Range Resources (RRC) 10-K 27 Feb 23 2022 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 20, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2022
Document Fiscal Year Focus	2022
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		240,617,237
Entity Public Float			$ 5,979,284,000
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 2023 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, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents		$ 207	$ 214,422
Accounts receivable, less allowance for doubtful accounts of $314 and $568		481,050	471,775
Contingent consideration receivable		24,500	29,500
Derivative assets		925	5,738
Prepaid and other current assets		32,905	15,230
Total current assets		539,587	736,665
Derivative assets		40,990	38,601
Natural gas and oil properties, successful efforts method	[1]	10,655,879	10,175,570
Accumulated depletion and depreciation	[1]	(4,765,475)	(4,420,914)
Natural gas and oil properties, successful efforts method, net	[1]	5,890,404	5,754,656
Other property and equipment		74,638	74,678
Accumulated depreciation and amortization		(72,204)	(71,184)
Other property and equipment, net		2,434	3,494
Operating lease right-of-use assets		84,070	40,832
Other assets		68,077	86,259
Total assets		6,625,562	6,660,507
Current liabilities:
Accounts payable		206,738	178,413
Asset retirement obligations		4,570	5,310
Accrued liabilities		442,922	392,605
Accrued interest		39,138	75,940
Deferred compensation liabilities		89,334	28,293
Derivative liabilities		151,417	162,767
Divestiture contract obligation		86,546	91,120
Current maturities of long-term debt		0	218,017
Total current liabilities		1,020,665	1,152,465
Bank debt		9,509	0
Senior notes		1,832,451	2,707,770
Deferred tax liabilities		333,571	117,642
Derivative liabilities		15,495	8,216
Deferred compensation liabilities		99,907	137,102
Operating lease liabilities		20,903	24,861
Asset retirement obligations and other liabilities		112,981	101,509
Divestiture contract obligation		304,074	325,279
Total liabilities		3,749,556	4,574,844
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, 262,887,265 issued at December 31, 2022 and 259,795,554 issued at December 31, 2021		2,629	2,598
Common stock held in treasury, at cost, 24,001,535 shares at December 31, 2022 and 10,002,646 shares at December 31, 2021		(429,659)	(30,007)
Additional paid-in capital		5,764,970	5,720,277
Accumulated other comprehensive gain (loss)		467	(150)
Retained deficit		(2,462,401)	(3,607,055)
Total stockholders' equity		2,876,006	2,085,663
Total liabilities and stockholders' equity		$ 6,625,562	$ 6,660,507
[1] Includes capitalized asset retirement costs and the associated accumulated amortization.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 314,000	$ 568,000
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	262,887,265	259,795,554
Common stock held in treasury, shares	24,001,535	10,002,646

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues and other income:
Total Revenues from Contracts with Customers	$ 5,335,309,000	$ 3,580,439,000	$ 1,780,986,000
Derivative fair value (loss) income	(1,188,506,000)	(650,216,000)	187,711,000
Total revenues and other income	4,146,803,000	2,930,223,000	1,968,697,000
Costs and expenses:
Taxes other than income	35,367,000	30,648,000	25,649,000
Brokered natural gas and marketing	427,048,000	367,288,000	188,316,000
Exploration	26,772,000	23,555,000	32,654,000
Abandonment and impairment of unproved properties	28,608,000	7,206,000	19,334,000
General and administrative	168,085,000	168,435,000	158,383,000
Exit costs	70,337,000	21,661,000	547,409,000
Deferred compensation plan	61,880,000	68,351,000	12,541,000
Interest	165,145,000	227,336,000	192,667,000
Loss (gain) on early extinguishment of debt	69,493,000	98,000	(14,068,000)
Depletion, depreciation and amortization	353,420,000	364,555,000	394,330,000
Impairment of proved properties and other assets	0	0	78,955,000
Gain on the sale of assets	(409,000)	(701,000)	(110,791,000)
Total costs and expenses	2,732,973,000	2,528,188,000	2,706,026,000
Income (loss) before income taxes	1,413,830,000	402,035,000	(737,329,000)
Income tax (benefit) expense:
Current	14,688,000	7,984,000	(523,000)
Deferred	215,772,000	(17,727,000)	(25,029,000)
Total (benefit) expense for income taxes	230,460,000	(9,743,000)	(25,552,000)
Net income (loss)	$ 1,183,370,000	$ 411,778,000	$ (711,777,000)
Net loss per common share:
Basic	$ 4.79	$ 1.65	$ (2.95)
Diluted	$ 4.69	$ 1.61	$ (2.95)
Weighted average common shares outstanding:
Basic	240,858	242,862	241,373
Diluted	246,379	249,314	241,373
Natural Gas, NGLs and Oil Sales
Revenues and other income:
Total Revenues from Contracts with Customers	$ 4,911,092,000	$ 3,215,027,000	$ 1,607,713,000
Brokered Natural Gas, Marketing and Other
Revenues and other income:
Total Revenues from Contracts with Customers	424,217,000	365,412,000	173,273,000
Direct Operating
Costs and expenses:
Costs and expenses	84,286,000	75,287,000	92,157,000
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 1,242,941,000	$ 1,174,469,000	$ 1,088,490,000

