.11)	$ 0.46	$ 0.01	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ (6.92)	$ (7.10)	$ 1.34
Natural Gas, NGLs and Oil Sales
Revenues and other income:
Revenues and other income	$ 545,438	$ 474,754	$ 563,579	$ 671,654	$ 756,627	$ 736,431	$ 661,390	$ 696,629	$ 2,255,425	$ 2,851,077	$ 2,176,287
Brokered Natural Gas, Marketing and Other
Revenues and other income:
Revenues and other income	41,675	73,015	92,605	138,214	215,312	109,385	98,084	59,979	345,509	482,760	221,393
Direct Operating
Costs and expenses:
Costs and expenses	33,792	35,276	33,981	33,227	35,395	30,926	35,088	38,122	136,276	139,531	134,252
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 299,511	$ 295,912	$ 301,219	$ 302,655	$ 298,716	$ 304,562	$ 269,910	$ 244,628	$ 1,199,297	$ 1,117,816	$ 761,183

Supplemental Information on N_3

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (Detail) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Natural gas and oil properties:
Properties subject to depletion	[1]	$ 9,345,557	$ 10,974,929	$ 10,572,453
Unproved properties	[1]	868,180	2,110,277	2,644,000
Total	[1]	10,213,737	13,085,206	13,216,453
Accumulated depreciation, depletion and amortization	[1]	(4,172,702)	(4,062,021)	(3,649,716)
Natural gas and oil properties, successful efforts method, net	[1]	$ 6,041,035	$ 9,023,185	$ 9,566,737
[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Supplemental Information on N_4

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Acquisitions
Acreage purchases	[1]	$ 57,324	$ 62,390	$ 62,075
Oil and gas properties	[1]	0	1,683	18,269
Development	[1]	666,984	834,552	1,177,526
Exploration:
Exploration drilling costs incurred	[1]	0	1,380	2,030
Gas gathering facilities:
Development	[1]	3,583	10,218	15,097
Subtotal	[1]	764,574	944,340	1,328,659
Asset retirement obligations	[1]	11,193	28,826	20,245
Total costs incurred	[1]	775,767	973,166	1,348,904
Expense
Exploration:
Exploration costs incurred	[1]	35,117	32,196	50,920
Stock-based compensation expense	[1]	$ 1,566	$ 1,921	$ 2,742
[1]	Includes cost incurred whether capitalized or expensed.

Supplemental Information on N_5

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Additional Information (Detail) Bcfe in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2019USD ($)MMcfeBcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls	Dec. 31, 2018MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls	Dec. 31, 2017MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls	Dec. 31, 2016MMcfeMMcfMBbls
Reserve Quantities [Line Items]
Percentage of proved resources reviewed by consultants		90.00%
Proved reserve and pretax present value of reserve discounted		10.00%
Variance in reserve estimates		less than 5%.
Scheduled to be drilling period maximum for undeveloped reserves		scheduled to be drilled within five years
Reserve additions attributable to natural gas		83.00%	72.00%	82.00%
Proved undeveloped reserves dropped		601,300	379,000	668,000
Revision of negative pricing		17,800
Revision of positive pricing and performance			957,000
Revisions of positive pricing			154,000	46,000
Improved recoveries				597,000
Cost spent on undeveloped reserves transferred to developed reserves | $		$ 340.4
Estimated future development costs over next five years | $		$ 2,900
Proved undeveloped reserves reported for more than five years | Bcfe		86
Crude Oil and NGL
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / bbl		55.73	65.55	51.19
Crude Oil and Condensate
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		49.24	59.96	45.73
Proved developed and undeveloped reserves | MBbls		74,532	85,856	69,854	70,252
NGLs
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		17.32	25.22	17.84
Proved developed and undeveloped reserves | MBbls		938,236	921,594	763,264	630,066
Natural Gas
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / Mcf		2.38	2.98	2.60
Proved developed and undeveloped reserves | MMcf		12,114,977	12,027,702	10,263,649	7,870,416
Natural Gas, Per Thousand Cubic Feet
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / MMBTU		2.58	3.10	2.98
Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved reserves from drilling activities and evaluations of proved areas	[1]	1,161,274	3,143,898	3,487,519
Proved developed and undeveloped reserve balances	[1]	18,191,583	18,072,406	15,262,361	12,072,322
Revisions of previous estimates	[1]	303,068	731,735	506,919
Revision of positive performance		922,200		532,000
Ethane and Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve balances		2,102,000	2,075,000	1,596,000
Proved developed and undeveloped reserves | MBbls		475,000	468,900	360,600
Maximum
Reserve Quantities [Line Items]
Statement that reserve estimates differ from auditors		0.10
[1]	Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Supplemental Information on N_6

