Range Resources (RRC) 10-K 22 Feb 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 18, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2021
Document Fiscal Year Focus	2021
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		262,145,991
Entity Public Float			$ 4,229,441,000
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 2022 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
ICFR Auditor Attestation Flag	true
Auditor Name	Ernst & Young LLP
Auditor Firm ID	42
Auditor Location	Fort Worth, Texas

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents		$ 214,422	$ 458
Accounts receivable, less allowance for doubtful accounts of $568 and $3,004		471,775	252,642
Contingent consideration receivable		29,500	0
Derivative assets		5,738	23,332
Prepaid and other current assets		15,230	13,408
Total current assets		736,665	289,840
Derivative assets		38,601	16,680
Natural gas and oil properties, successful efforts method	[1]	10,175,570	9,751,114
Accumulated depletion and depreciation	[1]	(4,420,914)	(4,064,305)
Natural gas and oil properties, successful efforts method, net	[1]	5,754,656	5,686,809
Other property and equipment		74,678	79,878
Accumulated depreciation and amortization		(71,184)	(75,717)
Other Property and equipment, net		3,494	4,161
Operating lease right-of-use assets		40,832	63,581
Other assets		86,259	75,865
Total assets		6,660,507	6,136,936
Current liabilities:
Accounts payable		178,413	132,421
Asset retirement obligations		5,310	6,689
Accrued liabilities		420,898	348,333
Accrued interest		75,940	54,742
Derivative liabilities		162,767	26,707
Divestiture contract obligation		91,120	92,593
Current maturities of long-term debt		218,017	45,356
Total current liabilities		1,152,465	706,841
Bank debt		0	693,123
Senior notes		2,707,770	2,329,745
Senior subordinated notes		0	17,384
Deferred tax liabilities		117,642	135,267
Derivative liabilities		8,216	9,746
Deferred compensation liabilities		137,102	81,481
Operating lease liabilities		24,861	43,155
Asset retirement obligations and other liabilities		101,509	91,157
Divestiture contract obligation		325,279	391,502
Total liabilities		4,574,844	4,499,401
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, 259,795,554 issued at December 31, 2021 and 256,353,887 issued at December 31, 2020		2,598	2,563
Common stock held in treasury, at cost, 10,002,646 shares at December 31, 2021 and 10,005,795 shares at December 31, 2020		(30,007)	(30,132)
Additional paid-in capital		5,720,277	5,684,268
Accumulated other comprehensive loss		(150)	(479)
Retained deficit		(3,607,055)	(4,018,685)
Total stockholders' equity		2,085,663	1,637,535
Total liabilities and stockholders' equity		$ 6,660,507	$ 6,136,936
[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 568,000	$ 3,004,000
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	259,795,554	256,353,887
Common stock held in treasury, shares	10,002,646	10,005,795

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues and other income:
Total Revenues from Contracts with Customers	$ 3,580,439,000	$ 1,780,986,000	$ 2,600,934,000
Derivative fair value (loss) income	(650,216,000)	187,711,000	226,681,000
Total revenues and other income	2,930,223,000	1,968,697,000	2,827,615,000
Costs and expenses:
Production and ad valorem taxes	29,317,000	24,617,000	37,967,000
Brokered natural gas and marketing	367,288,000	188,316,000	359,892,000
Exploration	23,555,000	32,654,000	36,683,000
Abandonment and impairment of unproved properties	7,206,000	19,334,000	1,235,342,000
General and administrative	169,766,000	159,415,000	181,109,000
Exit and termination costs	21,661,000	547,409,000	9,506,000
Deferred compensation plan	68,351,000	12,541,000	(15,472,000)
Interest	227,336,000	192,667,000	194,285,000
Loss (gain) on early extinguishment of debt	98,000	(14,068,000)	(5,415,000)
Depletion, depreciation and amortization	364,555,000	394,330,000	548,843,000
Impairment of proved properties and other assets	0	78,955,000	1,095,634,000
(Gain) loss on the sale of assets	(701,000)	(110,791,000)	30,256,000
Total costs and expenses	2,528,188,000	2,706,026,000	5,044,203,000
Income (loss) before income taxes	402,035,000	(737,329,000)	(2,216,588,000)
Income tax (benefit) expense:
Current	7,984,000	(523,000)	6,147,000
Deferred	(17,727,000)	(25,029,000)	(506,438,000)
Total (benefit) expense for income taxes	(9,743,000)	(25,552,000)	(500,291,000)
Net income (loss)	$ 411,778,000	$ (711,777,000)	$ (1,716,297,000)
Net loss per common share:
Basic	$ 1.65	$ (2.95)	$ (6.92)
Diluted	$ 1.61	$ (2.95)	$ (6.92)
Weighted average common shares outstanding:
Basic	242,862	241,373	247,970
Diluted	249,314	241,373	247,970
Natural Gas, NGLs and Oil Sales
Revenues and other income:
Total Revenues from Contracts with Customers	$ 3,215,027,000	$ 1,607,713,000	$ 2,255,425,000
Brokered Natural Gas, Marketing and Other
Revenues and other income:
Total Revenues from Contracts with Customers	365,412,000	173,273,000	345,509,000
Direct Operating
Costs and expenses:
Costs and expenses	75,287,000	92,157,000	136,276,000
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 1,174,469,000	$ 1,088,490,000	$ 1,199,297,000

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 411,778	$ (711,777)	$ (1,716,297)
Postretirement benefits:
Actuarial gain (loss)	62	39	(532)
Amortization of prior service costs	369	369	369
Income tax (expense) benefit	(102)	(99)	33
Total comprehensive income (loss)	$ 412,107	$ (711,468)	$ (1,716,427)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating activities:
Net income (loss)	$ 411,778,000	$ (711,777,000)	$ (1,716,297,000)
Adjustments to reconcile net income (loss) to net cash provided from operating activities
Deferred income tax benefit	(17,727,000)	(25,029,000)	(506,438,000)
Depletion, depreciation and amortization and impairment of proved properties	364,555,000	473,285,000	1,644,477,000
Exploration dry hole costs	0	888,000	(11,000)
Abandonment and impairment of unproved properties	7,206,000	19,334,000	1,235,342,000
Derivative fair value loss (income)	650,216,000	(187,711,000)	(226,681,000)
Cash settlements on derivative financial instruments	(520,013,000)	(322,629,000)	(188,384,000)
Divestiture contract obligation	20,340,000	499,934,000
Allowance for bad debt	200,000	400,000	4,341,000
Amortization of deferred financing costs and other	8,347,000	6,919,000	6,455,000
Deferred and stock-based compensation	110,356,000	48,552,000	24,891,000
(Gain) loss on the sale of assets	(701,000)	(110,791,000)	30,256,000
Loss (gain) on early extinguishment of debt	98,000	(14,068,000)	(5,415,000)
Changes in working capital:
Accounts receivable	(250,538,000)	24,539,000	214,196,000
Prepaid and other	(1,140,000)	1,010,000	4,520,000
Accounts payable	39,231,000	(32,686,000)	(60,374,000)
Accrued liabilities and other	(29,260,000)	(46,748,000)	(155,803,000)
Net cash provided from operating activities	792,948,000	268,680,000	681,843,000
Investing activities:
Additions to natural gas and oil properties	(393,478,000)	(405,617,000)	(687,277,000)
Additions to field service assets	(1,231,000)	(2,873,000)	(1,162,000)
Acreage purchases	(23,962,000)	(26,816,000)	(59,986,000)
Proceeds from disposal of assets	303,000	246,127,000	784,937,000
Purchases of marketable securities held by the deferred compensation plan	(30,806,000)	(17,076,000)	(19,039,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	31,295,000	22,173,000	22,005,000
Net cash (used in) provided from investing activities	(417,879,000)	(184,082,000)	39,478,000
Financing activities:
Borrowings on credit facilities	1,434,000,000	2,076,000,000	2,311,000,000
Repayments on credit facilities	(2,136,000,000)	(1,851,000,000)	(2,777,000,000)
Issuance of senior notes	600,000,000	850,000,000
Repayment of senior or senior subordinated notes	(63,324,000)	(1,120,634,000)	(195,432,000)
Dividends paid	0		(20,070,000)
Treasury stock purchases	0	(22,992,000)	(6,908,000)
Debt issuance costs	(8,854,000)	(13,608,000)	(4,446,000)
Taxes paid for shares withheld	(9,299,000)	(3,324,000)	(3,384,000)
Change in cash overdrafts	16,493,000	176,000	(25,747,000)
Proceeds from the sales of common stock held by the deferred compensation plan	5,879,000	696,000	667,000
Net cash used in financing activities	(161,105,000)	(84,686,000)	(721,320,000)
(Decrease) increase in cash and cash equivalents	213,964,000	(88,000)	1,000
Cash and cash equivalents at beginning of year	458,000	546,000	545,000
Cash and cash equivalents at end of year	$ 214,422,000	$ 458,000	$ 546,000

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, 2018	$ 4,059,431	$ 2,495	$ (391)	$ 5,628,447	$ (1,570,462)	$ (658)
Beginning balance Shares at Dec. 31, 2018		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 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		251,439,000
Issuance of common stock	(893)	$ 49		(942)
Issuance of common stock, shares		4,896,000
Issuance of common stock upon vesting of PSUs				74	(74)
Issuance of common stock upon vesting of PSUs, shares		19,000
Stock-based compensation expense	25,400			25,400
Treasury stock issuance			96	(96)
Treasury stock repurchased	(22,992)		(22,992)
Other comprehensive income (loss)	309					309
Net loss	(711,777)				(711,777)
Ending balance at Dec. 31, 2020	$ 1,637,535	$ 2,563	(30,132)	5,684,268	(4,018,685)	(479)
Ending balance Shares at Dec. 31, 2020	256,353,887	256,354
Issuance of common stock	$ 7,033	$ 35		6,998
Issuance of common stock, shares		3,429,000
Issuance of common stock upon vesting of PSUs				148	(148)
Issuance of common stock upon vesting of PSUs, shares		13,000
Stock-based compensation expense	28,988			28,988
Treasury stock issuance			125	(125)
Other comprehensive income (loss)	329					329
Net loss	411,778				411,778
Ending balance at Dec. 31, 2021	$ 2,085,663	$ 2,598	$ (30,007)	$ 5,720,277	$ (3,607,055)	$ (150)
Ending balance Shares at Dec. 31, 2021	259,795,554	259,796

CONSOLIDATED STATEMENTS OF ST_2

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

Summary of Organization and Nat

Summary of Organization and Nature of Business	12 Months Ended
	Dec. 31, 2021
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 region of the United States. Our objective is to build stockholder value through returns focused development of natural gas and oil properties. 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, 2021
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 17 for further detail. Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, valuation of certain derivative instruments, exit cost liabilities 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. We consider our gathering, processing and marketing functions as integral to our natural gas, crude oil and condensate producing activities. 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 measure financial performance as a single enterprise and not on an area-by-area basis. All of our operating revenues, income from operations and assets are generated and located in the United States. Revenue Recognition and Accounts Receivable 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 below for a more detailed summary of our product types. 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 utilize 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. Proceeds generated from the sale of excess firm transportation to third parties is also included here when we are determined to no longer be the primary obligor of such arrangement. Our net brokered margin was income of $ 1.1 million in 2021 compared to a loss of $ 14.2 million in both 2020 and 2019. 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. Each reporting period, we assess the recoverability of material receivables using historical data and current market conditions. The loss given default method is used when, based on management’s judgement, an allowance for expected credit losses is accrued on material receivables to reflect the net amount to be collected. 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 regularly review collectability and establish or adjust our allowance as necessary. We have allowances for doubtful accounts relating to exploration and production receivables of $ 568,000 at December 31, 2021 compared to $ 3.0 million at December 31, 2020. We recorded debt expense of $ 200,000 in the year ended December 31, 2021 compared to $ 400,000 in the year ended December 31, 2020 and $ 4.3 million in the year ended December 31, 2019. 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. 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 10. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. 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. Unproved properties had a net book value of $ 837.3 million as of December 31, 2021 compared to $ 859.8 million in 2020. We have recorded abandonment and impairment expense related to unproved properties of $ 7.2 million in the year ended December 31, 2021 compared to $ 19.3 million in 2020 and $ 1.2 billion in 2019. In 2019, an impairment of $ 1.2 billion was recorded associated with our North Louisiana unproved property values that we no longer had the intent to drill based on a shift in capital allocation. 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 3. 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 $ 2.4 million in the year ended December 31, 2021 compared to $ 2.6 million in the year ended December 31, 2020 and $ 5.0 million in the year ended December 31, 2019. Leases We determine if an arrangement is a lease at the inception of the arrangement. We lease certain drilling rigs, office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. Certain of our lease agreements include lease and non-lease components. We account for these components as a single lease. Lease costs associated with drilling rigs are capitalized as part of well costs. Lease right-of-use ("ROU") assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of our lease contracts do not provide an implicit discount rate, we use our incremental borrowing rate which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at our discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with a term of 12 months or less are not recorded as a right-of-use asset and liability. The majority of our leases are classified as either short-term or long-term operating leases. 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 contractual basis. Other Assets Other assets at December 31, 2021 include $ 69.6 million of marketable securities held in our deferred compensation plans, $ 11.5 million of other investments and $ 5.2 million of deferred financing costs primarily related to our bank credit facility. Other assets at December 31, 2020 included $ 63.9 million of marketable securities held in our deferred compensation plans and $ 11.9 million of other investments. 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 11. Derivative Financial Instruments All of our commodity 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 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 commodity 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, which in an event of default, allows us to offset payables to and receivables from the defaulting counterparty. 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 derivative instruments 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 commodity derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We 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 entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. We have also 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. Our program may also include a three-way collar which is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price while the purchased put establishes the floor price until the market price for the commodity falls below the sold put stock price at which time the value of the purchased put is effectively capped. We also have the right to receive contingent consideration related to the sale of our North Louisiana assets in 2020. This derivative financial instrument is recorded as an asset in the accompanying consolidated balance sheets. This contingent consideration is based on future natural gas, NGLs and oil prices primarily based on published indexes. For additional information regarding our derivative instruments, see Note 9. 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 2021, we did not materially modify any existing derivative contracts. Concentrations of Credit Risk As of December 31, 2021, 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 customers’ 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 year ended December 31, 2021, we had one customer that accounted for 10% or more of natural gas, NGLs and oil sales compared to no ne for the year ended December 31, 2020. 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, 2021, our derivative counterparties included fifteen financial institutions and commodity traders, of which all but five are secured lenders in our bank credit facility. At December 31, 2021, our net derivative liability includes a payable to one counterparty not included in our bank credit facility totaling $ 637,000 and a receivable from the remaining four counterparties of $ 4.9 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. Historically, we have not experienced any issues of non-performance by derivative counterparties. 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 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. 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 8 for additional information. Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions. Fair value estimates are based on future discounted cash outflows required to satisfy the obligation. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, are recognized as an adjustment to the liability in the period of the change utilizing the initial discount rate. These costs, including associated accretion expense, are included in exit and termination costs in the accompanying consolidated statements of operations. See Note 15 for additional information. 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 14 for a more detailed discussion regarding our contingencies. 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 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 in the accompanying consolidated balance sheets. 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.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
Dispositions	(3) Dispositions We recognized a pretax net gain on the sale of assets of $ 701,000 in the year ended December 31, 2021 compared to a pretax gain of $ 110.8 million in 2020 and a pretax loss of $ 30.3 million in 2019. The following describes the significant divestitures that are included in our consolidated results of operations for each of three years ended December 31, 2021, 2020 and 2019. 2021 Dispositions North Louisiana. As described below, we completed the sale of our North Louisiana assets in third quarter 2020. In 2021, we recognized an additional gain on the sale of these assets of $ 479,000 which includes a gain of $ 1.9 million primarily related to final closing adjustments partially offset by a $ 1.5 million loss on settlement of royalty claims. 2020 Dispositions North Louisiana. In third quarter 2020, we completed the sale of our North Louisiana assets for total consideration having an estimated fair value of $ 260.0 million. This estimated fair value reflects (i) cash proceeds of $ 245.0 million, before normal closing adjustments and (ii) $ 15.0 million in contingent consideration which represents the estimated fair value, on August 14, 2020, of the contingent consideration we are entitled to receive in the future should certain commodity price thresholds be met. During 2020, we recorded a pretax loss of $ 9.5 million, after closing adjustments and transaction costs. The sale included: • Divestiture contingent consideration. We are entitled to receive contingent consideration, annually through 2023, based on future realization of certain natural gas and oil prices based on published indexes along with the realized NGLs price of the buyer. The fair value of the contingent consideration is classified as a current and noncurrent derivative asset on our consolidated balance sheets. We revalue the contingent consideration each reporting period, with any valuation changes being recorded as derivative fair value income or loss in our consolidated statements of operations. See also Note 9 and Note 10 for additional information. • Divestiture contract obligation. As part of this sale, we retained certain midstream gathering, transportation and processing obligations through 2030. The divestiture contract obligation is included in current or non-current liabilities in our consolidated balance sheet based on the forecasted timing of payments. These costs, along with accretion expense and any adjustments to this obligation, are recognized in exit and termination costs in our consolidated statements of operations. See also Note 10, Note 14 and Note 15 for additional information. Pennsylvania . In first quarter 2020, we completed the sale of our shallow legacy assets in Northwest Pennsylvania for proceeds of $ 1.0 million. Based upon the receipt of approval from state governmental authorities of a change in operatorship during that quarter, we recognized a pretax gain of $ 122.5 million primarily due to the elimination of the asset retirement obligation associated with these properties. 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.

Revenues from Contracts with Cu

Revenues from Contracts with Customers	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Revenues from Contracts with Customers	(4) 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, 2021 2020 2019 Natural gas sales $ 1,896,231 $ 943,740 $ 1,388,838 NGLs sales 1,135,826 578,454 681,134 Oil and condensate sales 182,970 85,519 185,453 Total natural gas, NGLs and oil sales 3,215,027 1,607,713 2,255,425 Sales of purchased natural gas 342,431 160,122 332,006 Sales of purchased NGLs 6,925 3,776 1,661 Other marketing revenue 16,056 9,375 11,842 Total $ 3,580,439 $ 1,780,986 $ 2,600,934 Performance Obligations and Contract Balance A significant number of our product sales are short-term in nature with a contract term of one year or less. We typically satisfy our performance obligation upon transfer of control and record revenue in the month production is delivered to the purchaser. Settlement statements for certain gas and NGLs sales may be received 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 three years ended December 31, 2021, 2020 and 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. 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 $ 460.2 million at December 31, 2021 compared to $ 237.8 million at December 31, 2020.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	(5) Income Taxes Our income tax benefit was $ 9.7 million for the year ended December 31, 2021 compared to $ 25.6 million in 2020 and $ 500.3 million in 2019. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2021 2020 2019 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State, net of federal benefit 4.0 5.2 3.8 State rate and law change ( 3.4 ) 4.3 1.8 Valuation allowances ( 24.8 ) ( 26.3 ) ( 3.8 ) Non-deductible equity compensation 0.8 ( 0.7 ) ( 0.2 ) Consolidated effective tax rate ( 2.4 %) 3.5 % 22.6 % Income tax expense (benefit) attributable to income (loss) before income taxes consists of the following (in thousands): 2021 2020 2019 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ 6,297 $ 6,297 $ ( 366 ) $ ( 24,489 ) $ ( 24,855 ) $ — $ ( 434,585 ) $ ( 434,585 ) U.S. state and local 7,984 ( 24,024 ) ( 16,040 ) ( 157 ) ( 540 ) ( 697 ) 6,147 ( 71,853 ) ( 65,706 ) Total $ 7,984 $ ( 17,727 ) $ ( 9,743 ) $ ( 523 ) $ ( 25,029 ) $ ( 25,552 ) $ 6,147 $ ( 506,438 ) $ ( 500,291 ) Significant components of deferred tax assets and liabilities are as follows: December 31, 2021 2020 (in thousands) Deferred tax assets: Net operating loss carryforward $ 788,375 $ 879,339 Divestiture contract obligation 112,199 132,352 Deferred compensation 22,121 16,635 Equity compensation 4,833 5,445 Asset retirement obligations 21,734 18,923 Interest expense carryforward 53,876 15,757 Lease right-of-use assets 9,954 16,070 Cumulative mark-to-market loss 32,221 2,607 Other 12,181 12,082 Valuation allowances: Federal ( 67,984 ) ( 152,499 ) State, net of federal benefit ( 203,085 ) ( 226,520 ) Total deferred tax assets 786,425 720,191 Deferred tax liabilities: Depreciation and depletion ( 879,163 ) ( 835,506 ) Operating lease liabilities ( 9,247 ) ( 15,058 ) Other ( 15,657 ) ( 4,894 ) Total deferred tax liabilities ( 904,067 ) ( 855,458 ) Net deferred tax liability $ ( 117,642 ) $ ( 135,267 ) At December 31, 2021, deferred tax liabilities exceeded deferred tax assets by $ 117.6 million. As of December 31, 2021, we have a state valuation allowance of $ 203.1 million related to state tax attributes in Louisiana, Oklahoma, Pennsylvania, Texas and West Virginia. As of December 31, 2021, we have federal valuation allowances of $ 68.0 million primarily related to our federal net operating loss carryforward (“NOL”), and federal basis differences. The net change in our deferred tax asset valuation allowances was a reduction of $ 108.0 million for the year ended December 31, 2021 compared to an increase in our valuation allowances of $ 188.2 million in 2020 and an increase of $ 70.5 million in 2019. At December 31, 2021, we had federal NOL carryforwards of $ 2.9 billion. This includes $ 1.2 billion that expires between 2030 and 2037 and also includes $ 1.7 billion of NOL carryforwards generated after 2017 that do not expire. We have state NOL carryforwards in Pennsylvania of $ 861.0 million that expire between 2028 and 2040 and in Louisiana, we have state NOL carryforwards of $ 1.5 billion that do not expire. 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 2018 and after and we are subject to various state tax examinations for years 2017 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 no t have any accrued interest or penalties related to tax amounts as of December 31, 2021. Throughout 2021, 2020 and 2019, our unrecognized tax benefits were not material.