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 1,183,370	$ 411,778	$ (711,777)
Postretirement benefits:
Actuarial gain	482	62	39
Amortization of prior service costs	292	369	369
Income tax expense	(157)	(102)	(99)
Total comprehensive income (loss)	$ 1,183,987	$ 412,107	$ (711,468)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating activities:
Net income (loss)	$ 1,183,370,000	$ 411,778,000	$ (711,777,000)
Adjustments to reconcile net income (loss) to net cash provided from operating activities
Deferred income tax expense (benefit)	215,772,000	(17,727,000)	(25,029,000)
Depletion, depreciation and amortization and impairment of proved properties	353,420,000	364,555,000	473,285,000
Abandonment and impairment of unproved properties	28,608,000	7,206,000	19,334,000
Derivative fair value loss (income)	1,188,506,000	650,216,000	(187,711,000)
Cash settlements on derivative financial instruments	(1,190,154,000)	(520,013,000)	322,629,000
Divestiture contract obligation	69,766,000	20,340,000	499,934,000
Allowance for bad debt	(250,000)	200,000	400,000
Amortization of deferred financing costs and other	7,959,000	8,347,000	7,807,000
Deferred and stock-based compensation	107,959,000	110,356,000	48,552,000
Gain on the sale of assets	(409,000)	(701,000)	(110,791,000)
Loss (gain) on early extinguishment of debt	69,493,000	98,000	(14,068,000)
Changes in working capital:
Accounts receivable	(3,286,000)	(250,538,000)	24,539,000
Prepaid and other	(18,438,000)	(1,140,000)	1,010,000
Accounts payable	17,077,000	39,231,000	(32,686,000)
Accrued liabilities and other	(164,649,000)	(29,260,000)	(46,748,000)
Net cash provided from operating activities	1,864,744,000	792,948,000	268,680,000
Investing activities:
Additions to natural gas and oil properties	(456,505,000)	(393,478,000)	(405,617,000)
Additions to field service assets	(682,000)	(1,231,000)	(2,873,000)
Acreage purchases	(30,885,000)	(23,962,000)	(26,816,000)
Proceeds from disposal of assets	518,000	303,000	246,127,000
Purchases of marketable securities held by the deferred compensation plan	(43,691,000)	(30,806,000)	(17,076,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	41,413,000	31,295,000	22,173,000
Net cash used in investing activities	(489,832,000)	(417,879,000)	(184,082,000)
Financing activities:
Borrowings on credit facilities	972,000,000	1,434,000,000	2,076,000,000
Repayments on credit facilities	(953,000,000)	(2,136,000,000)	(1,851,000,000)
Issuance of senior notes	500,000,000	600,000,000	850,000,000
Repayment of senior or senior subordinated notes	(1,659,422,000)	(63,324,000)	(1,120,634,000)
Dividends paid	(38,638,000)	0	0
Treasury stock purchases	(399,699,000)	0	(22,992,000)
Debt issuance costs	(16,176,000)	(8,854,000)	(13,608,000)
Taxes paid for shares withheld	(25,492,000)	(9,299,000)	(3,324,000)
Change in cash overdrafts	9,071,000	16,493,000	176,000
Proceeds from the sales of common stock held by the deferred compensation plan	22,229,000	5,879,000	696,000
Net cash used in financing activities	(1,589,127,000)	(161,105,000)	(84,686,000)
(Decrease) increase in cash and cash equivalents	(214,215,000)	213,964,000	(88,000)
Cash and cash equivalents at beginning of year	214,422,000	458,000	546,000
Cash and cash equivalents at end of year	$ 207,000	$ 214,422,000	$ 458,000