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Proved Developed and Undeveloped Reserves (Detail)		12 Months Ended
		Dec. 31, 2019MMcfeMMcfMBbls	Dec. 31, 2018MMcfeMMcfMBbls	Dec. 31, 2017MMcfeMMcfMBbls
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe		8,289,115	8,315,536
Natural Gas
Reserve Quantities [Line Items]
Beginning Balance | MMcf		12,027,702	10,263,649	7,870,416
Revisions | MMcf		33,122	178,595	70,222
Extensions, discoveries and additions | MMcf		959,901	2,269,427	2,866,103
Purchases | MMcf			0	7,738
Property sales | MMcf		(327,634)	(135,884)	(60,278)
Production | MMcf		(578,114)	(548,085)	(490,552)
Ending Balance | MMcf		12,114,977	12,027,702	10,263,649
Proved developed reserves:
Proved developed reserves | MMcf		6,486,211	6,451,012	5,437,674
Proved undeveloped reserves:
Proved undeveloped reserves | MMcf		5,628,766	5,576,690	4,825,975
NGLs
Reserve Quantities [Line Items]
Beginning Balance		921,594	763,264	630,066
Revisions		57,311	84,993	83,338
Extensions, discoveries and additions		26,505	128,436	87,572
Purchases			0	330
Property sales		(28,324)	(16,774)	(2,356)
Production		(38,850)	(38,325)	(35,686)
Ending Balance		938,236	921,594	763,264
Proved developed reserves:
Proved developed reserves		535,007	512,318	448,258
Proved undeveloped reserves:
Proved undeveloped reserves		403,229	409,276	315,006
Crude Oil and Condensate
Reserve Quantities [Line Items]
Beginning Balance		85,856	69,854	70,252
Revisions		(12,320)	7,197	(10,555)
Extensions, discoveries and additions		7,057	17,309	15,997
Purchases			0	66
Property sales		(2,371)	(4,276)	(1,121)
Production		(3,690)	(4,228)	(4,785)
Ending Balance		74,532	85,856	69,854
Proved developed reserves:
Proved developed reserves		34,369	38,658	36,808
Proved undeveloped reserves:
Proved undeveloped reserves		40,163	47,198	33,046
Natural Gas Equivalents
Proved developed reserves:
Proved developed reserves | MMcfe	[1]	9,902,468	9,756,870	8,348,074
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe	[1]	8,289,115	8,315,536	6,914,287
Beginning Balance | MMcfe	[1]	18,072,406	15,262,361	12,072,322
Revisions | MMcfe	[1]	303,068	731,735	506,919
Extensions, discoveries and additions | MMcfe	[1]	1,161,274	3,143,898	3,487,519
Purchases | MMcfe	[1]		0	10,116
Property sales | MMcfe	[1]	(511,811)	(262,180)	(81,133)
Production | MMcfe	[1]	(833,354)	(803,408)	(733,382)
Ending Balance | MMcfe	[1]	18,191,583	18,072,406	15,262,361
[1]	Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Supplemental Information on N_7

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Detail)	12 Months Ended
	Dec. 31, 2019MMcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves at December 31, 2018	8,315,536
Undeveloped reserves transferred to developed	(1,215,684)
Revisions	265,947	[1]
Sales	(214,637)
Extension and discoveries	1,137,953
Ending proved undeveloped reserves at December 31, 2019	8,289,115
[1]	Includes 601 Bcfe of proved undeveloped reserves removed and deferred due to the five-year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan.

Supplemental Information on N_8

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Parenthetical) (Detail) MMcfe in Thousands	12 Months Ended
	Dec. 31, 2019MMcfe
Extractive Industries [Abstract]
Proved undeveloped reserves removed and deferred	601

Supplemental Information on N_9

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Future cash inflows		$ 48,718,733	$ 64,287,737
Future costs:
Production		(23,320,477)	(25,626,373)
Development	[1]	(3,219,349)	(3,824,936)
Future net cash flows before income taxes		22,178,907	34,836,428
Future income tax expense		(4,179,297)	(7,285,274)
Total future net cash flows before 10% discount		17,999,610	27,551,154
10% annual discount		(11,371,037)	(16,435,560)
Standardized measure of discounted future net cash flows		$ 6,628,573	$ 11,115,594	$ 7,165,214	$ 3,451,929
[1]	2019 includes $339.1 million of undiscounted future asset retirement costs estimated as of December 31, 2019, using current estimates of future abandonment costs.

Supplemental Information on _10

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail) $ in Millions	Dec. 31, 2019USD ($)
Extractive Industries [Abstract]
Undiscounted future asset retirement costs estimation	$ 339.1

Supplemental Information on _11

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revisions of previous estimates
Changes in prices and production costs	$ (6,560,107)	$ 2,959,488	$ 2,615,825
Revisions in quantities	(12,741)	667,763	445,667
Changes in future development and abandonment costs	104,585	(686,632)	(814,215)
Net change in income taxes	1,125,639	(1,075,867)	(706,531)
Accretion of discount	1,317,349	814,725	372,743
Purchases of reserves in place	0	0	6,173
Additions to proved reserves from extensions, discoveries and improved recovery	552,710	2,543,296	2,128,135
Natural gas, NGLs and oil sales, net of production costs	(881,883)	(1,547,580)	(1,237,970)
Actual development costs incurred during the period	676,520	851,188	1,202,618
Sales of reserves in place	(688,937)	(226,953)	(32,946)
Timing and other	(120,156)	(349,048)	(266,214)
Net change for the year	(4,487,021)	3,950,380	3,713,285
Beginning of year	11,115,594	7,165,214	3,451,929
End of year	$ 6,628,573	$ 11,115,594	$ 7,165,214