Net Income (Loss) Per Common Sh

Net Income (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Net Income (Loss) Per Common Share	(6) 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, 2021 2020 2019 Net income (loss), as reported $ 411,778 $ ( 711,777 ) $ ( 1,716,297 ) Participating basic earnings (a) ( 10,795 ) — ( 251 ) Basic net income (loss) attributed to common stockholders 400,983 ( 711,777 ) ( 1,716,548 ) Reallocation of participating earnings (a) 272 — — Diluted net income (loss) attributed to common stockholders $ 401,255 $ ( 711,777 ) $ ( 1,716,548 ) Net income (loss) per common share: Basic $ 1.65 $ ( 2.95 ) $ ( 6.92 ) Diluted $ 1.61 $ ( 2.95 ) $ ( 6.92 ) (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 details basic weighted average common shares outstanding and diluted weighted average common shares outstanding (in thousands): Year Ended December 31, 2021 2020 2019 Denominator: Weighted average common shares outstanding – basic 242,862 241,373 247,970 Effect of dilutive securities 6,452 — — Weighted average common shares outstanding – diluted 249,314 241,373 247,970 Weighted average common shares outstanding – basic excludes 6.5 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, 2021 compared to 5.5 million shares for the period ending December 31, 2020 and 3.1 million shares for the period ending December 31, 2019. Due to our net loss for the years ended December 31, 2020 and 2019, 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 18,000 for the year ended December 31, 2021 were outstanding but not included in the computation of diluted net income because the grant prices were greater than the average market price of the common shares and would be anti-dilutive to the computations.

Indebtedness

Indebtedness	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Indebtedness	(7) Indebtedness We had the following debt outstanding as of the dates shown below. The expenses of issuing debt are generally capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. For December 31, 2021, deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. 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 in the three-year period ended December 31, 2021. The components of our debt outstanding, including the effects of debt issuance costs, is as follows (in thousands): December 31, 2021 2020 Bank debt $ — $ 702,000 Senior notes 4.875 % senior notes due 2025 750,000 750,000 5.00 % senior notes due 2022 169,589 169,589 5.00 % senior notes due 2023 532,335 532,335 5.75 % senior notes due 2021 — 25,496 5.875 % senior notes due 2022 48,528 48,528 8.25 % senior notes due 2029 600,000 — 9.25 % senior notes due 2026 850,000 850,000 Other senior notes due 2022 — 490 Total senior notes 2,950,452 2,376,438 Senior subordinated notes 5.00 % senior subordinated notes due 2022 — 9,730 5.00 % senior subordinated notes due 2023 — 7,712 5.75 % senior subordinated notes due 2021 — 19,896 Total senior subordinated notes — 37,338 Total debt 2,950,452 3,115,776 Unamortized premium 188 457 Unamortized debt issuance costs ( 24,853 ) ( 30,625 ) Total debt (net of debt issuance costs) 2,925,787 3,085,608 Less current maturities of long-term debt ( 218,017 ) ( 45,356 ) Total long-term debt $ 2,707,770 $ 3,040,252 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 and has a maturity date of April 13, 2023 . The bank credit facility provides for a maximum facility amount of $ 4.0 billion and an initial borrowing base of $ 3.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations and for event-driven unscheduled redeterminations. Our current bank group is composed of twenty-six financial institutions, with no one bank holding more than 8.3 % 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. 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 0.75 % to 1.75 % or at the LIBOR Rate (as defined in the bank credit agreement) plus a spread ranging from 1.75 % to 2.75 %. 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 2.1 % for the year ended December 31, 2021 compared to 2.6 % for the year ended December 31, 2020 and 3.8 % for the year ended December 31, 2019. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30 % to 0.375 %. At December 31, 2021, the commitment fee was 0.3 %, the interest rate margin was 1.75 % on our LIBOR loans and 0.75 % on our ABR loans. On December 31, 2021, bank commitments totaled $ 2.4 billion and we had no outstanding borrowings under our bank credit facility. Additionally, we had $ 338.0 million of undrawn letters of credit leaving $ 2.1 billion of committed borrowing capacity available under the facility. As part of our redetermination completed in September 2021, our borrowing base was reaffirmed for $ 3.0 billion and our bank commitment was also reaffirmed at $ 2.4 billion. As of February 18, 2022, we have sufficient available borrowing capacity under our credit facility to satisfy any requests for additional collateral our transportation counterparties may request in the event of a credit rating downgrade. New Senior Notes In January 2021, we issued $ 600.0 million aggregate principal amount of 8.25 % senior notes due 2029 (the “ 8.25 % Notes”) for an estimated net proceeds of $ 591.3 million after underwriting discounts and commissions of $ 8.8 million. The notes were issued at par. The 8.25 % 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 under the Securities Act of 1933, as amended (the “Securities Act”). Interest due on the 8.25 % Notes is payable semi-annually in January and July and is unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors. On or after January 15, 2027, we may redeem the 8.25 % Notes in whole or in part 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 8.25 % Notes. Upon occurrence of certain changes in control, we must offer to repurchase the 8.25 % Notes. The 8.25 % 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. Upon closing of the 8.25 % Notes, we used the proceeds to repay borrowings under our bank credit facility. In October 2021, our 8.25% Notes were exchanged for an equal principal amount of registered notes pursuant to an effective registration statement on Form S-4 filed with the SEC on October 28, 2021 under the Securities Act (the "New Notes"). The New Notes are identical to the 8.25% Notes except the New Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. In January 2022, we issued $ 500.0 million aggregate principal amount of 4.75 % senior notes due 2030 (the “4.75% Notes”) for an estimated net proceeds of $ 492.1 million after underwriting discounts and commissions of $ 7.9 million. The notes were issued at par. The 4.75 % Notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A (for life) and Regulation S under the Securities Act. Interest due on the 4.75 % 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, 2027, we may redeem the 4.75 % 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 4.75% Notes. Upon occurrence of certain changes in control, we must offer to repurchase the 4.75 % Notes. The 4.75 % 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 4.75 % Notes, we used these proceeds, along with cash on hand and our bank credit facility to redeem $ 850.0 million of our 9.25 % senior notes due 2026. Early Extinguishment of Debt in 2022 In January 2022, we announced a call for the redemption of $ 850.0 million of our outstanding 9.25% senior notes due 2026 at a price of 106.938 % of par plus accrued and unpaid interest, which were redeemed on February 1, 2022. For the year ending December 31, 2022, we currently expect to record a loss of early extinguishment of debt of approximately $ 70.0 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt. Senior Notes If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior notes at 101 % of the principal amount plus accrued and unpaid interest, if any. All of 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 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, 2021. Certain of our senior notes may also limit our ability to pay cash dividends. The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2021 (in thousands): Year Ended 2022 $ 218,117 2023 532,335 2024 — 2025 750,000 2026 850,000 Thereafter 600,000 $ 2,950,452

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(8) 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, 2021 and 2020 (in thousands): 2021 2020 Beginning of period $ 79,822 $ 251,076 Liabilities incurred 73 1,483 Acquisitions — 123 Liabilities settled ( 8,197 ) ( 4,634 ) Disposition of wells — ( 176,748 ) Accretion expense 5,511 7,518 Change in estimate 18,627 1,004 End of period 95,836 79,822 Less current portion ( 5,310 ) ( 6,689 ) Long-term asset retirement obligations $ 90,526 $ 73,133 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, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Activities	(9) 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 liability of $ 169.5 million at December 31, 2021. These contracts expire monthly through December 2023. The following table sets forth the derivative volumes by year as of December 31, 2021, excluding our basis, freight swaps and divestiture contingent consideration which are discussed separately below: Period Contract Type Volume Hedged Weighted Average Hedge Price Swap Sold Put Floor Ceiling Natural Gas (1) 2022 Swaps 497,479 Mmbtu/day $ 3.12 2022 Collars 224,301 Mmbtu/day $ 3.28 $ 3.73 2022 Three-way Collars 251,781 Mmbtu/day $ 2.37 $ 3.03 $ 3.77 January-March 2022 Calls 80,000 Mmbtu/day $ 6.02 2023 Swaps 197,500 Mmbtu/day $ 3.40 2023 Collars 110,000 Mmbtu/day $ 3.26 $ 4.26 2023 Three-way Collars 70,000 Mmbtu/day $ 2.25 $ 3.25 $ 4.28 Crude Oil 2022 Swaps 6,437 bbls/day $ 60.73 2023 Swaps 623 bbls/day $ 66.40 NGLs (C5-Natural Gasoline) January-June 2022 Swaps 2,749 bbls/day $ 1.65 /gallon January-June 2022 Collars 1,497 bbls/day $ 1.53 /gallon $ 1.67 /gallon (1) We also sold natural gas call swaptions of 72,500 Mmbtu/day for 2023 at a weighted average price of $ 3.06 per Mmbtu. Basis Swap Contracts In addition to the swaps, collars and swaptions above, at December 31, 2021, 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 2024 and include a total volume of 213,710,000 Mmbtu. The fair value of these contracts was a net derivative asset of $ 16.0 million on December 31, 2021. At December 31, 2021, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indexes. The contracts settle monthly in first quarter 2022. The fair value of these contracts was a net derivative asset of $ 123,000 on December 31, 2021. Freight Swap Contracts In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at December 31, 2021, 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 7,000 metric tons for first quarter 2022. The fair value of these contracts was a net derivative asset of $ 114,000 on December 31, 2021. Divestiture Contingent Consideration In addition to the derivatives described above, our right to receive contingent consideration in conjunction with the sale of our North Louisiana assets was determined to be a derivative financial instrument that is not designated as a hedging instrument. The contingent consideration of up to $ 45.5 million is based on future realization of natural gas and oil prices based on published indexes and realized NGLs prices of the buyer for the years 2022 and 2023. All changes in the fair value are recognized as a gain or loss in earnings in the period they occur in derivative fair value income or loss in our consolidated statements of operations. The fair value of this instrument on December 31, 2021 was a derivative asset of $ 26.6 million. In addition, we currently expect to receive $ 29.5 million for the year ended December 31, 2021 which is reflected in current assets in the accompanying consolidated balance sheet and represents the maximum contingent payment amount for 2021. Derivative Assets and Liabilities The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2021 and 2020 is summarized below (in thousands). As of December 31, 2021, we are conducting derivative activities with fifteen counterparties, of which all but five 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, 2021 Gross Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 22,491 $ ( 18,111 ) $ 4,380 –collars 12,378 ( 8,600 ) 3,778 –three-way collars 12,234 ( 8,449 ) 3,785 –basis swaps 18,092 ( 10,487 ) 7,605 Crude oil –swaps 368 ( 2,153 ) ( 1,785 ) NGLs –C3 propane spread 4,153 ( 4,153 ) — –C5 natural gasoline swaps 266 ( 363 ) ( 97 ) –C5 natural gasoline collars 221 ( 221 ) — Freight –swaps 114 ( 81 ) 33 Divestiture contingent consideration 26,640 — 26,640 $ 96,957 $ ( 52,618 ) $ 44,339 December 31, 2021 Gross Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ ( 121,759 ) $ 18,111 $ ( 103,648 ) –swaptions ( 11,149 ) — ( 11,149 ) –collars ( 16,579 ) 8,600 ( 7,979 ) –three-way collars ( 37,166 ) 8,449 ( 28,717 ) –calls ( 61 ) — ( 61 ) –basis swaps ( 2,064 ) 10,487 8,423 Crude oil –swaps ( 27,252 ) 2,153 ( 25,099 ) NGLs –C3 propane spread ( 4,030 ) 4,153 123 –C5 natural gasoline swaps ( 2,048 ) 363 ( 1,685 ) –C5 natural gasoline collars ( 1,493 ) 221 ( 1,272 ) Freight –swaps — 81 81 $ ( 223,601 ) $ 52,618 $ ( 170,983 ) December 31, 2020 Gross Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 33,559 $ ( 16,821 ) $ 16,738 –collars 7,016 ( 2,329 ) 4,687 –three-way collars 535 ( 6,139 ) ( 5,604 ) –basis swaps 7,894 ( 3,502 ) 4,392 Crude oil –swaps 2,465 ( 829 ) 1,636 NGLs –C3 propane spread 4,863 ( 4,863 ) — –C3 propane collars — ( 107 ) ( 107 ) Freight –swaps 2,310 — 2,310 Divestiture contingent consideration 15,960 — 15,960 $ 74,602 $ ( 34,590 ) $ 40,012 December 31, 2020 Gross Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ ( 10,120 ) $ 16,821 $ 6,701 –swaptions ( 9,803 ) — ( 9,803 ) –collars — 2,329 2,329 –three-way collars ( 18,353 ) 6,139 ( 12,214 ) –basis swaps ( 4,197 ) 3,502 ( 695 ) Crude oil –swaps ( 5,471 ) 829 ( 4,642 ) NGLs –C3 propane spread ( 4,069 ) 4,863 794 –C3 propane swaps ( 8,243 ) — ( 8,243 ) –C3 propane collars ( 3,086 ) 107 ( 2,979 ) –C5 natural gasoline swaps ( 4,897 ) — ( 4,897 ) –C5 natural gasoline calls ( 546 ) — ( 546 ) –NC4 butane swaps ( 651 ) — ( 651 ) –NC4 butane collars ( 401 ) — ( 401 ) Freight –swaps ( 1,206 ) — ( 1,206 ) $ ( 71,043 ) $ 34,590 $ ( 36,453 ) The effects of our derivatives on our consolidated statements of operations for the last three years are summarized below (in thousands). Derivative Fair Value (Loss) Income Year Ended December 31, 2021 2020 2019 Commodity swaps $ ( 466,203 ) $ 158,248 $ 219,968 Swaptions ( 1,346 ) ( 4,955 ) 333 Collars ( 117,612 ) 3,304 ( 3,903 ) Three-way collars ( 137,443 ) ( 16,346 ) — Basis swaps 33,691 48,278 6,661 Calls ( 836 ) ( 558 ) ( 349 ) Freight swaps ( 647 ) ( 1,230 ) 3,971 Divestiture contingent consideration 40,180 970 — Total $ ( 650,216 ) $ 187,711 $ 226,681

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value Measurements	(10) 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, 2021 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred $ 69,606 $ — $ — $ 69,606 Derivatives –swaps — ( 127,934 ) — ( 127,934 ) –calls — ( 61 ) — ( 61 ) –collars — ( 4,201 ) ( 1,272 ) ( 5,473 ) –three-way collars — ( 24,932 ) — ( 24,932 ) –basis swaps — 16,151 — 16,151 –swaptions — — ( 11,149 ) ( 11,149 ) Derivatives –freight swaps — 114 — 114 Divestiture contingent consideration — 26,640 — 26,640 Fair Value Measurements at December 31, 2020 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred $ 63,942 $ — $ — $ 63,942 Derivatives –swaps — 6,642 — 6,642 –calls — — ( 546 ) ( 546 ) –collars — 7,016 ( 3,487 ) 3,529 –three-way collars — ( 17,818 ) — ( 17,818 ) –basis swaps — 4,491 — 4,491 –swaptions — — ( 9,803 ) ( 9,803 ) Derivatives –freight swaps — 1,104 — 1,104 Divestiture contingent consideration — 15,960 — 15,960 Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2021 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. 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. As of December 31, 2021, 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. In addition to our swaptions in Level 3, at December 31, 2021, we have NGLs collars. Subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our derivatives in Level 3. For our natural gas swaptions, we used a weighted average implied volatility of 25 %. We utilized a range of implied volatilities from 37 % to 61 % for our NGLs collars with a weighted average implied volatility of approximately 45 %. 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 Balance at December 31, 2020 $ ( 13,836 ) Additions ( 12,420 ) Settlements 5,176 Transfers out of Level 3 8,660 Balance at December 31, 2021 $ ( 12,420 ) 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, 2021, interest and dividends were $ 951,000 and mark-to-market was a gain of $ 3.0 million. For the year ended December 31, 2020, interest and dividends were $ 713,000 and mark-to-market was a gain of $ 6.3 million. 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. Divestiture Contingent Consideration. In August 2020, we completed the sale of our North Louisiana assets where we are entitled to receive contingent consideration, based on future realization of natural gas and oil prices based on published indexes along with NGLs prices based on the realized NGLs prices of the buyer. We used an option pricing model to estimate the fair value of the contingent consideration using significant Level 2 inputs that include quoted future commodity prices based on active markets. See also Note 3 and Note 9 for additional information. Fair Values-Non recurring 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, we recorded an impairment of $ 1.1 billion. An additional guideline transaction market approach was also utilized to corroborate the estimated fair value. In first quarter 2020, we recognized an additional impairment charge of $ 77.0 million related to these North Louisiana properties that reduced the carrying value to the anticipated sales proceeds which is a market approach using Level 2 inputs. See also Note 3 for additional information. 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, 2021 2020 2019 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ — $ — $ 290,500 $ 77,000 $ 370,500 $ 1,093,531 North Louisiana Divestiture Contract Obligation. In 2020, we recorded a divestiture contract obligation in conjunction with the sale of our North Louisiana assets. The fair value of this obligation was determined as of the closing date using Level 3 inputs based on a probability-weighted forecast that considers historical results, market conditions and various potential development plans of the buyer to arrive at the estimated present value of the future payments. Inherent in this fair value calculation were numerous other assumptions and judgements including the credit-adjusted discount rate as well as the development plans of the buyer and our probability weighted forecast of those drilling plans, market conditions and the ultimate usage by the buyer of each facility included in the agreement, all of which are inherently uncertain and can alter the amount and timing of future payments. A significant portion of this obligation is a gas processing agreement that includes a deficiency payment if the minimum volume commitment is not met. The present value of future cash payments was determined using a 12 percent discount rate. See also Note 15 for additional information. Leases. As part of our ongoing effort to reduce general and administrative expense due to both the lower commodity price environment and in conjunction with the sale of our North Louisiana assets, we vacated one floor in our Fort Worth headquarters. We recorded an impairment related to this lease of $ 2.0 million which is included in impairment of proved property and other assets in our consolidated statement of operations for the year ended December 31, 2020. In fourth quarter 2019, we announced the closing of our Houston office. We recorded an impairment related to our Houston office lease ROU asset of $ 2.1 million which is also included in impairment of proved property and other assets for the year ended December 31, 2019. Fair Values-Reported The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2021 and 2020 (in thousands): December 31, 2021 December 31, 2020 Carrying Fair Carrying Fair Assets: Commodity swaps, collars, calls and basis swaps $ 17,699 $ 17,699 $ 24,052 $ 24,052 Divestiture contingent consideration 26,640 26,640 15,960 15,960 Marketable securities (a) 69,606 69,606 63,942 63,942 (Liabilities): Commodity swaps, collars, calls and basis swaps ( 170,983 ) ( 170,983 ) ( 36,453 ) ( 36,453 ) Bank credit facility (b) — — ( 702,000 ) ( 702,000 ) 5.75 % senior notes due 2021 (b) — — ( 25,496 ) ( 25,474 ) 5.00 % senior notes due 2022 (b) ( 169,589 ) ( 171,488 ) ( 169,589 ) ( 170,128 ) 5.875 % senior notes due 2022 (b) ( 48,528 ) ( 48,955 ) ( 48,528 ) ( 48,471 ) Other senior notes due 2022 (b) — — ( 490 ) ( 490 ) 5.00 % senior notes due 2023 (b) ( 532,335 ) ( 543,471 ) ( 532,335 ) ( 521,699 ) 4.875 % senior notes due 2025 (b) ( 750,000 ) ( 776,153 ) ( 750,000 ) ( 707,918 ) 9.25 % senior notes due 2026 (b) ( 850,000 ) ( 916,929 ) ( 850,000 ) ( 888,208 ) 8.25 % senior notes due 2029 (b) ( 600,000 ) ( 669,648 ) — — 5.75 % senior subordinated notes due 2021 (b) — — ( 19,896 ) ( 19,589 ) 5.00 % senior subordinated notes due 2022 (b) — — ( 9,730 ) ( 9,247 ) 5.00 % senior subordinated notes due 2023 (b) — — ( 7,712 ) ( 6,604 ) Deferred compensation plan (c) ( 165,395 ) ( 165,395 ) ( 96,563 ) ( 96,563 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and is updated based on end of period closing prices which is a Level 1 input. (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. Non-financial liabilities initially measured at fair value include asset retirement obligations, operating lease liabilities and the divestiture contract obligation that we incurred in conjunction with the sale of our North Louisiana assets.

Stock-based Compensation Plans

Stock-based Compensation Plans	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Stock-based Compensation Plans	(11) Stock-Based Compensation Plans Description of the Plans We have two active equity-based stock plans, our Amended and Restated 2005 Equity-Based Compensation Plan, which we refer to as the 2005 Plan and the Amended and Restated 2019 Equity-Based Compensation Plan, which we refer to as the 2019 Plan. Under these plans, the Compensation Committee of the board of directors may grant, various 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, 2021 (in thousands): 2021 2020 2019 Direct operating expense $ 1,310 $ 1,078 $ 1,928 Brokered natural gas and marketing expense 1,794 1,416 1,856 Exploration expense 1,507 1,279 1,566 General and administrative expense 39,673 32,905 35,061 Termination costs — 2,165 1,971 Total stock-based compensation $ 44,284 $ 38,843 $ 42,382 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 2021, we recorded an additional tax benefit of an estimated $ 340,000 for the tax effect of financial accounting expense compared to the corporate income tax deduction for equity compensation that vested during the year compared to additional tax expense of $ 4.3 million in 2020 and additional tax expense of $ 3.4 million in 2019. 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 period and are contingent on the recipient’s continued employment. These awards are net settled by withholding shares to satisfy income tax withholding payments due upon vesting. The remaining shares are remitted to individual brokerage accounts. The grant date fair value of the Equity Awards is based on the fair market value of our common stock on the date of grant. Shares to be delivered upon vesting are made available from authorized but unissued shares or shares held as treasury stock. 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 one year after grant date 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, if any, 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 re-measured 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 two types of performance share awards: one based on performance conditions measured against internal performance metrics and one based on market conditions measured based on Range’s performance relative to a predetermined peer group. 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 payout 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 three year s. Restricted Stock – Equity Awards In 2021, we granted 2.3 million restricted stock Equity Awards to employees which generally vest over a three-year period compared to 4.5 million in 2020 and 2.8 million in 2019. We recorded compensation expense for these awards of $ 19.6 million in the year ended December 31, 2021 compared to $ 17.8 million in 2020 and $ 22.5 million in 2019. As of December 31, 2021, there was $ 19.0 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.8 years. Restricted stock Equity Awards are not issued to employees until such time as they are vested and the employees do not have the option to receive cash. Restricted Stock – Liability Awards In 2021, we granted 1.3 million shares of restricted stock Liability Awards as compensation to directors and employees at an average grant date fair value of $ 9.56 . These grants included 102,000 shares issued to non-employee directors, which vest at the end of one year and 1.2 million shares to employees with vesting generally over a three-year period. In 2020, we granted 3.5 million shares of restricted stock Liability Awards as compensation to directors and employees at an average grant date fair value of $ 3.18 . This grant included 217,000 shares issued to non-employee directors, which vested at the end of one year and 3.3 million shares to employees with vesting generally over a three-year period. In 2019, we granted 1.2 million shares of restricted stock Liability Awards as compensation to directors and employees at an average grant date fair value of $ 10.16 . These grants included 183,000 shares issued to non-employee directors, which vested immediately and 1.0 million shares to employees with vesting generally over a three-year period. We recorded compensation expense for these restricted stock Liability Awards of $ 11.4 million in the year ended December 31, 2021 compared to $ 10.3 million in 2020 and $ 9.3 million in 2019. As of December 31, 2021, there was $ 4.4 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of 1.4 years. A large portion of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan were $ 5.9 million in 2021 compared to $ 696,000 in 2020 and $ 667,000 in 2019. The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2021: Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2020 2,815,860 $ 4.97 1,186,636 $ 4.18 Granted 2,340,114 10.20 1,289,495 9.56 Vested ( 2,397,336 ) 7.33 ( 1,679,502 ) 7.21 Forfeited ( 83,861 ) 6.32 — — Outstanding at December 31, 2021 2,674,777 $ 7.39 796,629 $ 6.49 Stock-Based Performance Units Internal Performance Metric Awards. Awards granted in 2019 and 2020 were earned based on: • Debt and adjusted per share Production Growth • Debt and adjusted per share Reserve Growth Internal performance metric awards granted in 2021 are earned based on: • Debt/EBITDAX (earnings before interest, taxes, depreciation and amortization, and exploration expense) • GHG emissions intensity Prior to 2021, the performance period was based on annual performance targets earned over a three-year period. For awards granted in 2021, the three-year target was set in first quarter 2021. If the performance metric for the applicable period is not met, then that portion is considered forfeited and there is an adjustment to the expense recorded. The following is a summary of our non-vested internal performance metric awards activities at December 31, 2021: Number of Weighted Outstanding at December 31, 2020 1,099,102 $ 5.92 Units granted (a) 303,231 9.81 Vested ( 306,978 ) 12.20 Forfeited (b) — — Outstanding at December 31, 2021 1,095,355 $ 7.80 (a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 20 0% depending on achievement of specifically identified performance targets. (b) For Production Growth units granted in 2019 which are set to vest in early 2022, the payout is estimated at 74 %. For Reserve Growth units granted in 2019 which are set to vest in early 2022, the payout is estimated at 121 %. We recorded internal performance metric award compensation expense of $ 6.6 million in the year ended December 31, 2021 compared to $ 2.7 million in the year ended December 31, 2020 and $ 3.8 million in the year ended December 31, 2019. As of December 31, 2021, there was $ 2.6 million of unrecognized compensation related to these internal performance metric awards to be recognized over a weighted average period of 1.4 years. TSR Awards. These awards 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. Their fair value 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 performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of the TSR awards granted during the years ended December 31, 2021, 2020 and 2019: Year Ended December 31, 2021 2020 2019 Risk-free interest rate 0.2 % 1.4 % 2.4 % Expected annual volatility 75 % 65 % 46 % Grant date fair value per unit $ 12.58 $ 3.85 $ 11.34 The following is a summary of our non-vested TSR award activities: Number of Units Weighted Outstanding at December 31, 2020 1,249,524 $ 9.55 Granted (a) 223,687 12.58 Vested and issued (b) ( 325,217 ) 18.51 Forfeited — — Outstanding at December 31, 2021 1,147,994 $ 7.60 (a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 200 % of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date. (b) Includes TSR-PSUs awards issued related to the 2018 performance period where the return on our common stock was negative and therefore, the performances multiple and actual payout was reduced to 100 %. We recorded TSR award compensation expense of $ 2.6 million in the year ended December 31, 2021 compared to $ 2.4 million in the year ended December 31, 2020 and $ 3.0 million in the year ended December 31, 2019. As of December 31, 2021, there was $ 1.5 million of unrecognized compensation related to these TSR awards to be recognized over a weighted average period of 1.5 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 2021, we contributed $ 4.6 million to the 401(k) Plan compared to $ 5.3 million in 2020 and $ 5.4 million in 2019. 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 loss of $ 68.4 million in 2021 compared to a loss of $ 12.5 million in 2020 and a gain of $ 15.5 million in 2019. The Rabbi Trust held 6.2 million shares ( 5.4 million of vested shares) of Range stock at December 31, 2021 compared to 6.1 million ( 5.0 million of vested shares) at December 31, 2020. Other Post-Retirement Benefits We have 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: 2021 2020 Benefit obligation at beginning of year $ 1,953 $ 1,957 Service cost 77 80 Interest cost 38 50 Actuarial (gain) loss ( 62 ) ( 39 ) Benefits paid ( 88 ) ( 95 ) Benefit obligation at end of year $ 1,918 $ 1,953 Amounts recognized in the consolidated balance sheet: Long-term liabilities $ 1,918 $ 1,953 Components of Net Periodic Post Retirement Benefit Cost: Service cost $ 77 $ 80 Interest cost 38 50 Amortization of prior service cost 369 369 Net periodic post retirement costs (recognized in general and $ 484 $ 499 Other Changes in Benefit Obligations in Other Comprehensive Net (gain) loss $ ( 62 ) $ ( 39 ) Prior service cost — — Amortization of prior service cost ( 369 ) ( 369 ) Total recognized in other comprehensive (loss) income $ ( 431 ) $ ( 408 ) Total recognized in net periodic benefit cost and other comprehensive $ 53 $ 91 The following summarizes the assumptions used to determine the benefit obligation at December 31, 2021 and 2020: December 31, December 31, Weighted average assumptions used to determine benefit obligation: Discount rate 2.5 % 1.9 % Assumed weighted average healthcare cost trend rates: Initial healthcare trend rate 7.0 % 6.5 % Ultimate trend rate 4.0 % 4.5 % Year ultimate trend rate reached 2033 2024 The expected future benefit payments under our post-retirement benefit plan is $ 768,000 for the five year period 2022 through 2026 and $ 458,000 for the five year period 2027 through 2031. The estimated prior service cost that will be amortized from accumulated other comprehensive loss into our statements of operations in 2022 is $ 369,000 .

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Capital Stock	(12) 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 2020: Year Ended December 31, 2021 2020 Beginning balance 246,348,092 249,630,803 Restricted stock grants 1,293,892 3,390,358 Restricted stock units vested 1,493,341 1,226,473 Performance stock units issued 640,468 279,420 Performance stock dividends 13,966 18,700 Treasury shares 3,149 ( 8,197,662 ) Ending balance 249,792,908 246,348,092 Common Stock Dividends The board of directors declared quarterly dividends of $ 0.02 per common share for each of the four quarters of 2019. In January 2020, we announced that the board had suspended the dividend. We expect the quarterly cash dividend will be reinstated in the second half of 2022. 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 allows for the payment of common dividends, with certain limitations, as described in the facility agreement. Stock Repurchase Program In October 2019, the board of directors approved a stock purchase program to acquire up to $ 100 million of our outstanding stock. In early 2022, the board approved an increase to this stock purchase plan where the board of directors authorized an additional repurchase of up to $ 500.0 million. The following is a schedule of the change in treasury shares since the beginning of 2020: Year Ended December 31, 2021 2020 Beginning balance 10,005,795 1,808,133 Rabbi trust shares distributed and/or sold ( 3,149 ) ( 2,338 ) Shares repurchased — 8,200,000 Ending balance 10,002,646 10,005,795

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(13) Supplemental Cash Flow Information Year Ended December 31, 2021 2020 2019 (in thousands) Net cash provided from operating activities included: Income taxes paid to taxing authorities $ 7,061 $ 343 $ — Interest paid ( 196,750 ) ( 168,471 ) ( 189,443 ) Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 18,634 $ 2,610 $ 11,193 Decrease in accrued capital expenditures ( 4,505 ) ( 23,625 ) ( 20,104 )

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(14) Commitments and Contingencies Litigation We are the subject of, or party to, a number of pending or threatened legal actions and administrative proceedings or investigations 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 establish reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible 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, 2021 and 2020, liabilities for remediation were not material. We are not aware of any environmental claims existing as of December 31, 2021 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. On March 4, 2021 a putative class action lawsuit was filed in the Western District of Pennsylvania in Case No. 2:21-CV-301 (Jacobowitz v. Range Resources Corporation et al.) in which the Plaintiff seeks to represent a class of Range stockholders who purchased or acquired stock from April 29, 2016 to February 10, 2021. This lawsuit was transferred to the U.S. District Court for the Northern District of Texas (Fort Worth Division). The lawsuit claims that Range misclassified certain wells as inactive rather than having plugged the wells and that such alleged misclassification affected the determination of our asset retirement obligation accrual. The lawsuit claims that the disclosure of a $ 294,000 agreed penalty that we paid to the Pennsylvania Department of Environmental Protection (DEP) in connection with the DEP’s investigation of our application for inactive status for a small number of our wells, which the DEP disclosed during market hours on February 10, 2021 was the basis for the Plaintiffs’ discovery of the alleged misrepresentations. We maintain that the factual allegations and the claims made in the litigation are baseless; there were no misrepresentations made and our asset retirement obligation was properly calculated. We also maintain that the market fully absorbed the information disclosed by the DEP on February 10, 2021 and the stock price on tha t day did not decrease. Given our view of the litigation as baseless, we are vigorously defending the litigation and moved for its dismissal. Additionally, on January 20, 2022, a derivative action styled as Lewis v. Ventura et al. was filed under seal in the Northern District of Texas (Case No. 4-22CV-051-0) asserting similar allegations as the previously described Jacobowitz matter. We maintain the same views as to the merits of the Lewis matter as the Jacobowitz matter as more fully detailed above and we plan to vigorously defend the matter. Obligations Following Divestitures Certain contractual obligations were retained by us after our divestiture of our North Louisiana assets. These obligations are primarily related to gathering, processing and transportation agreements including certain minimum volume commitments. For additional information see Note 3, Note 10 and Note 15. Lease Commitments The components of our total lease expense for the two years ended December 31, 2021, the majority of which is included in general and administrative expense, are as follows (in thousands): Year Ended December 31, 2021 2020 Operating lease cost $ 26,343 $ 27,895 Variable lease expense (1) 27,243 33,849 Short-term lease expense (2) 1,950 1,866 Sublease income ( 2,380 ) ( 3,199 ) Total lease expense $ 53,156 $ 60,411 Short-term lease costs (3) $ 18,984 $ 15,984 (1) Variable lease payments that are not dependent on an index or rate and 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 and are not included in our ROU assets or lease liability in our consolidated balance sheet. (3) These short-term lease costs are related to leases with a contract term of one year or less, the majority of which are related to drilling rigs which 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, 2021 2020 Cash paid for amounts included in the measurement of lease $ 28,118 $ 32,030 ROU assets added in exchange for lease obligations $ 1,059 $ 27,769 Supplemental balance sheet information related to our operating leases is included in the table below (in thousands): Year Ended December 31, 2021 2020 Operating lease ROU assets $ 40,832 $ 63,581 Accrued liabilities – current $ ( 19,066 ) $ ( 24,673 ) Operating lease liabilities – long-term $ ( 24,861 ) $ ( 43,155 ) Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows: Year Ended December 31, 2021 2020 Weighted average remaining lease term 3.8 years 4.0 years Weighted average discount rate 6 % 6 % Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating 2022 $ 21,281 2023 7,207 2024 6,546 2025 6,468 2026 6,168 Thereafter 2,627 Total lease payments 50,297 Less effects of discounting ( 6,370 ) Total lease liability $ 43,927 We recorded impairment expense on certain office leases of $ 2.0 million in the year ended December 31, 2020 and $ 2.1 million in the year ended December 31, 2019. 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. 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. Our production committed to these pipelines is currently expected to exceed the minimum daily volumes provided in the contracts. However, if in the future we fail to deliver the committed volumes, we would recognize a deficiency payment in the period in which the under-delivery takes place and the related liability has been incurred. As of December 31, 2021, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands): Transportation, (a) 2022 $ 801,974 2023 784,712 2024 768,059 2025 682,050 2026 623,561 Thereafter 3,520,105 $ 7,180,461 (a) 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. In addition to the amounts included in the above table, we have entered into an additional agreement which is contingent on certain pipeline modifications and/or construction for natural gas volumes of 25,000 mcf per day and is expected to begin in 2022 with a six-year term. Not included in the table above is our estimate of accrued contractual obligations related to certain obligations retained by us after our divestiture of our North Louisiana assets. These contractual obligations are related to gathering, processing and transportation agreements including certain minimum volume commitments. There are inherent uncertainties surrounding the retained obligation and, as a result, the determination of the accrued obligation required significant judgement and estimation. The actual settlement amount and timing may differ from our estimates. See also Note 3 and Note 10. As of December 31, 2021, the carrying value of this obligation was $ 416.4 million and is included in divestiture contract obligation in our consolidated balance sheet. As of December 31, 2021, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands): Divestiture 2022 $ 91,120 2023 71,277 2024 58,401 2025 51,688 2026 36,971 Thereafter 106,942 $ 416,399 Delivery Commitments We have various volume delivery commitments that are related to our Marcellus Shale properties. 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, 2021, our delivery commitments through 2031 were as follows: Year Ending December 31, Natural Gas Ethane and Propane 2022 588,158 55,000 2023 500,710 39,932 2024 253,566 35,000 2025 182,493 35,000 2026 158,301 35,000 2027 100,000 35,000 2028 100,000 35,000 2029 100,000 20,000 2030 — 20,000 2031 — 20,000 In addition to the amounts included in the above table, we have contracted with a pipeline company through 2037 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are contingent upon facility construction and/or modification, are for 3,000 bbls per day starting in 2022 and increasing to 18,000 bbls per day in 2027 and increasing again to 25,000 bbls per day in 2029 then declining to 10,000 bbls per day in 2034 and declining again to 3,000 bbls per day through the end of the term in 2037. Other We 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.

Exit and Termination Costs

Exit and Termination Costs	12 Months Ended
	Dec. 31, 2021
Restructuring and Related Activities [Abstract]
Exit and Termination Costs	(15) Exit and Termination Costs Exit Costs In August 2020, we sold our North Louisiana assets and retained certain gathering, transportation and processing obligations which extend into 2030. These are contracts where we will not realize any future benefit. The estimated obligations are included in current and long-term divestiture contract obligation in our consolidated balance sheet. In the twelve months ended December 31, 2021, we recorded accretion expense of $ 47.9 million compared to $ 20.2 million in the prior year. In second quarter 2021, we also recorded a net favorable adjustment of $ 28.2 million to reduce this obligation due to a reduction of certain contractual payments compared to those originally estimated and a change to our assessment of drilling plans of the buyer. In third quarter 2020, the present value of our estimated obligations related to these assets was initially recorded as an exit cost at a total of $ 479.8 million. Also associated with this sale, we agreed to pay a midstream company $ 28.5 million to reduce our financial obligation related to the minimum volume commitments associated with this asset which was also recorded as an exit cost in third quarter 2020. The estimated discounted value for this divestiture contract obligation was $ 416.4 million at December 31, 2021. In second quarter 2020, we negotiated capacity releases on certain transportation pipelines in Pennsylvania effective May 31, 2020 and extending through the remainder of the contract. As a result of these releases, we recorded exit costs of $ 10.4 million which represented the discounted present value of our remaining obligations to the third party. The remaining carrying value for these transportation capacity releases as of December 31, 2021 was $ 7.3 million. Termination Costs In third quarter 2020, we completed the sale of our North Louisiana assets and we recorded $ 2.5 million of severance costs and stock-based compensation expense. Also in third quarter 2020, we announced an additional reduction in our work force as we continued to focus on lowering administrative expenses and recorded $ 3.7 million of severance costs and stock-based compensation expense related to this reduction in force. In first quarter 2020, we completed the sale of our shallow legacy assets in Northwest Pennsylvania and we recorded $ 1.4 million of severance costs which is primarily related to the sale of these assets. In 2019, we sold various non-core assets in Pennsylvania and accrued $ 819,000 of severance costs related to this sale. In second quarter 2019, we also announced another reduction in our work force and recorded $ 2.2 million of severance costs related to this work force reduction. The following summarizes our exit and termination costs for the three years ended December 31, 2021, 2020 and 2019 (in thousands): Year Ended December 31, 2021 2020 2019 Severance costs $ 567 $ 5,909 $ 7,535 Transportation contract capacity releases (including 754 10,900 — Divestiture contract obligation (including accretion 20,340 499,935 — One-time minimum volume commitment contract — 28,500 — Stock-based compensation and other — 2,165 1,971 $ 21,661 $ 547,409 $ 9,506 The following details the accrued exit and termination cost liability activity for the years ended December 31, 2021 and 2020 (in thousands): Exit Costs Termination Costs Balance at December 31, 2019 $ — $ 4,692 Accrued severance costs — 5,909 Accrued contract obligations 490,114 — Accretion of discount 20,720 — Payments ( 17,291 ) ( 9,147 ) Balance at December 31, 2020 493,543 1,454 Accrued severance costs — 567 Accrued contract obligations-changes in estimate ( 27,575 ) — Accretion of discount 48,669 — Payments ( 90,895 ) ( 2,011 ) Balance at December 31, 2021 $ 423,742 $ 10

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2021
Capitalized Exploratory Well Costs [Abstract]
Suspended Exploratory Well Costs	(16) Suspended Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. We had no capitalized exploratory well costs for year ended December 31, 2019. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2021 and December 31, 2020 (in thousands): 2021 2020 Balance at beginning of period $ 7,709 $ — Additions to capitalized exploratory well costs pending the 6,329 7,709 Reclassifications to wells, facilities and equipment based on ( 14,038 ) — Capitalized exploratory well costs, charged to expense — — Balance at end of period $ — $ 7,709 Less exploratory well costs that have been capitalized for a period of $ — $ 7,709 Capitalized exploratory well costs that have been capitalized for a period $ — $ —

Supplemental Information on Nat

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2021
Extractive Industries [Abstract]
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	(17) 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, 2021 2020 2019 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 9,338,236 $ 8,891,348 $ 9,345,557 Unproved properties 837,334 859,766 868,180 Total 10,175,570 9,751,114 10,213,737 Accumulated depreciation, depletion and ( 4,420,914 ) ( 4,064,305 ) ( 4,172,702 ) Net capitalized costs $ 5,754,656 $ 5,686,809 $ 6,041,035 ( a) Includes capitalized asset retirement costs and the associated accumulated amortization. Costs Incurred for Property Acquisition, Exploration and Development (a) December 31, 2021 2020 2019 (in thousands) Acquisitions Acreage purchases $ 21,942 $ 26,166 $ 57,324 Development 381,753 369,093 666,984 Exploration: Drilling 6,329 7,709 — Expense 22,048 31,376 35,117 Stock-based compensation expense 1,507 1,279 1,566 Gas gathering facilities: Development 3,402 3,694 3,583 Subtotal 436,981 439,317 764,574 Asset retirement obligations 18,634 2,610 11,193 Total costs incurred $ 455,615 $ 441,927 $ 775,767 (a) Includes cost incurred whether capitalized or expensed. Reserves Audit All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2021, Netherland, Sewell & Associates, Inc., an independent petroleum consultant, conducted an audit of our 2021 reserves in Appalachia. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2021, our consultant audited approximately 97 % of our proved reserves. A copy of the summary reserve report 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 consultant 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 consultant 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 consultant 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, 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 forty 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, 2021 to estimate reserve information were $ 59.35 per barrel of oil, $ 28.41 per barrel of NGLs and $ 3.30 per mcf for gas using a benchmark (NYMEX) of $ 66.34 per barrel and $ 3.60 per Mmbtu. The average realized prices used at December 31, 2020 to estimate reserve information were $ 30.13 per barrel of oil, $ 16.14 per barrel of NGLs and $ 1.68 per mcf for gas using a benchmark (NYMEX) of $ 39.77 per barrel and $ 1.98 per Mmbtu. 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. Natural Gas NGLs Crude Oil Natural (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: 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 Revisions ( 789,992 ) 42,741 ( 12,444 ) ( 608,211 ) Extensions, discoveries and additions 1,007,415 38,298 4,512 1,264,282 Property sales ( 609,311 ) ( 30,317 ) ( 6,145 ) ( 828,084 ) Production ( 574,529 ) ( 37,492 ) ( 2,829 ) ( 816,456 ) Balance, December 31, 2020 11,148,560 951,466 57,626 17,203,114 Revisions ( 311,410 ) 16,845 ( 7,089 ) ( 252,876 ) Extensions, discoveries and additions 1,155,952 69,367 5,103 1,602,769 Production ( 541,021 ) ( 36,373 ) ( 3,044 ) ( 777,523 ) Balance, December 31, 2021 11,452,081 1,001,305 52,596 17,775,484 Proved developed reserves: December 31, 2019 6,486,211 535,007 34,369 9,902,468 December 31, 2020 6,350,057 550,771 22,976 9,792,540 December 31, 2021 6,809,849 577,506 23,833 10,417,887 Proved undeveloped reserves: December 31, 2019 5,628,766 403,229 40,163 8,289,115 December 31, 2020 4,798,503 400,695 34,650 7,410,574 December 31, 2021 4,642,232 423,798 28,762 7,357,597 (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 2021, we added approximately 1.6 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 72 % of the 2021 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 252.9 Bcfe include positive performance revisions of 1.0 Tcfe and positive pricing revisions of 22.6 Bcfe more than offset by 1.3 Tcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. During 2020, we added approximately 1.3 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 80 % of the 2020 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 608.2 Bcfe include positive performance revisions of 420.9 Bcfe which were more than offset by 961.1 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon and negative pricing revisions of 67.9 Bcfe. 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. The following details the changes in proved undeveloped reserves for 2021 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2020 7,410,574 Undeveloped reserves transferred to developed ( 1,199,544 ) Revisions (a) ( 393,561 ) Extension and discoveries 1,540,128 Ending proved undeveloped reserves at December 31, 2021 7,357,597 (a) Includes 1.3 Tcfe 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. During 2021, we spent approximately $361.3 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 $ 2.2 billion over the next five years. As of December 31, 2021, we have 21 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 completed and are expected to turn to sales in 2022. 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 2026. 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 2021, 2020 and 2019, 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, 2021 2020 (in thousands) Future cash inflows $ 69,403,611 $ 35,820,758 Future costs: Production ( 27,015,321 ) ( 23,281,268 ) Development (a) ( 2,469,028 ) ( 2,744,539 ) Future net cash flows before income taxes 39,919,262 9,794,951 Future income tax expense ( 8,146,832 ) ( 1,240,011 ) Total future net cash flows before 10% discount 31,772,430 8,554,940 10% annual discount ( 19,287,204 ) ( 5,708,618 ) Standardized measure of discounted future net cash $ 12,485,226 $ 2,846,322 (a ) 2021 i ncludes $ 308.5 million of undiscounted future asset retirement costs as of December 31, 2021, using current estimates of future abandonment costs. The following table summarizes ch anges in the standardized measure of discounted future net cash flows. December 31, 2021 2020 2019 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ 11,600,850 $ ( 4,868,371 ) $ ( 6,560,107 ) Revisions in quantities 577,737 ( 345,073 ) ( 12,741 ) Changes in future development and abandonment ( 53,818 ) 107,899 104,585 Net change in income taxes ( 2,248,161 ) 797,816 1,125,639 Accretion of discount 298,077 756,083 1,317,349 Additions to proved reserves from extensions, 1,423,510 280,441 552,710 Natural gas, NGLs and oil sales, net of production ( 1,934,254 ) ( 402,450 ) ( 881,883 ) Actual development costs incurred during the 399,681 384,530 676,520 Sales of reserves in place — ( 394,125 ) ( 688,937 ) Timing and other ( 424,718 ) ( 99,001 ) ( 120,156 ) Net change for the year 9,638,904 ( 3,782,251 ) ( 4,487,021 ) Beginning of year 2,846,322 6,628,573 11,115,594 End of year $ 12,485,226 $ 2,846,322 $ 6,628,573

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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 17 for further detail.
Business Segment Information	Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment. We consider our gathering, processing and marketing functions as integral to our natural gas, crude oil and condensate producing activities. 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 measure financial performance as a single enterprise and not on an area-by-area basis. All of our operating revenues, income from operations and assets are generated and located in the United States.
Revenue Recognition, Accounts Receivable and Gas Imbalances	Revenue Recognition and Accounts Receivable 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 below for a more detailed summary of our product types. 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 utilize 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. Proceeds generated from the sale of excess firm transportation to third parties is also included here when we are determined to no longer be the primary obligor of such arrangement. Our net brokered margin was income of $ 1.1 million in 2021 compared to a loss of $ 14.2 million in both 2020 and 2019. 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. Each reporting period, we assess the recoverability of material receivables using historical data and current market conditions. The loss given default method is used when, based on management’s judgement, an allowance for expected credit losses is accrued on material receivables to reflect the net amount to be collected. 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 regularly review collectability and establish or adjust our allowance as necessary. We have allowances for doubtful accounts relating to exploration and production receivables of $ 568,000 at December 31, 2021 compared to $ 3.0 million at December 31, 2020. We recorded debt expense of $ 200,000 in the year ended December 31, 2021 compared to $ 400,000 in the year ended December 31, 2020 and $ 4.3 million in the year ended December 31, 2019.
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. 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 10. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. 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. Unproved properties had a net book value of $ 837.3 million as of December 31, 2021 compared to $ 859.8 million in 2020. We have recorded abandonment and impairment expense related to unproved properties of $ 7.2 million in the year ended December 31, 2021 compared to $ 19.3 million in 2020 and $ 1.2 billion in 2019. In 2019, an impairment of $ 1.2 billion was recorded associated with our North Louisiana unproved property values that we no longer had the intent to drill based on a shift in capital allocation. 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 3.
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 $ 2.4 million in the year ended December 31, 2021 compared to $ 2.6 million in the year ended December 31, 2020 and $ 5.0 million in the year ended December 31, 2019.
Leases	Leases We determine if an arrangement is a lease at the inception of the arrangement. We lease certain drilling rigs, office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. Certain of our lease agreements include lease and non-lease components. We account for these components as a single lease. Lease costs associated with drilling rigs are capitalized as part of well costs. Lease right-of-use ("ROU") assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of our lease contracts do not provide an implicit discount rate, we use our incremental borrowing rate which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at our discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with a term of 12 months or less are not recorded as a right-of-use asset and liability. The majority of our leases are classified as either short-term or long-term operating leases. 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 contractual basis.
Other Assets	Other Assets Other assets at December 31, 2021 include $ 69.6 million of marketable securities held in our deferred compensation plans, $ 11.5 million of other investments and $ 5.2 million of deferred financing costs primarily related to our bank credit facility. Other assets at December 31, 2020 included $ 63.9 million of marketable securities held in our deferred compensation plans and $ 11.9 million of other investments.
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 11.
Derivative Financial Instruments	Derivative Financial Instruments All of our commodity 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 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 commodity 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, which in an event of default, allows us to offset payables to and receivables from the defaulting counterparty. 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 derivative instruments 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 commodity derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We 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 entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. We have also 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. Our program may also include a three-way collar which is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price while the purchased put establishes the floor price until the market price for the commodity falls below the sold put stock price at which time the value of the purchased put is effectively capped. We also have the right to receive contingent consideration related to the sale of our North Louisiana assets in 2020. This derivative financial instrument is recorded as an asset in the accompanying consolidated balance sheets. This contingent consideration is based on future natural gas, NGLs and oil prices primarily based on published indexes. For additional information regarding our derivative instruments, see Note 9. 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 2021, we did not materially modify any existing derivative contracts.
Concentrations of Credit Risk	Concentrations of Credit Risk As of December 31, 2021, 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 customers’ 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 year ended December 31, 2021, we had one customer that accounted for 10% or more of natural gas, NGLs and oil sales compared to no ne for the year ended December 31, 2020. 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, 2021, our derivative counterparties included fifteen financial institutions and commodity traders, of which all but five are secured lenders in our bank credit facility. At December 31, 2021, our net derivative liability includes a payable to one counterparty not included in our bank credit facility totaling $ 637,000 and a receivable from the remaining four counterparties of $ 4.9 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. Historically, we have not experienced any issues of non-performance by derivative counterparties. 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. 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 8 for additional information.
Exit Costs	Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions. Fair value estimates are based on future discounted cash outflows required to satisfy the obligation. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, are recognized as an adjustment to the liability in the period of the change utilizing the initial discount rate. These costs, including associated accretion expense, are included in exit and termination costs in the accompanying consolidated statements of operations. See Note 15 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 14 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 in the accompanying consolidated 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.

Revenues from Contracts with _2

Revenues from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Natural gas sales $ 1,896,231 $ 943,740 $ 1,388,838 NGLs sales 1,135,826 578,454 681,134 Oil and condensate sales 182,970 85,519 185,453 Total natural gas, NGLs and oil sales 3,215,027 1,607,713 2,255,425 Sales of purchased natural gas 342,431 160,122 332,006 Sales of purchased NGLs 6,925 3,776 1,661 Other marketing revenue 16,056 9,375 11,842 Total $ 3,580,439 $ 1,780,986 $ 2,600,934

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax	Our income tax benefit was $ 9.7 million for the year ended December 31, 2021 compared to $ 25.6 million in 2020 and $ 500.3 million in 2019. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2021 2020 2019 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State, net of federal benefit 4.0 5.2 3.8 State rate and law change ( 3.4 ) 4.3 1.8 Valuation allowances ( 24.8 ) ( 26.3 ) ( 3.8 ) Non-deductible equity compensation 0.8 ( 0.7 ) ( 0.2 ) Consolidated effective tax rate ( 2.4 %) 3.5 % 22.6 %
Income Tax Expense (Benefit) Attributable to Income (Loss) Before Income Taxes	Income tax expense (benefit) attributable to income (loss) before income taxes consists of the following (in thousands): 2021 2020 2019 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ 6,297 $ 6,297 $ ( 366 ) $ ( 24,489 ) $ ( 24,855 ) $ — $ ( 434,585 ) $ ( 434,585 ) U.S. state and local 7,984 ( 24,024 ) ( 16,040 ) ( 157 ) ( 540 ) ( 697 ) 6,147 ( 71,853 ) ( 65,706 ) Total $ 7,984 $ ( 17,727 ) $ ( 9,743 ) $ ( 523 ) $ ( 25,029 ) $ ( 25,552 ) $ 6,147 $ ( 506,438 ) $ ( 500,291 )
Significant Components of Deferred Tax Assets and Liabilities	Significant components of deferred tax assets and liabilities are as follows: December 31, 2021 2020 (in thousands) Deferred tax assets: Net operating loss carryforward $ 788,375 $ 879,339 Divestiture contract obligation 112,199 132,352 Deferred compensation 22,121 16,635 Equity compensation 4,833 5,445 Asset retirement obligations 21,734 18,923 Interest expense carryforward 53,876 15,757 Lease right-of-use assets 9,954 16,070 Cumulative mark-to-market loss 32,221 2,607 Other 12,181 12,082 Valuation allowances: Federal ( 67,984 ) ( 152,499 ) State, net of federal benefit ( 203,085 ) ( 226,520 ) Total deferred tax assets 786,425 720,191 Deferred tax liabilities: Depreciation and depletion ( 879,163 ) ( 835,506 ) Operating lease liabilities ( 9,247 ) ( 15,058 ) Other ( 15,657 ) ( 4,894 ) Total deferred tax liabilities ( 904,067 ) ( 855,458 ) Net deferred tax liability $ ( 117,642 ) $ ( 135,267 )

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Net income (loss), as reported $ 411,778 $ ( 711,777 ) $ ( 1,716,297 ) Participating basic earnings (a) ( 10,795 ) — ( 251 ) Basic net income (loss) attributed to common stockholders 400,983 ( 711,777 ) ( 1,716,548 ) Reallocation of participating earnings (a) 272 — — Diluted net income (loss) attributed to common stockholders $ 401,255 $ ( 711,777 ) $ ( 1,716,548 ) Net income (loss) per common share: Basic $ 1.65 $ ( 2.95 ) $ ( 6.92 ) Diluted $ 1.61 $ ( 2.95 ) $ ( 6.92 ) (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 details basic weighted average common shares outstanding and diluted weighted average common shares outstanding (in thousands): Year Ended December 31, 2021 2020 2019 Denominator: Weighted average common shares outstanding – basic 242,862 241,373 247,970 Effect of dilutive securities 6,452 — — Weighted average common shares outstanding – diluted 249,314 241,373 247,970

Indebtedness (Tables)

Indebtedness (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt Outstanding	We had the following debt outstanding as of the dates shown below. The expenses of issuing debt are generally capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. For December 31, 2021, deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. 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 in the three-year period ended December 31, 2021. The components of our debt outstanding, including the effects of debt issuance costs, is as follows (in thousands): December 31, 2021 2020 Bank debt $ — $ 702,000 Senior notes 4.875 % senior notes due 2025 750,000 750,000 5.00 % senior notes due 2022 169,589 169,589 5.00 % senior notes due 2023 532,335 532,335 5.75 % senior notes due 2021 — 25,496 5.875 % senior notes due 2022 48,528 48,528 8.25 % senior notes due 2029 600,000 — 9.25 % senior notes due 2026 850,000 850,000 Other senior notes due 2022 — 490 Total senior notes 2,950,452 2,376,438 Senior subordinated notes 5.00 % senior subordinated notes due 2022 — 9,730 5.00 % senior subordinated notes due 2023 — 7,712 5.75 % senior subordinated notes due 2021 — 19,896 Total senior subordinated notes — 37,338 Total debt 2,950,452 3,115,776 Unamortized premium 188 457 Unamortized debt issuance costs ( 24,853 ) ( 30,625 ) Total debt (net of debt issuance costs) 2,925,787 3,085,608 Less current maturities of long-term debt ( 218,017 ) ( 45,356 ) Total long-term debt $ 2,707,770 $ 3,040,252
Schedule for Long-Term Debt Outstanding	The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2021 (in thousands): Year Ended 2022 $ 218,117 2023 532,335 2024 — 2025 750,000 2026 850,000 Thereafter 600,000 $ 2,950,452

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 (in thousands): 2021 2020 Beginning of period $ 79,822 $ 251,076 Liabilities incurred 73 1,483 Acquisitions — 123 Liabilities settled ( 8,197 ) ( 4,634 ) Disposition of wells — ( 176,748 ) Accretion expense 5,511 7,518 Change in estimate 18,627 1,004 End of period 95,836 79,822 Less current portion ( 5,310 ) ( 6,689 ) Long-term asset retirement obligations $ 90,526 $ 73,133

Derivative Activities (Tables)

Derivative Activities (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021, excluding our basis, freight swaps and divestiture contingent consideration which are discussed separately below: Period Contract Type Volume Hedged Weighted Average Hedge Price Swap Sold Put Floor Ceiling Natural Gas (1) 2022 Swaps 497,479 Mmbtu/day $ 3.12 2022 Collars 224,301 Mmbtu/day $ 3.28 $ 3.73 2022 Three-way Collars 251,781 Mmbtu/day $ 2.37 $ 3.03 $ 3.77 January-March 2022 Calls 80,000 Mmbtu/day $ 6.02 2023 Swaps 197,500 Mmbtu/day $ 3.40 2023 Collars 110,000 Mmbtu/day $ 3.26 $ 4.26 2023 Three-way Collars 70,000 Mmbtu/day $ 2.25 $ 3.25 $ 4.28 Crude Oil 2022 Swaps 6,437 bbls/day $ 60.73 2023 Swaps 623 bbls/day $ 66.40 NGLs (C5-Natural Gasoline) January-June 2022 Swaps 2,749 bbls/day $ 1.65 /gallon January-June 2022 Collars 1,497 bbls/day $ 1.53 /gallon $ 1.67 /gallon (1) We also sold natural gas call swaptions of 72,500 Mmbtu/day for 2023 at a weighted average price of $ 3.06 per Mmbtu.
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, 2021 and 2020 is summarized below (in thousands). As of December 31, 2021, we are conducting derivative activities with fifteen counterparties, of which all but five 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, 2021 Gross Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 22,491 $ ( 18,111 ) $ 4,380 –collars 12,378 ( 8,600 ) 3,778 –three-way collars 12,234 ( 8,449 ) 3,785 –basis swaps 18,092 ( 10,487 ) 7,605 Crude oil –swaps 368 ( 2,153 ) ( 1,785 ) NGLs –C3 propane spread 4,153 ( 4,153 ) — –C5 natural gasoline swaps 266 ( 363 ) ( 97 ) –C5 natural gasoline collars 221 ( 221 ) — Freight –swaps 114 ( 81 ) 33 Divestiture contingent consideration 26,640 — 26,640 $ 96,957 $ ( 52,618 ) $ 44,339 December 31, 2021 Gross Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ ( 121,759 ) $ 18,111 $ ( 103,648 ) –swaptions ( 11,149 ) — ( 11,149 ) –collars ( 16,579 ) 8,600 ( 7,979 ) –three-way collars ( 37,166 ) 8,449 ( 28,717 ) –calls ( 61 ) — ( 61 ) –basis swaps ( 2,064 ) 10,487 8,423 Crude oil –swaps ( 27,252 ) 2,153 ( 25,099 ) NGLs –C3 propane spread ( 4,030 ) 4,153 123 –C5 natural gasoline swaps ( 2,048 ) 363 ( 1,685 ) –C5 natural gasoline collars ( 1,493 ) 221 ( 1,272 ) Freight –swaps — 81 81 $ ( 223,601 ) $ 52,618 $ ( 170,983 ) December 31, 2020 Gross Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 33,559 $ ( 16,821 ) $ 16,738 –collars 7,016 ( 2,329 ) 4,687 –three-way collars 535 ( 6,139 ) ( 5,604 ) –basis swaps 7,894 ( 3,502 ) 4,392 Crude oil –swaps 2,465 ( 829 ) 1,636 NGLs –C3 propane spread 4,863 ( 4,863 ) — –C3 propane collars — ( 107 ) ( 107 ) Freight –swaps 2,310 — 2,310 Divestiture contingent consideration 15,960 — 15,960 $ 74,602 $ ( 34,590 ) $ 40,012 December 31, 2020 Gross Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ ( 10,120 ) $ 16,821 $ 6,701 –swaptions ( 9,803 ) — ( 9,803 ) –collars — 2,329 2,329 –three-way collars ( 18,353 ) 6,139 ( 12,214 ) –basis swaps ( 4,197 ) 3,502 ( 695 ) Crude oil –swaps ( 5,471 ) 829 ( 4,642 ) NGLs –C3 propane spread ( 4,069 ) 4,863 794 –C3 propane swaps ( 8,243 ) — ( 8,243 ) –C3 propane collars ( 3,086 ) 107 ( 2,979 ) –C5 natural gasoline swaps ( 4,897 ) — ( 4,897 ) –C5 natural gasoline calls ( 546 ) — ( 546 ) –NC4 butane swaps ( 651 ) — ( 651 ) –NC4 butane collars ( 401 ) — ( 401 ) Freight –swaps ( 1,206 ) — ( 1,206 ) $ ( 71,043 ) $ 34,590 $ ( 36,453 )
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). Derivative Fair Value (Loss) Income Year Ended December 31, 2021 2020 2019 Commodity swaps $ ( 466,203 ) $ 158,248 $ 219,968 Swaptions ( 1,346 ) ( 4,955 ) 333 Collars ( 117,612 ) 3,304 ( 3,903 ) Three-way collars ( 137,443 ) ( 16,346 ) — Basis swaps 33,691 48,278 6,661 Calls ( 836 ) ( 558 ) ( 349 ) Freight swaps ( 647 ) ( 1,230 ) 3,971 Divestiture contingent consideration 40,180 970 — Total $ ( 650,216 ) $ 187,711 $ 226,681

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred $ 69,606 $ — $ — $ 69,606 Derivatives –swaps — ( 127,934 ) — ( 127,934 ) –calls — ( 61 ) — ( 61 ) –collars — ( 4,201 ) ( 1,272 ) ( 5,473 ) –three-way collars — ( 24,932 ) — ( 24,932 ) –basis swaps — 16,151 — 16,151 –swaptions — — ( 11,149 ) ( 11,149 ) Derivatives –freight swaps — 114 — 114 Divestiture contingent consideration — 26,640 — 26,640 Fair Value Measurements at December 31, 2020 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred $ 63,942 $ — $ — $ 63,942 Derivatives –swaps — 6,642 — 6,642 –calls — — ( 546 ) ( 546 ) –collars — 7,016 ( 3,487 ) 3,529 –three-way collars — ( 17,818 ) — ( 17,818 ) –basis swaps — 4,491 — 4,491 –swaptions — — ( 9,803 ) ( 9,803 ) Derivatives –freight swaps — 1,104 — 1,104 Divestiture contingent consideration — 15,960 — 15,960
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 Balance at December 31, 2020 $ ( 13,836 ) Additions ( 12,420 ) Settlements 5,176 Transfers out of Level 3 8,660 Balance at December 31, 2021 $ ( 12,420 )
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, 2021 2020 2019 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ — $ — $ 290,500 $ 77,000 $ 370,500 $ 1,093,531
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, 2021 and 2020 (in thousands): December 31, 2021 December 31, 2020 Carrying Fair Carrying Fair Assets: Commodity swaps, collars, calls and basis swaps $ 17,699 $ 17,699 $ 24,052 $ 24,052 Divestiture contingent consideration 26,640 26,640 15,960 15,960 Marketable securities (a) 69,606 69,606 63,942 63,942 (Liabilities): Commodity swaps, collars, calls and basis swaps ( 170,983 ) ( 170,983 ) ( 36,453 ) ( 36,453 ) Bank credit facility (b) — — ( 702,000 ) ( 702,000 ) 5.75 % senior notes due 2021 (b) — — ( 25,496 ) ( 25,474 ) 5.00 % senior notes due 2022 (b) ( 169,589 ) ( 171,488 ) ( 169,589 ) ( 170,128 ) 5.875 % senior notes due 2022 (b) ( 48,528 ) ( 48,955 ) ( 48,528 ) ( 48,471 ) Other senior notes due 2022 (b) — — ( 490 ) ( 490 ) 5.00 % senior notes due 2023 (b) ( 532,335 ) ( 543,471 ) ( 532,335 ) ( 521,699 ) 4.875 % senior notes due 2025 (b) ( 750,000 ) ( 776,153 ) ( 750,000 ) ( 707,918 ) 9.25 % senior notes due 2026 (b) ( 850,000 ) ( 916,929 ) ( 850,000 ) ( 888,208 ) 8.25 % senior notes due 2029 (b) ( 600,000 ) ( 669,648 ) — — 5.75 % senior subordinated notes due 2021 (b) — — ( 19,896 ) ( 19,589 ) 5.00 % senior subordinated notes due 2022 (b) — — ( 9,730 ) ( 9,247 ) 5.00 % senior subordinated notes due 2023 (b) — — ( 7,712 ) ( 6,604 ) Deferred compensation plan (c) ( 165,395 ) ( 165,395 ) ( 96,563 ) ( 96,563 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and is updated based on end of period closing prices which is a Level 1 input. (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, 2021
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, 2021 (in thousands): 2021 2020 2019 Direct operating expense $ 1,310 $ 1,078 $ 1,928 Brokered natural gas and marketing expense 1,794 1,416 1,856 Exploration expense 1,507 1,279 1,566 General and administrative expense 39,673 32,905 35,061 Termination costs — 2,165 1,971 Total stock-based compensation $ 44,284 $ 38,843 $ 42,382
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, 2021: Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2020 2,815,860 $ 4.97 1,186,636 $ 4.18 Granted 2,340,114 10.20 1,289,495 9.56 Vested ( 2,397,336 ) 7.33 ( 1,679,502 ) 7.21 Forfeited ( 83,861 ) 6.32 — — Outstanding at December 31, 2021 2,674,777 $ 7.39 796,629 $ 6.49
Schedule of Share Based Payment Award Performance Stock Awards Valuation Assumptions	The following assumptions were used to estimate the fair value of the TSR awards granted during the years ended December 31, 2021, 2020 and 2019: Year Ended December 31, 2021 2020 2019 Risk-free interest rate 0.2 % 1.4 % 2.4 % Expected annual volatility 75 % 65 % 46 % Grant date fair value per unit $ 12.58 $ 3.85 $ 11.34
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: 2021 2020 Benefit obligation at beginning of year $ 1,953 $ 1,957 Service cost 77 80 Interest cost 38 50 Actuarial (gain) loss ( 62 ) ( 39 ) Benefits paid ( 88 ) ( 95 ) Benefit obligation at end of year $ 1,918 $ 1,953 Amounts recognized in the consolidated balance sheet: Long-term liabilities $ 1,918 $ 1,953 Components of Net Periodic Post Retirement Benefit Cost: Service cost $ 77 $ 80 Interest cost 38 50 Amortization of prior service cost 369 369 Net periodic post retirement costs (recognized in general and $ 484 $ 499 Other Changes in Benefit Obligations in Other Comprehensive Net (gain) loss $ ( 62 ) $ ( 39 ) Prior service cost — — Amortization of prior service cost ( 369 ) ( 369 ) Total recognized in other comprehensive (loss) income $ ( 431 ) $ ( 408 ) Total recognized in net periodic benefit cost and other comprehensive $ 53 $ 91
Summary of Assumptions Used to Determine Benefit Obligation	The following summarizes the assumptions used to determine the benefit obligation at December 31, 2021 and 2020: December 31, December 31, Weighted average assumptions used to determine benefit obligation: Discount rate 2.5 % 1.9 % Assumed weighted average healthcare cost trend rates: Initial healthcare trend rate 7.0 % 6.5 % Ultimate trend rate 4.0 % 4.5 % Year ultimate trend rate reached 2033 2024
Performance-based Internal Performance Awards
Summary of Non-Vested Awards Activities	The following is a summary of our non-vested internal performance metric awards activities at December 31, 2021: Number of Weighted Outstanding at December 31, 2020 1,099,102 $ 5.92 Units granted (a) 303,231 9.81 Vested ( 306,978 ) 12.20 Forfeited (b) — — Outstanding at December 31, 2021 1,095,355 $ 7.80 (a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 20 0% depending on achievement of specifically identified performance targets. (b) For Production Growth units granted in 2019 which are set to vest in early 2022, the payout is estimated at 74 %. For Reserve Growth units granted in 2019 which are set to vest in early 2022, the payout is estimated at 121 %.
Performance Based TSR - PSUs
Summary of Non-Vested Awards Activities	The following is a summary of our non-vested TSR award activities: Number of Units Weighted Outstanding at December 31, 2020 1,249,524 $ 9.55 Granted (a) 223,687 12.58 Vested and issued (b) ( 325,217 ) 18.51 Forfeited — — Outstanding at December 31, 2021 1,147,994 $ 7.60 (a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 200 % of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date. (b) Includes TSR-PSUs awards issued related to the 2018 performance period where the return on our common stock was negative and therefore, the performances multiple and actual payout was reduced to 100 %.

Capital Stock (Tables)

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2021
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 2020: Year Ended December 31, 2021 2020 Beginning balance 246,348,092 249,630,803 Restricted stock grants 1,293,892 3,390,358 Restricted stock units vested 1,493,341 1,226,473 Performance stock units issued 640,468 279,420 Performance stock dividends 13,966 18,700 Treasury shares 3,149 ( 8,197,662 ) Ending balance 249,792,908 246,348,092
Schedule of Change in Treasury Shares	The following is a schedule of the change in treasury shares since the beginning of 2020: Year Ended December 31, 2021 2020 Beginning balance 10,005,795 1,808,133 Rabbi trust shares distributed and/or sold ( 3,149 ) ( 2,338 ) Shares repurchased — 8,200,000 Ending balance 10,002,646 10,005,795

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Year Ended December 31, 2021 2020 2019 (in thousands) Net cash provided from operating activities included: Income taxes paid to taxing authorities $ 7,061 $ 343 $ — Interest paid ( 196,750 ) ( 168,471 ) ( 189,443 ) Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 18,634 $ 2,610 $ 11,193 Decrease in accrued capital expenditures ( 4,505 ) ( 23,625 ) ( 20,104 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of Components of Lease Expense	The components of our total lease expense for the two years ended December 31, 2021, the majority of which is included in general and administrative expense, are as follows (in thousands): Year Ended December 31, 2021 2020 Operating lease cost $ 26,343 $ 27,895 Variable lease expense (1) 27,243 33,849 Short-term lease expense (2) 1,950 1,866 Sublease income ( 2,380 ) ( 3,199 ) Total lease expense $ 53,156 $ 60,411 Short-term lease costs (3) $ 18,984 $ 15,984 (1) Variable lease payments that are not dependent on an index or rate and 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 and are not included in our ROU assets or lease liability in our consolidated balance sheet. (3) These short-term lease costs are related to leases with a contract term of one year or less, the majority of which are related to drilling rigs which 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, 2021 2020 Cash paid for amounts included in the measurement of lease $ 28,118 $ 32,030 ROU assets added in exchange for lease obligations $ 1,059 $ 27,769
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): Year Ended December 31, 2021 2020 Operating lease ROU assets $ 40,832 $ 63,581 Accrued liabilities – current $ ( 19,066 ) $ ( 24,673 ) Operating lease liabilities – long-term $ ( 24,861 ) $ ( 43,155 )
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: Year Ended December 31, 2021 2020 Weighted average remaining lease term 3.8 years 4.0 years Weighted average discount rate 6 % 6 %
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 2022 $ 21,281 2023 7,207 2024 6,546 2025 6,468 2026 6,168 Thereafter 2,627 Total lease payments 50,297 Less effects of discounting ( 6,370 ) Total lease liability $ 43,927
Schedule of Future Minimum Transportation Fees Due	As of December 31, 2021, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands): Transportation, (a) 2022 $ 801,974 2023 784,712 2024 768,059 2025 682,050 2026 623,561 Thereafter 3,520,105 $ 7,180,461 (a) 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.
Schedule of Estimated Settlement of Divestiture Contract Obligation Based On Discounted Value	As of December 31, 2021, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands): Divestiture 2022 $ 91,120 2023 71,277 2024 58,401 2025 51,688 2026 36,971 Thereafter 106,942 $ 416,399
Future Delivery Commitments	As of December 31, 2021, our delivery commitments through 2031 were as follows: Year Ending December 31, Natural Gas Ethane and Propane 2022 588,158 55,000 2023 500,710 39,932 2024 253,566 35,000 2025 182,493 35,000 2026 158,301 35,000 2027 100,000 35,000 2028 100,000 35,000 2029 100,000 20,000 2030 — 20,000 2031 — 20,000

Exit and Termination Costs (Tab

Exit and Termination Costs (Tables)	12 Months Ended
	Dec. 31, 2021
Restructuring and Related Activities [Abstract]
Summary of Exit and Termination Costs	The following summarizes our exit and termination costs for the three years ended December 31, 2021, 2020 and 2019 (in thousands): Year Ended December 31, 2021 2020 2019 Severance costs $ 567 $ 5,909 $ 7,535 Transportation contract capacity releases (including 754 10,900 — Divestiture contract obligation (including accretion 20,340 499,935 — One-time minimum volume commitment contract — 28,500 — Stock-based compensation and other — 2,165 1,971 $ 21,661 $ 547,409 $ 9,506
Exit and Termination Costs Included in Accrued Liabilities in Consolidated Balance Sheet	The following details the accrued exit and termination cost liability activity for the years ended December 31, 2021 and 2020 (in thousands): Exit Costs Termination Costs Balance at December 31, 2019 $ — $ 4,692 Accrued severance costs — 5,909 Accrued contract obligations 490,114 — Accretion of discount 20,720 — Payments ( 17,291 ) ( 9,147 ) Balance at December 31, 2020 493,543 1,454 Accrued severance costs — 567 Accrued contract obligations-changes in estimate ( 27,575 ) — Accretion of discount 48,669 — Payments ( 90,895 ) ( 2,011 ) Balance at December 31, 2021 $ 423,742 $ 10

Suspended Exploratory Well Co_2

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2021
Capitalized Exploratory Well Costs [Abstract]
Schedule Of Changes In Capitalized Exploratory Well Costs	The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2021 and December 31, 2020 (in thousands): 2021 2020 Balance at beginning of period $ 7,709 $ — Additions to capitalized exploratory well costs pending the 6,329 7,709 Reclassifications to wells, facilities and equipment based on ( 14,038 ) — Capitalized exploratory well costs, charged to expense — — Balance at end of period $ — $ 7,709 Less exploratory well costs that have been capitalized for a period of $ — $ 7,709 Capitalized exploratory well costs that have been capitalized for a period $ — $ —

Supplemental Information on N_2

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Extractive Industries [Abstract]
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization	Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2021 2020 2019 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 9,338,236 $ 8,891,348 $ 9,345,557 Unproved properties 837,334 859,766 868,180 Total 10,175,570 9,751,114 10,213,737 Accumulated depreciation, depletion and ( 4,420,914 ) ( 4,064,305 ) ( 4,172,702 ) Net capitalized costs $ 5,754,656 $ 5,686,809 $ 6,041,035 ( a) Includes capitalized asset retirement costs and the associated accumulated amortization.
Costs Incurred for Property Acquisition, Exploration and Development	Costs Incurred for Property Acquisition, Exploration and Development (a) December 31, 2021 2020 2019 (in thousands) Acquisitions Acreage purchases $ 21,942 $ 26,166 $ 57,324 Development 381,753 369,093 666,984 Exploration: Drilling 6,329 7,709 — Expense 22,048 31,376 35,117 Stock-based compensation expense 1,507 1,279 1,566 Gas gathering facilities: Development 3,402 3,694 3,583 Subtotal 436,981 439,317 764,574 Asset retirement obligations 18,634 2,610 11,193 Total costs incurred $ 455,615 $ 441,927 $ 775,767 (a) Includes cost incurred whether capitalized or expensed.
Proved Developed and Undeveloped Reserves	Natural Gas NGLs Crude Oil Natural (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: 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 Revisions ( 789,992 ) 42,741 ( 12,444 ) ( 608,211 ) Extensions, discoveries and additions 1,007,415 38,298 4,512 1,264,282 Property sales ( 609,311 ) ( 30,317 ) ( 6,145 ) ( 828,084 ) Production ( 574,529 ) ( 37,492 ) ( 2,829 ) ( 816,456 ) Balance, December 31, 2020 11,148,560 951,466 57,626 17,203,114 Revisions ( 311,410 ) 16,845 ( 7,089 ) ( 252,876 ) Extensions, discoveries and additions 1,155,952 69,367 5,103 1,602,769 Production ( 541,021 ) ( 36,373 ) ( 3,044 ) ( 777,523 ) Balance, December 31, 2021 11,452,081 1,001,305 52,596 17,775,484 Proved developed reserves: December 31, 2019 6,486,211 535,007 34,369 9,902,468 December 31, 2020 6,350,057 550,771 22,976 9,792,540 December 31, 2021 6,809,849 577,506 23,833 10,417,887 Proved undeveloped reserves: December 31, 2019 5,628,766 403,229 40,163 8,289,115 December 31, 2020 4,798,503 400,695 34,650 7,410,574 December 31, 2021 4,642,232 423,798 28,762 7,357,597 (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 2021 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2020 7,410,574 Undeveloped reserves transferred to developed ( 1,199,544 ) Revisions (a) ( 393,561 ) Extension and discoveries 1,540,128 Ending proved undeveloped reserves at December 31, 2021 7,357,597 (a) Includes 1.3 Tcfe 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.
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, 2021 2020 (in thousands) Future cash inflows $ 69,403,611 $ 35,820,758 Future costs: Production ( 27,015,321 ) ( 23,281,268 ) Development (a) ( 2,469,028 ) ( 2,744,539 ) Future net cash flows before income taxes 39,919,262 9,794,951 Future income tax expense ( 8,146,832 ) ( 1,240,011 ) Total future net cash flows before 10% discount 31,772,430 8,554,940 10% annual discount ( 19,287,204 ) ( 5,708,618 ) Standardized measure of discounted future net cash $ 12,485,226 $ 2,846,322 (a ) 2021 i ncludes $ 308.5 million of undiscounted future asset retirement costs as of December 31, 2021, using current estimates of future abandonment costs.
Changes in Discounted Future Net Cash Flows	The following table summarizes ch anges in the standardized measure of discounted future net cash flows. December 31, 2021 2020 2019 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ 11,600,850 $ ( 4,868,371 ) $ ( 6,560,107 ) Revisions in quantities 577,737 ( 345,073 ) ( 12,741 ) Changes in future development and abandonment ( 53,818 ) 107,899 104,585 Net change in income taxes ( 2,248,161 ) 797,816 1,125,639 Accretion of discount 298,077 756,083 1,317,349 Additions to proved reserves from extensions, 1,423,510 280,441 552,710 Natural gas, NGLs and oil sales, net of production ( 1,934,254 ) ( 402,450 ) ( 881,883 ) Actual development costs incurred during the 399,681 384,530 676,520 Sales of reserves in place — ( 394,125 ) ( 688,937 ) Timing and other ( 424,718 ) ( 99,001 ) ( 120,156 ) Net change for the year 9,638,904 ( 3,782,251 ) ( 4,487,021 ) Beginning of year 2,846,322 6,628,573 11,115,594 End of year $ 12,485,226 $ 2,846,322 $ 6,628,573

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2021USD ($)CounterpartiesCustomerCounterparty	Dec. 31, 2020USD ($)Customer	Dec. 31, 2019USD ($)
Summary Of Significant Accounting Policies [Line Items]
Net brokered margin gain (loss)		$ 1,100,000	$ (14,200,000)	$ (14,200,000)
Allowance for doubtful accounts on accounts receivable		568,000	3,004,000
Bad debt (income) expense		200,000	400,000	4,341,000
Net book value of unproved properties	[1]	837,334,000	859,766,000	868,180,000
Abandonment and impairment of unproved properties		7,206,000	19,334,000	1,235,342,000
Depreciation expense		$ 2,400,000	2,600,000	5,000,000
Lessee, operating lease, contract term		12 months
Marketable securities held in deferred compensation plans		$ 69,600,000	63,900,000
Deferred financing cost related to bank credit facility		5,200,000
Other investments including surface acreage		$ 11,500,000	$ 11,900,000
Number of customers accounted more than 10% of total oil and gas revenues | Customer		1	0
Number of counterparties | Counterparty		5
Number of financial institutions included in counter parties | Counterparty		15
Number of counterparties amount payable | Counterparties		1
Number of counterparties amount receivable | Counterparties		4
Counterparties in a Liability position
Summary Of Significant Accounting Policies [Line Items]
Net derivative liability		$ 637,000
Counterparties in a Receivable position
Summary Of Significant Accounting Policies [Line Items]
Derivative amount receivable		$ 4,900,000
Other property and equipment | Minimum [Member]
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
North Louisiana
Summary Of Significant Accounting Policies [Line Items]
Abandonment and impairment of unproved properties				$ 1,200,000,000
[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Dispositions - Additional Infor

Dispositions - Additional Information (Detail)	Aug. 14, 2020USD ($)	Mar. 31, 2020USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)a	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (Loss) on sale of assets					$ 701,000	$ 110,791,000	$ (30,256,000)
Proceeds from disposal of assets					303,000	246,127,000	$ 784,937,000
Gross Amounts of Recognized Assets					96,957,000	74,602,000
Contingent Consideration
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gross Amounts of Recognized Assets					26,640,000	15,960,000
North Louisiana
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (Loss) on sale of assets					479,000	$ (9,500,000)
Fair value of total consideration for sale	$ 260,000,000
Proceeds from disposal of assets	245,000,000
North Louisiana | Oil and Gas
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (Loss) on sale of assets					1,900,000
Loss on settlement of royalty claims					$ 1,500,000
North Louisiana | Contingent Consideration
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gross Amounts of Recognized Assets	$ 15,000,000
Northwest Pennsylvania
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (Loss) on sale of assets		$ 122,500,000
Proceeds from sale of oil and gas properties		$ 1,000,000
Pennsylvania
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (Loss) on sale of assets			$ (36,500,000)	$ 5,900,000
Proceeds from sale of oil and gas properties			$ 750,000,000	$ 34,000,000
Percentage of royalty disposed			2.50%
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, 2021USD ($)Stream	Dec. 31, 2020USD ($)
Disaggregation of Revenue [Line Items]
Number of revenue streams | Stream	3
Revenue Contract with Customer
Disaggregation of Revenue [Line Items]
Accounts receivable | $	$ 460.2	$ 237.8

Revenues from Contracts with _4

Revenues from Contracts with Customers - Disaggregation of Revenue by Identified Revenue Stream (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Total Revenue	$ 3,580,439	$ 1,780,986	$ 2,600,934
Natural Gas, NGLs and Oil Sales
Disaggregation of Revenue [Line Items]
Total Revenue	3,215,027	1,607,713	2,255,425
Natural Gas, NGLs and Oil Sales | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	1,896,231	943,740	1,388,838
Natural Gas, NGLs and Oil Sales | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	1,135,826	578,454	681,134
Natural Gas, NGLs and Oil Sales | Oil and condensate sales
Disaggregation of Revenue [Line Items]
Total Revenue	182,970	85,519	185,453
Brokered Natural Gas, Marketing and Other
Disaggregation of Revenue [Line Items]
Total Revenue	365,412	173,273	345,509
Brokered Natural Gas, Marketing and Other | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	342,431	160,122	332,006
Brokered Natural Gas, Marketing and Other | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	6,925	3,776	1,661
Brokered Natural Gas, Marketing and Other | Other marketing revenue
Disaggregation of Revenue [Line Items]
Total Revenue	$ 16,056	$ 9,375	$ 11,842

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Line Items]
Income tax benefit	$ 9,743,000	$ 25,552,000	$ 500,291,000
Deferred tax liabilities	117,642,000	135,267,000
Accrued interest or penalties related to tax amounts	0
Total deferred tax assets	786,425,000	720,191,000
Change in Valuation Allowances	$ 108,000,000	188,200,000	$ 70,500,000
Minimum [Member]
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire	Dec. 31, 2030
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	$ 203,085,000	226,520,000
Federal
Income Taxes [Line Items]
Valuation allowances	67,984,000	$ 152,499,000
Federal and State
Income Taxes [Line Items]
Net operating loss carryforwards	2,900,000,000
Net operating loss carryforward subject to expiration	1,200,000,000
Net operating loss carryforward not subject to expiration	1,700,000,000
Pennsylvania
Income Taxes [Line Items]
Net operating loss carryforwards	$ 861,000,000
Pennsylvania | Minimum [Member]
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire	Dec. 31, 2028
Pennsylvania | Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire	Dec. 31, 2040
Louisiana
Income Taxes [Line Items]
Net operating loss carryforward not subject to expiration	$ 1,500,000,000

Income Taxes - Reconciliation B

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory tax rate	21.00%	21.00%	21.00%
State, net of federal benefit	4.00%	5.20%	3.80%
State rate and law change	(3.40%)	4.30%	1.80%
Valuation allowances	(24.80%)	(26.30%)	(3.80%)
Non-deductible equity compensation	0.80%	(0.70%)	(0.20%)
Consolidated effective tax rate	(2.40%)	3.50%	22.60%

Income Taxes - Income Tax Expen

Income Taxes - Income Tax Expense (Benefit) Attributable to Income (Loss) Before Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal, Current	$ 0	$ (366)	$ 0
U.S. state and local, Current	7,984	(157)	6,147
Total, Current	7,984	(523)	6,147
U.S. federal, Deferred	6,297	(24,489)	(434,585)
U.S. state and local, Deferred	(24,024)	(540)	(71,853)
Total, Deferred	(17,727)	(25,029)	(506,438)
U.S. federal, Total	6,297	(24,855)	(434,585)
U.S. state and local, Total	(16,040)	(697)	(65,706)
Total (benefit) expense for income taxes	$ (9,743)	$ (25,552)	$ (500,291)

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
Net operating loss carryforward	$ 788,375	$ 879,339
Divestiture contract obligation	112,199	132,352
Deferred compensation	22,121	16,635
Equity compensation	4,833	5,445
Asset retirement obligations	21,734	18,923
Interest expense carryforward	53,876	15,757
Lease deferred tax assets	9,954	16,070
Cumulative mark-to-market loss	32,221	2,607
Other	12,181	12,082
Valuation allowances:
Total deferred tax assets	786,425	720,191
Deferred tax liabilities:
Depreciation and depletion	(879,163)	(835,506)
Leases	(9,247)	(15,058)
Other	(15,657)	(4,894)
Total deferred tax liabilities	(904,067)	(855,458)
Net deferred tax liability	(117,642)	(135,267)
Federal
Valuation allowances:
Valuation allowances	(67,984)	(152,499)
State, net of federal benefit
Valuation allowances:
Valuation allowances	$ (203,085)	$ (226,520)

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		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share Reconciliation [Abstract]
Net income (loss)		$ 411,778	$ (711,777)	$ (1,716,297)
Participating basic earnings	[1]	(10,795)	0	(251)
Basic net income (loss) attributed to common stockholders		400,983	(711,777)	(1,716,548)
Reallocation of participating earnings	[1]	272	0	0
Diluted net income (loss) attributed to common stockholders		$ 401,255	$ (711,777)	$ (1,716,548)
Net income (loss) per common share:
Basic		$ 1.65	$ (2.95)	$ (6.92)
Diluted		$ 1.61	$ (2.95)	$ (6.92)
[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, 2021	Dec. 31, 2020	Dec. 31, 2019
Denominator:
Basic	242,862	241,373	247,970
Effect of dilutive securities	6,452	0	0
Diluted	249,314	241,373	247,970

Net Income (Loss) Per Common _5

Net Income (Loss) Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	6,500,000	5,500,000	3,100,000
Equity Grants [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	18,000

Indebtedness - Additional Infor

Indebtedness - Additional Information (Detail)	36 Months Ended
	Dec. 31, 2021USD ($)
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0

Indebtedness - Debt Outstanding

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Senior notes	$ 2,950,452	$ 2,376,438
Senior subordinated notes	0	37,338
Total debt	2,950,452	3,115,776
Unamortized premium	188	457
Unamortized debt issuance costs	(24,853)	(30,625)
Total debt (net of debt issuance costs)	2,925,787	3,085,608
Less current maturities of long-term debt	(218,017)	(45,356)
Total debt	2,707,770	3,040,252
Notes Payable to Banks
Debt Instrument [Line Items]
Bank debt	0	702,000
4.875% Senior Notes Due 2025 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	750,000	750,000
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior subordinated notes	0	9,730
5.00% Senior Notes Due 2022 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	169,589	169,589
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior subordinated notes	0
5.00% Senior Notes Due 2023 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	532,335	532,335
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Senior subordinated notes	0
5.75% Senior Notes Due 2021 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	0	25,496
5.875% Senior Notes Due 2022 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	48,528	48,528
8.25% Senior Notes Due 2029 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	600,000	0
9.25% Senior Notes Due 2026 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	850,000	850,000
Other Senior Notes Due 2022 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	$ 0	490
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Senior subordinated notes		7,712
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Senior subordinated notes		$ 19,896

Indebtedness - Debt Outstandi_2

Indebtedness - Debt Outstanding (Parenthetical) (Detail)	Dec. 31, 2021	Dec. 31, 2020
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Percentage of redemption	4.875%	4.875%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Percentage of redemption	5.00%	5.00%
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Percentage of redemption	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Percentage of redemption	5.75%	5.75%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Percentage of redemption	5.875%	5.875%
8.25% Senior Notes Due 2029
Debt Instrument [Line Items]
Percentage of redemption	8.25%	8.25%
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Percentage of redemption	9.25%	9.25%
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Percentage of redemption	5.00%	5.00%
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Percentage of redemption	5.00%	5.00%
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Percentage of redemption	5.75%	5.75%

Indebtedness - Bank Debt - Addi

Indebtedness - Bank Debt - Additional Information (Detail) $ in Thousands	Jan. 01, 2022USD ($)	Dec. 31, 2021USD ($)Commercialbank	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Jan. 31, 2022	Sep. 30, 2021USD ($)
Debt Instrument [Line Items]
Loss (gain) on early extinguishment of debt		$ 98	$ (14,068)	$ (5,415)
Bank Credit Facility [Member]
Debt Instrument [Line Items]
Bank credit facility, maximum amount		4,000,000
Bank credit facility, borrowing base		3,000,000				$ 3,000,000
Bank commitments		$ 2,400,000				$ 2,400,000
Number of commercial banks included in current bank group | Commercialbank		26
Percentage holding of commercial banks, Maximum		8.30%
Maturity date of loan		Apr. 13, 2023
Weighted average interest rate on the bank credit facility		2.10%	2.60%	3.80%
Annual rate of commitment fee paid on the undrawn balance		0.30%
Undrawn letters of credit		$ 338,000
Borrowing capacity available under the commitment amount		$ 2,100,000
Bank Credit Facility [Member] | Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin		0.75%
Bank Credit Facility [Member] | LIBOR Rate
Debt Instrument [Line Items]
Interest rate margin		1.75%
Bank Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance		0.30%
Bank Credit Facility [Member] | Minimum [Member] | Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt		0.75%
Bank Credit Facility [Member] | Minimum [Member] | LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt		1.75%
Bank Credit Facility [Member] | Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance		0.375%
Bank Credit Facility [Member] | Maximum | Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt		1.75%
Bank Credit Facility [Member] | Maximum | LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt		2.75%
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Base rate on debt		9.25%	9.25%
9.25% Senior Notes Due 2026 | Subsequent Event
Debt Instrument [Line Items]
Base rate on debt					9.25%
Borrowing capacity available under the commitment amount	$ 850,000
Redemption price of notes as percentage of principal amount	106.938%
Loss (gain) on early extinguishment of debt	$ 70,000
Debt instrument maturity year	2026

Indebtedness - New Senior Notes

Indebtedness - New Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands	Jan. 01, 2022	Jan. 31, 2022	Jan. 31, 2021	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Unamortized debt issuance costs				$ 24,853	$ 30,625
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Percentage of redemption				9.25%	9.25%
9.25% Senior Notes Due 2026 | Subsequent Event
Debt Instrument [Line Items]
Percentage of redemption		9.25%
Debt instrument maturity year	2026
Redemption price of notes as percentage of principal amount	106.938%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Percentage of redemption				5.75%	5.75%
8.25% Senior Notes Due 2029
Debt Instrument [Line Items]
Aggregate principal amount			$ 600,000
Percentage of redemption			8.25%
Debt instrument maturity year			2029
Net proceeds after underwriting expenses			$ 591,300
Unamortized debt issuance costs			$ 8,800
Redemption price of notes as percentage of principal amount			100.00%
4.75% Senior Notes Due 2030 | Subsequent Event
Debt Instrument [Line Items]
Aggregate principal amount		$ 500,000
Percentage of redemption		4.75%
Debt instrument maturity year		2030
Net proceeds after underwriting expenses		$ 492,100
Unamortized debt issuance costs		$ 7,900
Redemption price of notes as percentage of principal amount		100.00%
Repayments of senior notes		$ 850,000

Indebtedness - Senior Subordina

Indebtedness - Senior Subordinated Notes - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021
Subordinated Debt [Member]
Debt Instrument [Line Items]
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, 2021
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, 2021. Certain of our senior notes may also limit our ability to pay cash dividends.
Minimum [Member]
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) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
2022	$ 218,117
2023	532,335
2024	0
2025	750,000
2026	850,000
Thereafter	600,000
Total debt	$ 2,950,452	$ 3,115,776

Asset Retirement Obligations -

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation [Abstract]
Beginning of period	$ 79,822	$ 251,076
Liabilities incurred	73	1,483
Acquisitions	0	123
Liabilities settled	(8,197)	(4,634)
Disposition of wells	0	(176,748)
Accretion expense	5,511	7,518
Change in estimate	18,627	1,004
End of period	95,836	79,822
Less current portion	(5,310)	(6,689)
Long-term asset retirement obligations	$ 90,526	$ 73,133

Derivative Activities - Additio

Derivative Activities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021USD ($)MMBTU	Mar. 31, 2022TPerM	Dec. 31, 2020USD ($)
Derivative [Line Items]
Account receivable, net	$ 471,775,000		$ 252,642,000
Contingent Consideration
Derivative [Line Items]
Derivative assets liabilities at fair value net	26,600,000
Minimum [Member] | Contingent Consideration
Derivative [Line Items]
Derivative assets liabilities at fair value net	29,500,000
North Louisiana | Maximum | Contingent Consideration
Derivative [Line Items]
Potential Contractual Payout Of Contingent Consideration	45,500,000
Derivatives Excluding Basis Swaps And Freight Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	169,500,000
Commodity | Natural Gas Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 16,000,000
Volume Hedged | MMBTU	213,710,000
Commodity | Propane Spread Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 123,000,000
Freight | Swap | Fair Value, Inputs, Level 2
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 114,000
Freight | Swap | Contracts Settle in 2022 | Fair Value, Inputs, Level 2 | Forecast
Derivative [Line Items]
Volume Hedged | TPerM		7,000

Derivative Activities - Derivat

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail)	Dec. 31, 2021MmbtuPerDayBarrelsPerDay$ / MMBTU$ / gal$ / bbl
Naturals Gas [Member] | 2022 Commodity Contract | Swap
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	497,479	[1]
Weighted Average Hedge Price, Swap	3.12	[1]
Naturals Gas [Member] | 2022 Commodity Contract | Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	224,301	[1]
Weighted average price of hedge, Floor	3.28	[1]
Weighted average price of hedge, Ceiling	3.73	[1]
Naturals Gas [Member] | 2022 Commodity Contract | Three Way Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	251,781	[1]
Weighted Average Hedge Price, Sold Put	2.37	[1]
Weighted average price of hedge, Floor	3.03	[1]
Weighted average price of hedge, Ceiling	3.77	[1]
Naturals Gas [Member] | 2023 Commodity Contract | Swap
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	197,500	[1]
Weighted Average Hedge Price, Swap	3.40	[1]
Naturals Gas [Member] | 2023 Commodity Contract | Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	110,000	[1]
Weighted average price of hedge, Floor	3.26	[1]
Weighted average price of hedge, Ceiling	4.26	[1]
Naturals Gas [Member] | 2023 Commodity Contract | Three Way Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	70,000	[1]
Weighted Average Hedge Price, Sold Put	2.25	[1]
Weighted average price of hedge, Floor	3.25	[1]
Weighted average price of hedge, Ceiling	4.28	[1]
Naturals Gas [Member] | January-March 2022 | Calls
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	80,000	[1]
Weighted average price of hedge, Ceiling	6.02
Crude Oil | 2022 Commodity Contract | Swap
Derivative [Line Items]
Volume Hedged | BarrelsPerDay	6,437
Weighted Average Hedge Price, Swap | $ / bbl	60.73
Crude Oil | 2023 Commodity Contract | Swap
Derivative [Line Items]
Volume Hedged | BarrelsPerDay	623
Weighted Average Hedge Price, Swap	66.40
NGLs (C5-Natural Gasoline) | January-June 2022 | Swap
Derivative [Line Items]
Volume Hedged | BarrelsPerDay	2,749
Weighted Average Hedge Price, Swap | $ / gal	1.65
NGLs (C5-Natural Gasoline) | January-June 2022 | Collars
Derivative [Line Items]
Volume Hedged | BarrelsPerDay	1,497
Weighted average price of hedge, Floor | $ / gal	1.53
Weighted average price of hedge, Ceiling | $ / gal	1.67
[1]	We also sold natural gas call swaptions of 72,500 Mmbtu/day for 2023 at a weighted average price of $ 3.06 per Mmbtu.

Derivative Activities - Deriv_2

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - Natural Gas - 2023 Commodity Contract - Call Swaptions	Dec. 31, 2021MmbtuPerDay$ / MMBTU
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	72,500
Weighted average price of hedge | $ / MMBTU	3.06

Derivative Activities - Combine

Derivative Activities - Combined Fair Value of Derivatives, by Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 96,957	$ 74,602
Gross Amounts Offset in the Balance Sheet	(52,618)	(34,590)
Net Amounts of Assets Presented in the Balance Sheet	44,339	40,012
Gross Amounts of Recognized (Liabilities)	(223,601)	(71,043)
Gross Amounts Offset in the Balance Sheet	52,618	34,590
Net Amounts of (Liabilities) Presented in the Balance Sheet	(170,983)	(36,453)
Contingent Consideration
Derivative [Line Items]
Gross Amounts of Recognized Assets	26,640	15,960
Gross Amounts Offset in the Balance Sheet	0	0
Net Amounts of Assets Presented in the Balance Sheet	26,640	15,960
Commodity | Natural Gas | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	22,491	33,559
Gross Amounts Offset in the Balance Sheet	(18,111)	(16,821)
Net Amounts of Assets Presented in the Balance Sheet	4,380	16,738
Gross Amounts of Recognized (Liabilities)	121,759	(10,120)
Gross Amounts Offset in the Balance Sheet	18,111	16,821
Net Amounts of (Liabilities) Presented in the Balance Sheet	103,648	6,701
Commodity | Natural Gas | Swaption
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)	11,149	(9,803)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet	11,149	(9,803)
Commodity | Natural Gas | Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	12,378	7,016
Gross Amounts Offset in the Balance Sheet	8,600	(2,329)
Net Amounts of Assets Presented in the Balance Sheet	3,778	4,687
Gross Amounts of Recognized (Liabilities)	16,579	0
Gross Amounts Offset in the Balance Sheet	8,600	2,329
Net Amounts of (Liabilities) Presented in the Balance Sheet	7,979	2,329
Commodity | Natural Gas | Three Way Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	12,234	535
Gross Amounts Offset in the Balance Sheet	8,449	(6,139)
Net Amounts of Assets Presented in the Balance Sheet	3,785	(5,604)
Gross Amounts of Recognized (Liabilities)	37,166	(18,353)
Gross Amounts Offset in the Balance Sheet	8,449	6,139
Net Amounts of (Liabilities) Presented in the Balance Sheet	28,717	(12,214)
Commodity | Natural Gas | Basis Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	18,092	7,894
Gross Amounts Offset in the Balance Sheet	10,487	(3,502)
Net Amounts of Assets Presented in the Balance Sheet	7,605	4,392
Gross Amounts of Recognized (Liabilities)	2,064	(4,197)
Gross Amounts Offset in the Balance Sheet	10,487	3,502
Net Amounts of (Liabilities) Presented in the Balance Sheet	(8,423)	(695)
Commodity | Natural Gas | Calls
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)	61
Gross Amounts Offset in the Balance Sheet
Net Amounts of (Liabilities) Presented in the Balance Sheet	61
Commodity | Crude Oil | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	368	2,465
Gross Amounts Offset in the Balance Sheet	2,153	(829)
Net Amounts of Assets Presented in the Balance Sheet	(1,785)	1,636
Gross Amounts of Recognized (Liabilities)	27,252	(5,471)
Gross Amounts Offset in the Balance Sheet	2,153	829
Net Amounts of (Liabilities) Presented in the Balance Sheet	25,099	(4,642)
Commodity | NGLs (C3-Propane) | Spread Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	4,153	4,863
Gross Amounts Offset in the Balance Sheet	4,153	(4,863)
Net Amounts of Assets Presented in the Balance Sheet		0
Gross Amounts of Recognized (Liabilities)	4,030	(4,069)
Gross Amounts Offset in the Balance Sheet	4,153	4,863
Net Amounts of (Liabilities) Presented in the Balance Sheet	(123)	794
Commodity | NGLs (C3-Propane) | Swaps
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(8,243)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		(8,243)
Commodity | NGLs (C3-Propane) | Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets		0
Gross Amounts Offset in the Balance Sheet		(107)
Net Amounts of Assets Presented in the Balance Sheet		(107)
Gross Amounts of Recognized (Liabilities)		(3,086)
Gross Amounts Offset in the Balance Sheet		107
Net Amounts of (Liabilities) Presented in the Balance Sheet		(2,979)
Commodity | NGLs (C5-Natural Gasoline) | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	266
Gross Amounts Offset in the Balance Sheet	363
Net Amounts of Assets Presented in the Balance Sheet	(97)
Gross Amounts of Recognized (Liabilities)	2,048	(4,897)
Gross Amounts Offset in the Balance Sheet	363	0
Net Amounts of (Liabilities) Presented in the Balance Sheet	1,685	(4,897)
Commodity | NGLs (C5-Natural Gasoline) | Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	221
Gross Amounts Offset in the Balance Sheet	221
Net Amounts of Assets Presented in the Balance Sheet
Gross Amounts of Recognized (Liabilities)	1,493
Gross Amounts Offset in the Balance Sheet	221
Net Amounts of (Liabilities) Presented in the Balance Sheet	1,272
Commodity | NGLs (C5-Natural Gasoline) | Calls
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(546)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		(546)
Commodity | NGLs (NC4-Normal Butane) | Swaps
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(651)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		(651)
Commodity | NGLs (NC4-Normal Butane) | Collars
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(401)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		(401)
Freight | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	114	2,310
Gross Amounts Offset in the Balance Sheet	81	0
Net Amounts of Assets Presented in the Balance Sheet	33	2,310
Gross Amounts of Recognized (Liabilities)		(1,206)
Gross Amounts Offset in the Balance Sheet	81	0
Net Amounts of (Liabilities) Presented in the Balance Sheet	$ (81)	$ (1,206)

Derivative Activities - Effects

Derivative Activities - Effects of Derivatives on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ (650,216)	$ 187,711	$ 226,681
Contingent Consideration
Derivative [Line Items]
Derivative Fair Value Income (Loss)	40,180	970	0
Swaption
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(1,346)	(4,955)	333
Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(117,612)	3,304	(3,903)
Three Way Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(137,443)	(16,346)	0
Basis Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)	33,691	48,278	6,661
Calls
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(836)	(558)	(349)
Commodity | Swap
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(466,203)	158,248	219,968
Freight | Swap
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ (647)	$ (1,230)	$ 3,971

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	$ 69,606,000	$ 63,942,000
Commodity | Fair Value, Recurring | Swap
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(127,934,000)	6,642,000
Commodity | Fair Value, Recurring | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(61,000)	(546,000)
Commodity | Fair Value, Recurring | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(5,473,000)	3,529,000
Commodity | Fair Value, Recurring | Three Way Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(24,932,000)	(17,818,000)
Commodity | Fair Value, Recurring | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	16,151,000	4,491,000
Commodity | Fair Value, Recurring | Swaption
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(11,149,000)	(9,803,000)
Freight | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	114,000	1,104,000
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	69,606,000	63,942,000
Fair Value, Inputs, Level 1 | Commodity | Fair Value, Recurring | Swap
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 1 | Commodity | Fair Value, Recurring | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 1 | Commodity | Fair Value, Recurring | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 1 | Commodity | Fair Value, Recurring | Three Way Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 1 | Commodity | Fair Value, Recurring | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 1 | Commodity | Fair Value, Recurring | Swaption
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
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
Fair Value, Inputs, 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 2 | Commodity | Fair Value, Recurring | Swap
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(127,934,000)	6,642,000
Fair Value, Inputs, Level 2 | Commodity | Fair Value, Recurring | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(61,000)	0
Fair Value, Inputs, Level 2 | Commodity | Fair Value, Recurring | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(4,201,000)	7,016,000
Fair Value, Inputs, Level 2 | Commodity | Fair Value, Recurring | Three Way Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(24,932,000)	(17,818,000)
Fair Value, Inputs, Level 2 | Commodity | Fair Value, Recurring | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	16,151,000	4,491,000
Fair Value, Inputs, Level 2 | Commodity | Fair Value, Recurring | Swaption
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 2 | Freight | Swap
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	114,000
Fair Value, Inputs, 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	114,000	1,104,000
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
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Recurring | Swap
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Recurring | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	(546,000)
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Recurring | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(1,272,000)	(3,487,000)
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Recurring | Three Way Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Recurring | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 3 | Commodity | Fair Value, Recurring | Swaption
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(11,149,000)	(9,803,000)
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
Contingent Consideration
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	26,600,000
Contingent Consideration | Fair Value, Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	26,640,000	15,960,000
Contingent Consideration | 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
Contingent Consideration | Fair Value, Inputs, 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	26,640,000	15,960,000
Contingent Consideration | 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

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2020	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends			$ 951,000	$ 713,000	$ 1,100,000
Mark-to-market gain (loss)			$ 3,000,000	6,300,000	8,500,000
North Louisiana
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved properties and other assets	$ 77,000,000	$ 1,100,000,000
Annual discount rate			12.00%
North Louisiana Assets | Fair Value, Inputs, Level 2 | Leases
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved properties and other assets				$ 2,000,000
Houston | Fair Value, Inputs, Level 2 | Leases
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved properties and other assets					$ 2,100,000
Maximum | North Louisiana | Contingent Consideration
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Potential Contractual Payout Of Contingent Consideration			$ 45,500,000
Measurement Input, Price Volatility | Weighted Average
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Implied volatilities			45.00%
Measurement Input, Price Volatility | Weighted Average | Swaption
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Implied volatilities			25.00%
Measurement Input, Price Volatility | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Implied volatilities			37.00%
Measurement Input, Price Volatility | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Implied volatilities			61.00%

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, 2021USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at December 31, 2020	$ (13,836)
Additions	(12,420)
Settlements	5,176
Transfers out of Level 3	8,660
Balance at December 31, 2021	$ (12,420)

Fair Value Measurements - Value

Fair Value Measurements - Value of Assets Measured at Fair Value on Nonrecurring Basis (Detail) - North Louisiana - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties	$ 77,000	$ 1,100,000
Fair Value, Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		$ 370,500	$ 290,500	$ 370,500	$ 0
Impairment on natural gas and oil properties			$ 77,000	$ 1,093,531

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($) $ in Thousands		Dec. 31, 2021	Dec. 31, 2020
Assets:
Marketable securities		$ 69,600	$ 63,900
Reported Value Measurement
Assets:
Commodity swaps, collar, options and basis swaps		17,699	24,052
Marketable securities	[1]	69,606	63,942
(Liabilities):
Commodity swaps, collar, options and basis swaps		(170,983)	(36,453)
Bank credit facility	[2]	0	(702,000)
Deferred compensation plan	[3]	(165,395)	(96,563)
Reported Value Measurement | Contingent Consideration
Assets:
Commodity swaps, collar, options and basis swaps		26,640	15,960
Estimate of Fair Value Measurement
Assets:
Commodity swaps, collar, options and basis swaps		17,699	24,052
Marketable securities	[1]	69,606	63,942
(Liabilities):
Commodity swaps, collar, options and basis swaps		(170,983)	(36,453)
Bank credit facility	[2]	0	(702,000)
Deferred compensation plan	[3]	(165,395)	(96,563)
Estimate of Fair Value Measurement | Contingent Consideration
Assets:
Commodity swaps, collar, options and basis swaps		26,640	15,960
5.75% Senior Notes Due 2021
(Liabilities):
Senior notes	[2]		(25,474)
5.75% Senior Notes Due 2021 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	0	(25,496)
5.75% Senior Notes Due 2021 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	0
5.00% Senior Notes Due 2022
(Liabilities):
Senior notes	[2]		(170,128)
5.00% Senior Notes Due 2022 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	(169,589)	(169,589)
5.00% Senior Notes Due 2022 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	(171,488)
5.875% Senior Notes Due 2022 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	(48,528)	(48,528)
5.875% Senior Notes Due 2022 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	(48,955)	(48,471)
Other Senior Notes Due 2022 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	0	(490)
Other Senior Notes Due 2022 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	0	(490)
5.00% Senior Notes Due 2023 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	(532,335)	(532,335)
5.00% Senior Notes Due 2023 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	(543,471)	(521,699)
4.875% Senior Notes Due 2025 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	(750,000)	(750,000)
4.875% Senior Notes Due 2025 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	(776,153)	(707,918)
9.25% Senior Notes Due 2026 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	(850,000)	(850,000)
9.25% Senior Notes Due 2026 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	(916,929)	(888,208)
8.25% Senior Notes Due 2029 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	(600,000)	0
8.25% Senior Notes Due 2029 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	(669,648)	0
5.75% Senior Subordinated Notes Due 2021 | Reported Value Measurement
(Liabilities):
Subordinated debt	[2]	0	(19,896)
5.75% Senior Subordinated Notes Due 2021 | Estimate of Fair Value Measurement
(Liabilities):
Subordinated debt	[2]	0	(19,589)
5.00% Senior Subordinated Notes Due 2022 | Reported Value Measurement
(Liabilities):
Subordinated debt	[2]	0	(9,730)
5.00% Senior Subordinated Notes Due 2022 | Estimate of Fair Value Measurement
(Liabilities):
Subordinated debt	[2]	0	(9,247)
5.00% Senior Subordinated Notes Due 2023 | Reported Value Measurement
(Liabilities):
Subordinated debt	[2]	0	(7,712)
5.00% Senior Subordinated Notes Due 2023 | Estimate of Fair Value Measurement
(Liabilities):
Subordinated debt	[2]	$ 0	$ (6,604)
[1]	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and is updated based on end of period closing prices which is a Level 1 input.
[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, 2021	Dec. 31, 2020
5.75% Senior Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5.75%	5.75%
5.00% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5.00%	5.00%
5.875% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5.875%	5.875%
5.00% Senior Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5.00%	5.00%
4.875% Senior Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	4.875%	4.875%
9.25% Senior Notes Due 2026
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	9.25%	9.25%
8.25% senior notes due 2029
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	8.25%	8.25%
5.75% Senior Subordinated Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5.75%	5.75%
5.00% Senior Subordinated Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5.00%	5.00%
5.00% Senior Subordinated Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5.00%	5.00%

Stock-based Compensation Plan_2

Stock-based Compensation Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021USD ($)Plans	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Active equity-based stock plans | Plans	2
Income tax benefit	$ (9,743,000)	$ (25,552,000)	$ (500,291,000)
Equity Compensation
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax benefit	$ (340,000)	$ 4,300,000	$ 3,400,000

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 44,284	$ 38,843	$ 42,382
Direct Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,310	1,078	1,928
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,794	1,416	1,856
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,507	1,279	1,566
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	39,673	32,905	35,061
Termination Costs
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 0	$ 2,165	$ 1,971

Stock-based Compensation Plan_4

Stock-based Compensation Plans - Additional Information 1 (Detail)	12 Months Ended
	Dec. 31, 2021Awardshares
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
Types of awards available for grant	2
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 | Minimum [Member]
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
Types of awards available for grant	1
Performance Based TSR - PSUs | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	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%

Stock-based Compensation Plan_5

Stock-based Compensation Plans - Additional Information 2 (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average period	1 year 4 months 24 days
Proceeds from the sales of common stock held by the deferred compensation plan	$ 5,879,000	$ 696,000	$ 667,000
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	2,340,114	4,500,000	2,800,000
Vesting period	3 years
Stock-based compensation expense	$ 19,600,000	$ 17,800,000	$ 22,500,000
Unrecognized compensation related to Awards	$ 19,000,000
Weighted average period	1 year 9 months 18 days
Granted, weighted average grant date fair value	$ 10.20
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	1,289,495	3,500,000	1,200,000
Stock-based compensation expense	$ 11,400,000	$ 10,300,000	$ 9,300,000
Unrecognized compensation related to Awards	$ 4,400,000
Weighted average period	1 year 4 months 24 days
Granted, weighted average grant date fair value	$ 9.56	$ 3.18	$ 10.16
Restricted Stock Liability Awards | Non-Employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	102,000	217,000	183,000
Restricted Stock Liability Awards | Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	1,200,000	3,300,000	1,000,000
Vesting period	3 years	3 years	3 years

Stock-based Compensation Plan_6

Stock-based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	2,815,860
Granted	2,340,114	4,500,000	2,800,000
Vested and issued	(2,397,336)
Forfeited	(83,861)
Outstanding, Ending Balance	2,674,777	2,815,860
Outstanding, Beginning Balance, weighted average grant date fair value	$ 4.97
Granted, weighted average grant date fair value	10.20
Vested, weighted average grant date fair value	7.33
Forfeited, weighted average grant date fair value	6.32
Outstanding, Ending Balance, weighted average grant date fair value	$ 7.39	$ 4.97
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	1,186,636
Granted	1,289,495	3,500,000	1,200,000
Vested and issued	(1,679,502)
Forfeited	0
Outstanding, Ending Balance	796,629	1,186,636
Outstanding, Beginning Balance, weighted average grant date fair value	$ 4.18
Granted, weighted average grant date fair value	9.56	$ 3.18	$ 10.16
Vested, weighted average grant date fair value	7.21
Forfeited, weighted average grant date fair value	0
Outstanding, Ending Balance, weighted average grant date fair value	$ 6.49	$ 4.18

Stock-based Compensation Plan_7

Stock-based Compensation Plans - Additional Information 3 (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average period	1 year 4 months 24 days
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 6.6	$ 2.7	$ 3.8
Unrecognized compensation related to Awards	$ 2.6
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Stock-based compensation expense	$ 2.6	$ 2.4	$ 3
Unrecognized compensation related to Awards	$ 1.5
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Weighted average period	1 year 6 months

Stock-based Compensation Plan_8

Stock-based Compensation Plans - PG/RG-PSUs Activities (Detail) - Performance-based Internal Performance Awards	12 Months Ended
	Dec. 31, 2021$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance | shares	1,099,102
Granted | shares	303,231	[1]
Vested | shares	(306,978)
Forfeited | shares	0	[2]
Outstanding, Ending Balance | shares	1,095,355
Outstanding, Beginning Balance, weighted average grant date fair value | $ / shares	$ 5.92
Granted, weighted average grant date fair value | $ / shares	9.81	[1]
Vested, weighted average grant date fair value | $ / shares	12.20
Forfeited, weighted average grant date fair value | $ / shares	0	[2]
Outstanding, Ending Balance, weighted average grant date fair value | $ / shares	$ 7.80
[1]	Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 20 0% depending on achievement of specifically identified performance targets.
[2]	For Production Growth units granted in 2019 which are set to vest in early 2022, the payout is estimated at 74 %. For Reserve Growth units granted in 2019 which are set to vest in early 2022, the payout is estimated at 121 %.

Stock-based Compensation Plan_9

Stock-based Compensation Plans - PG/RG-PSUs Activities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2021
Performance Share Units Production Growth Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	74.00%
Performance Share Units Reserve Growth Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	121.00%
Minimum [Member] | Performance-based Internal Performance Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Maximum | Performance-based Internal Performance Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	20.00%

Stock-based Compensation Pla_10

Stock-based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Share - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	0.20%	1.40%	2.40%
Expected annual volatility	75.00%	65.00%	46.00%
Grant date fair value per unit	$ 12.58	$ 3.85	$ 11.34

Stock-based Compensation Pla_11

Stock-based Compensation Plans - TSR - PSUs Activities (Detail) - Performance Based TSR - PSUs	12 Months Ended
	Dec. 31, 2021$ / sharesshares
Summary of Performance Share Unit Awards outstanding, Number of Units
Outstanding, Beginning Balance | shares	1,249,524
Granted | shares	223,687	[1]
Vested and issued | shares	(325,217)	[2]
Forfeited | shares	0
Outstanding, Ending Balance | shares	1,147,994
Summary of Performance Share Unit Awards outstanding, Weighted Average Grant Date Fair Value
Outstanding, Beginning Balance, weighted average grant date fair value | $ / shares	$ 9.55
Granted, weighted average grant date fair value | $ / shares	12.58	[1]
Vested, weighted average grant date fair value | $ / shares	18.51	[2]
Forfeited, weighted average grant date fair value | $ / shares	0
Outstanding, Ending Balance, weighted average grant date fair value | $ / shares	$ 7.60
[1]	These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 200 % of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.
[2]	Includes TSR-PSUs awards issued related to the 2018 performance period where the return on our common stock was negative and therefore, the performances multiple and actual payout was reduced to 100 %.

Stock-based Compensation Pla_12

Stock-based Compensation Plans - TSR - PSUs Activities (Parenthetical) (Detail) - Performance Based TSR - PSUs	12 Months Ended
	Dec. 31, 2021
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares on performance units granted	0.00%
Minimum [Member] | March 2018 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares on performance units granted	100.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares on performance units granted	200.00%

Stock-based Compensation Pla_13

Stock-based Compensation Plans - Additional Information 4 (Detail) - USD ($) $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Retirement Benefits [Abstract]
Maximum percentage of employees contribution	75.00%
Maximum percentage of employers contribution in cash	6.00%
Employer contribution	$ 4,600	$ 5,300	$ 5,400
Deferred compensation plan vesting period	3 years
Deferred compensation plan	$ 68,351	$ 12,541	$ (15,472)
Shares held in rabbi trust total	6.2	6.1
Vested shares held in rabbi trust	5.4	5

Stock-based Compensation Pla_14

Stock-based Compensation Plans - Summary of Change in Post Retirement Benefit Obligation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Other Changes in Benefit Obligations in Other Comprehensive Income (Loss):
Net (gain) loss	$ (62)	$ (39)	$ 532
Amortization of prior service cost	(369)	(369)	(369)
Other Post Retirement Benefits
Change in Benefit Obligation:
Benefit obligation at beginning of year	1,953	1,957
Service cost	77	80
Interest cost	38	50
Actuarial (gain) loss	(62)	(39)
Benefits paid	(88)	(95)
Benefit obligation at end of year	1,918	1,953	$ 1,957
Amounts recognized in the consolidated balance sheet:
Long-term liabilities	1,918	1,953
Components of Net Periodic Post Retirement Benefit Cost:
Service cost	77	80
Interest cost	38	50
Amortization of prior service cost	369	369
Net periodic post retirement costs (recognized in general and administrative expense)	484	499
Other Changes in Benefit Obligations in Other Comprehensive Income (Loss):
Net (gain) loss	(62)	(39)
Prior service cost	0	0
Amortization of prior service cost	(369)	(369)
Total recognized in other comprehensive (loss) income	(431)	(408)
Total recognized in net periodic benefit cost and other comprehensive income	$ 53	$ 91

Stock-based Compensation Pla_15

Stock-based Compensation Plans - Summary of Assumptions Used to Determine Benefit Obligation (Detail) - Other Post Retirement Benefits	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Weighted average assumptions used to determine benefit obligation:
Discount rate	2.50%	1.90%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate	7.00%	6.50%
Ultimate trend rate	4.00%	4.50%
Year ultimate trend rate reached	2033	2024

Stock-based Compensation Pla_16

Stock-based Compensation Plans - Additional Information 5 (Detail) - Other Post Retirement Benefits	Dec. 31, 2021USD ($)
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments for the five year period 2021 through 2025	$ 768,000
Expected future benefit payments for the five year period 2026 through 2030	458,000
Estimated prior service cost amortized from accumulated other comprehensive loss into statements of operation in 2021	$ 369,000

Capital Stock - Additional Info

Capital Stock - Additional Information (Detail) - USD ($)	3 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Oct. 31, 2019
Class Of Stock Disclosures [Abstract]
Authorized capital stock					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
New stock purchase program, approved amount							$ 100,000,000
Maximum
Class Of Stock Disclosures [Abstract]
New stock purchase program, approved amount					$ 500,000,000

Capital Stock - Schedule of Cha

Capital Stock - Schedule of Changes in Number of Common Shares Outstanding (Detail) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Class Of Stock [Line Items]
Beginning balance	246,348,092	249,630,803
Restricted stock grants	1,293,892	3,390,358
Treasury shares	3,149	(8,197,662)
Ending balance	249,792,908	246,348,092
Restricted Stock
Class Of Stock [Line Items]
Restricted stock units vested	1,493,341	1,226,473
Performance Share
Class Of Stock [Line Items]
Performance stock units issued	640,468	279,420
Performance stock dividends	13,966	18,700

Capital Stock - Schedule of C_2

Capital Stock - Schedule of Change in Treasury Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Stockholders' Equity Note [Abstract]
Beginning balance	10,005,795	1,808,133
Rabbi trust shares distributed and/or sold	(3,149)	(2,338)
Shares repurchased	0	8,200,000
Ending balance	10,002,646	10,005,795

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net cash provided from operating activities included:
Income taxes paid to taxing authorities		$ 7,061	$ 343	$ 0
Interest paid		(196,750)	(168,471)	(189,443)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	[1]	18,634	2,610	11,193
Decrease in accrued capital expenditures		$ (4,505)	$ (23,625)	$ (20,104)
[1]	Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)	Feb. 10, 2021USD ($)	Dec. 31, 2021USD ($)BblDMcfD	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
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		3,000
2027
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day		18,000
2029
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day		25,000
2034
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day		10,000
2037
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day		3,000
Divestiture Contract Obligation [Member]
Commitments And Contingencies Disclosure [Line Items]
Accrued obligations | $		$ 416,400,000
Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification | McfD		25,000
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract		6 years
Pennsylvania Department of Environmental Protection (“PDEP”)
Commitments And Contingencies Disclosure [Line Items]
Penalty amount paid | $	$ 294,000
Impairment of Proved Property and Other Assets
Commitments And Contingencies Disclosure [Line Items]
Impairment of ROU Asset | $			$ 2,000,000	$ 2,100,000

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Components of Lease Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Commitments And Contingencies Disclosure [Line Items]
Operating lease cost		$ 26,343	$ 27,895
Variable lease expense	[1]	27,243	33,849
Short-term lease expense / costs	[2]	1,950	1,866
Sublease income		(2,380)	(3,199)
Total lease expense		53,156	60,411
Natural Gas and Oil Properties
Commitments And Contingencies Disclosure [Line Items]
Short-term lease expense / costs	[3]	$ 18,984	$ 15,984
[1]	Variable lease payments that are not dependent on an index or rate and 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 and are not included in our ROU assets or lease liability in our consolidated balance sheet.
[3]	These short-term lease costs are related to leases with a contract term of one year or less, the majority of which are related to drilling rigs which 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_3

Commitments and Contingencies - Supplemental Cash Flow Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 28,118	$ 32,030
ROU assets added in exchange for lease obligations	$ 1,059	$ 27,769

Commitments and Contingencies_4

Commitments and Contingencies - Supplemental Balance Sheet Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Loss Contingencies [Line Items]
Operating lease ROU assets	$ 40,832	$ 63,581
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued Liabilities, Current	Accrued Liabilities, Current
Operating lease liabilities – long-term	$ (24,861)	$ (43,155)
Accrued Liabilities [Member]
Loss Contingencies [Line Items]
Accrued liabilities – current	$ (19,066)	$ (24,673)

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, 2021	Dec. 31, 2020
Lessee Disclosure [Abstract]
Weighted average remaining lease term	3 years 9 months 18 days	4 years
Weighted average discount rate	6.00%	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, 2021USD ($)
Commitments and Contingencies Disclosure [Abstract]
2022	$ 21,281
2023	7,207
2024	6,546
2025	6,468
2026	6,168
Thereafter	2,627
Total lease payments	50,297
Less effects of discounting	(6,370)
Operating lease liabilities	$ 43,927

Commitments and Contingencies_7

Commitments and Contingencies - Schedule of Future Minimum Transportation Fees Due (Detail) $ in Thousands	Dec. 31, 2021USD ($)	[1]
Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]
2022	$ 801,974
2023	784,712
2024	768,059
2025	682,050
2026	623,561
Thereafter	3,520,105
Transportation, Gathering and Processing Contracts	$ 7,180,461
[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 - Schedule of Estimated Settlement of Divestiture Contract Obligation Based on Discounted Value (Detail) $ in Thousands	Dec. 31, 2021USD ($)
Disclosure Commitments And Contingencies Schedule Of Estimated Settlement Of Divestiture Contract Obligation [Abstract]
2022	$ 91,120
2023	71,277
2024	58,401
2025	51,688
2026	36,971
Thereafter	106,942
Divestiture Contract Obligation	$ 416,399

Commitments and Contingencies_9

Commitments and Contingencies - Future Delivery Commitments (Detail)	12 Months Ended
	Dec. 31, 2021MmbtuPerDaybbl / d
2022 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	588,158
2022 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	55,000
2023 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	500,710
2023 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	39,932
2024 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	253,566
2024 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	35,000
2025 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	182,493
2025 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	35,000
2026 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	158,301
2026 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	35,000
2027 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	100,000
2027 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	35,000
2028 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	100,000
2028 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	35,000
2029 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	100,000
2029 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000
2030 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	0
2030 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000
2031 | Natural Gas
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	0
2031 | Ethane and Propane
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000

Exit and Termination Costs - Ad

Exit and Termination Costs - Additional Information (Detail) - USD ($)	3 Months Ended					12 Months Ended
	Jun. 30, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restructuring Cost And Reserve [Line Items]
One-time minimum volume commitment contract payment		$ 28,500,000				$ 0	$ 28,500,000	$ 0
Severance costs						567,000	5,909,000	7,535,000
Restructuring Charges						21,661,000	547,409,000	9,506,000
Workforce Reduction
Restructuring Cost And Reserve [Line Items]
Severance costs		3,700,000			$ 2,200,000
North Louisiana
Restructuring Cost And Reserve [Line Items]
Accretion expense						47,900,000	20,200,000
Exit cost		479,800,000
Severance costs		$ 2,500,000				416,400,000
Restructuring Charges	$ 28,200,000
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost			$ 10,400,000			754,000	$ 10,900,000	0
Pennsylvania | Capacity Releases on Transportation Pipelines
Restructuring Cost And Reserve [Line Items]
Exit cost						$ 7,300,000
Northwest Pennsylvania
Restructuring Cost And Reserve [Line Items]
Severance costs				$ 1,400,000
Northwest Pennsylvania | Non-Core Assets
Restructuring Cost And Reserve [Line Items]
Severance costs								$ 819,000

Exit and Termination Costs - Su

Exit and Termination Costs - Summary of Exit and Termination Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restructuring Cost And Reserve [Line Items]
Severance costs			$ 567	$ 5,909	$ 7,535
One-time minimum volume commitment contract payment	$ 28,500		0	28,500	0
Stock-based compensation and other			0	2,165	1,971
Total termination costs			21,661	547,409	9,506
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost		$ 10,400	754	10,900	0
North Louisiana Contract Release
Restructuring Cost And Reserve [Line Items]
Exit cost			$ 20,340	$ 499,935	$ 0

Exit and Termination Costs - Ex

Exit and Termination Costs - Exit and Termination Costs Included in Accrued Liabilities in Consolidated Balance Sheet - (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Exit costs included in accrued liabilities in consolidated balance sheet
Accrued severance costs	$ 567	$ 5,909	$ 7,535
Exit Costs
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	493,543	0
Accrued severance costs	0	0
Accrued contract obligations	27,575	490,114
Accretion of discount	48,669	20,720
Payments	(90,895)	(17,291)
Ending balance	423,742	493,543	0
Termination Costs
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	1,454	4,692
Accrued severance costs	567	5,909
Accrued contract obligations	0	0
Accretion of discount	0	0
Payments	(2,011)	(9,147)
Ending balance	$ 10	$ 1,454	$ 4,692

Suspended Exploratory Well Co_3

Suspended Exploratory Well Costs - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Capitalized Exploratory Well Costs [Abstract]
Capitalized exploratory well costs	$ 0	$ 7,709	$ 0

Suspended Exploratory Well Co_4

Suspended Exploratory Well Costs - Schedule Of Changes In Capitalized Exploratory Well Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs, Beginning Balance	$ 7,709	$ 0
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	6,329	7,709
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	(14,038)	0
Capitalized Exploratory Well Cost, Charged to Expense	0	0
Capitalized Exploratory Well Costs, Ending Balance	0	7,709
Capitalized Exploratory Well Costs that Have Been Capitalized for Period of One Year or Less	0	7,709
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 0	$ 0

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Natural gas and oil properties:
Properties subject to depletion	[1]	$ 9,338,236	$ 8,891,348	$ 9,345,557
Unproved properties	[1]	837,334	859,766	868,180
Total	[1]	10,175,570	9,751,114	10,213,737
Accumulated depreciation, depletion and amortization	[1]	(4,420,914)	(4,064,305)	(4,172,702)
Natural gas and oil properties, successful efforts method, net	[1]	$ 5,754,656	$ 5,686,809	$ 6,041,035
[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, 2021	Dec. 31, 2020	Dec. 31, 2019
Acquisitions
Acreage purchases	[1]	$ 21,942	$ 26,166	$ 57,324
Development	[1]	381,753	369,093	666,984
Exploration:
Exploration drilling costs incurred	[1]	6,329	7,709	0
Gas gathering facilities:
Development	[1]	3,402	3,694	3,583
Subtotal	[1]	436,981	439,317	764,574
Asset retirement obligations	[1]	18,634	2,610	11,193
Total costs incurred	[1]	455,615	441,927	775,767
Exploration Expense
Exploration:
Exploration costs incurred	[1]	22,048	31,376	35,117
Stock-based compensation expense	[1]	$ 1,507	$ 1,279	$ 1,566
[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 Billions		12 Months Ended
		Dec. 31, 2021USD ($)MMcfeBcfe$ / bbl$ / Mcf$ / MMBTUMMBblsMMcf	Dec. 31, 2020MMcfe$ / bbl$ / Mcf$ / MMBTUMMBblsMMcf	Dec. 31, 2019MMcfe$ / bbl$ / Mcf$ / MMBTUMMcfMMBblsMBbls	Dec. 31, 2018MMcfeMMBblsMMcf
Reserve Quantities [Line Items]
Percentage of proved resources reviewed by consultants		97.00%
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		72.00%	80.00%	83.00%
Proved undeveloped reserves dropped		1,300	961,100	601,300
Revision of negative pricing			67,900	17,800
Revisions of positive pricing		22,600
Estimated future development costs over next five years | $		$ 2.2
Proved undeveloped reserves reported for more than five years | Bcfe		21
Crude Oil and NGL
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / bbl		66.34	39.77	55.73
Crude Oil and Condensate
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		59.35	30.13	49.24
Proved developed and undeveloped reserves | MMBbls		52,596	57,626	74,532	85,856
NGLs
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		28.41	16.14	17.32
Proved developed and undeveloped reserves | MMBbls		1,001,305	951,466	938,236	921,594
Natural Gas
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / Mcf		3.30	1.68	2.38
Proved developed and undeveloped reserves | MMcf		11,452,081	11,148,560	12,114,977	12,027,702
Natural Gas, Per Thousand Cubic Feet
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / MMBTU		3.60	1.98	2.58
Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved reserves from drilling activities and evaluations of proved areas	[1]	1,602,769	1,264,282	1,161,274
Proved developed and undeveloped reserve balances	[1]	17,775,484	17,203,114	18,191,583	18,072,406
Revisions of previous estimates	[1]	(252,876)	(608,211)	303,068
Revision of positive performance		1,000	420,900	922,200
Ethane and Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve balances				2,102,000
Proved developed and undeveloped reserves | MBbls				475,000
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, 2021MMcfeMMBblsMMcf	Dec. 31, 2020MMcfeMMBblsMMcf	Dec. 31, 2019MMcfeMMcfMMBbls
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe		7,357,597	7,410,574
Natural Gas
Reserve Quantities [Line Items]
Beginning Balance | MMcf		11,148,560	12,114,977	12,027,702
Revisions | MMcf		(311,410)	(789,992)	33,122
Extensions, discoveries and additions | MMcf		1,155,952	1,007,415	959,901
Property sales | MMcf			(609,311)	(327,634)
Production | MMcf		(541,021)	(574,529)	(578,114)
Ending Balance | MMcf		11,452,081	11,148,560	12,114,977
Proved developed reserves:
Proved developed reserves | MMcf		6,809,849	6,350,057	6,486,211
Proved undeveloped reserves:
Proved undeveloped reserves | MMcf		4,642,232	4,798,503	5,628,766
NGLs
Reserve Quantities [Line Items]
Beginning Balance		951,466	938,236	921,594
Revisions		16,845	42,741	57,311
Extensions, discoveries and additions		69,367	38,298	26,505
Property sales			(30,317)	(28,324)
Production		(36,373)	(37,492)	(38,850)
Ending Balance		1,001,305	951,466	938,236
Proved developed reserves:
Proved developed reserves		577,506	550,771	535,007
Proved undeveloped reserves:
Proved undeveloped reserves		423,798	400,695	403,229
Crude Oil and Condensate
Reserve Quantities [Line Items]
Beginning Balance		57,626	74,532	85,856
Revisions		(7,089)	(12,444)	(12,320)
Extensions, discoveries and additions		5,103	4,512	7,057
Property sales			(6,145)	(2,371)
Production		(3,044)	(2,829)	(3,690)
Ending Balance		52,596	57,626	74,532
Proved developed reserves:
Proved developed reserves		23,833	22,976	34,369
Proved undeveloped reserves:
Proved undeveloped reserves		28,762	34,650	40,163
Natural Gas Equivalents
Proved developed reserves:
Proved developed reserves | MMcfe	[1]	10,417,887	9,792,540	9,902,468
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe	[1]	7,357,597	7,410,574	8,289,115
Beginning Balance | MMcfe	[1]	17,203,114	18,191,583	18,072,406
Revisions | MMcfe	[1]	(252,876)	(608,211)	303,068
Extensions, discoveries and additions | MMcfe	[1]	1,602,769	1,264,282	1,161,274
Property sales | MMcfe	[1]		(828,084)	(511,811)
Production | MMcfe	[1]	(777,523)	(816,456)	(833,354)
Ending Balance | MMcfe	[1]	17,775,484	17,203,114	18,191,583
[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, 2021MMcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves at December 31, 2020	7,410,574
Undeveloped reserves transferred to developed	(1,199,544)
Revisions	(393,561)	[1]
Extension and discoveries	1,540,128
Ending proved undeveloped reserves at December 31, 2020	7,357,597
[1]	Includes 1.3 Tcfe 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)	12 Months Ended
	Dec. 31, 2021MMcfe
Extractive Industries [Abstract]
Proved undeveloped reserves removed and deferred	1,300

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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Extractive Industries [Abstract]
Future cash inflows		$ 69,403,611	$ 35,820,758
Future costs:
Production		(27,015,321)	(23,281,268)
Development	[1]	(2,469,028)	(2,744,539)
Future net cash flows before income taxes		39,919,262	9,794,951
Future income tax expense		8,146,832	(1,240,011)
Total future net cash flows before 10% discount		31,772,430	8,554,940
10% annual discount		(19,287,204)	(5,708,618)
Standardized measure of discounted future net cash flows		$ 12,485,226	$ 2,846,322	$ 6,628,573	$ 11,115,594
[1]	ncludes $ 308.5 million of undiscounted future asset retirement costs as of December 31, 2021, 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	12 Months Ended
	Dec. 31, 2021USD ($)MMcfe
Extractive Industries [Abstract]
Proved undeveloped reserves removed and deferred | MMcfe	1,300
Undiscounted future asset retirement costs estimation | $	$ 308.5

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Revisions of previous estimates
Changes in prices and production costs	$ 11,600,850	$ (4,868,371)	$ (6,560,107)
Revisions in quantities	577,737	(345,073)	(12,741)
Changes in future development and abandonment costs	(53,818)	107,899	104,585
Net change in income taxes	(2,248,161)	797,816	1,125,639
Accretion of discount	298,077	756,083	1,317,349
Additions to proved reserves from extensions, discoveries and improved recovery	1,423,510	280,441	552,710
Natural gas, NGLs and oil sales, net of production costs	(1,934,254)	(402,450)	(881,883)
Actual development costs incurred during the period	399,681	384,530	676,520
Sales of reserves in place	0	(394,125)	(688,937)
Timing and other	(424,718)	(99,001)	(120,156)
Net change for the year	9,638,904	(3,782,251)	(4,487,021)
Beginning of year	2,846,322	6,628,573	11,115,594
End of year	$ 12,485,226	$ 2,846,322	$ 6,628,573