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	Accumulated other comprehensive loss
Beginning balance at Dec. 31, 2019	$ 2,347,488	$ 2,514	$ (7,236)	$ 5,659,832	$ (3,306,834)	$ (788)
Beginning balance Shares at Dec. 31, 2019		251,439,000	1,808,000
Issuance of common stock	(893)	$ 49	$ 0	(942)	0	0
Issuance of common stock, shares		4,896,000
Issuance of common stock upon vesting of PSUs	0	$ 0	0	74	(74)	0
Issuance of common stock upon vesting of PSUs, shares		19,000
Stock-based compensation expense	25,400	$ 0	0	25,400	0	0
Treasury stock issuance	0	0	$ 96	(96)	0	0
Treasury stock issuance, shares			(2,000)
Treasury stock repurchased	(22,992)	0	$ (22,992)	0	0	0
Treasury stock repurchased, shares			8,200,000
Other comprehensive income	309	0	$ 0	0	0	309
Net income (loss)	(711,777)	0	0	0	(711,777)	0
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		256,354,000	10,006,000
Issuance of common stock	7,033	$ 35	$ 0	6,998	0	0
Issuance of common stock, shares		3,429,000
Issuance of common stock upon vesting of PSUs	0	$ 0	0	148	(148)	0
Issuance of common stock upon vesting of PSUs, shares		13,000
Stock-based compensation expense	28,988	$ 0	0	28,988	0	0
Treasury stock issuance	0	0	$ 125	(125)	0	0
Treasury stock issuance, shares			(3,000)
Other comprehensive income	329	0	$ 0	0	0	329
Net income (loss)	411,778	0	0	0	411,778	0
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	259,796,000	10,003,000
Issuance of common stock	$ 13,560	$ 31	$ 0	13,529	0	0
Issuance of common stock, shares		3,089,000	0
Issuance of common stock upon vesting of PSUs	0	$ 0	$ 0	78	(78)	0
Issuance of common stock upon vesting of PSUs, shares		2,000	0
Stock-based compensation expense	31,133		$ 0	31,133	0	0
Stock-based compensation expense, shares			0
Cash dividends paid ($0.16 per share)	(38,638)	$ 0			(38,638)
Treasury stock issuance	0	0	$ 47	(47)	0
Treasury stock issuance, shares			(1,000)
Treasury stock repurchased	(399,699)		$ (399,699)	0
Treasury stock repurchased, shares			14,000,000
Other comprehensive income	617	0	$ 0	0	0	617
Net income (loss)	1,183,370	0	0	0	1,183,370	0
Ending balance at Dec. 31, 2022	$ 2,876,006	$ 2,629	$ (429,659)	$ 5,764,970	$ (2,462,401)	$ 467
Ending balance Shares at Dec. 31, 2022	262,887,265	262,887,000	24,002,000

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical)	12 Months Ended
	Dec. 31, 2022 $ / shares
Statement of Stockholders' Equity [Abstract]
Cash dividends paid per share	$ 0.16

Summary of Organization and Nat

Summary of Organization and Nature of Business	12 Months Ended
	Dec. 31, 2022
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 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 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, 2022
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. These reclassifications have no impact on previously reported stockholders’ equity, net income or cash flows. 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, 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 some of 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 other 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 a loss of $ 5.4 million in 2022 compared to income of $ 1.1 million in 2021 and a loss of $ 14.2 million in 2020. 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 $ 314,000 at December 31, 2022 compared to $ 568,000 at December 31, 2021. We recorded a reduction in our debt expense of $ 250,000 in the year ended December 31, 2022 compared to debt expense of $ 200,000 in the year ended December 31, 2021 and debt expense of $ 400,000 in the year ended December 31, 2020. 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 of value whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying value of the asset, an impairment loss is recognized based on the fair value of the asset. 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. Natural gas and oil properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. There were no indicators of proved property impairment identified in 2022 or 2021. Proved property impairment recorded in the year ended December 31, 2020 reduced the carrying value of our North Louisiana properties to the anticipated sales proceeds. 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. Unproved properties had a net book value of $ 800.6 million as of December 31, 2022 compared to $ 837.3 million in 2021. We have recorded abandonment and impairment expense related to unproved properties of $ 28.6 million in the year ended December 31, 2022 compared to $ 7.2 million in 2021 and $ 19.3 million in 2020. 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 $ 2.2 million in the year ended December 31, 2022 compared to $ 2.4 million in the year ended December 31, 2021 and $ 2.6 million in the year ended December 31, 2020. 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, 2022 include $ 57.7 million of marketable securities held in our deferred compensation plans and $ 10.4 million of other investments. Other assets at December 31, 2021 included $ 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. 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. 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. We did not materially modify any existing derivative contracts in 2022, 2021 or 2020. Concentrations of Credit Risk As of December 31, 2022, 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, 2022, we had no customer that accounted for 10% or more of natural gas, NGLs and oil sales compared to one customer for the year ended December 31, 2021 and 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, 2022, our derivative counterparties included fourteen financial institutions and commodity traders, of which all but six are secured lenders in our bank credit facility. At December 31, 2022, our net derivative liability includes a payable to four counterparties not included in our bank credit facility totaling $ 4.0 million and a receivable from the remaining two counterparties of $ 3.3 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 ( “ ARO”) 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 properties 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, federal and state regulatory requirements, inflation rates and credit-adjusted-risk-free interest rates. 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, measured by the enacted tax rates, 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 whether we are in a cumulative loss position in recent years, our reversal of temporary differences and 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, 2022
Business Combinations [Abstract]
Dispositions	(3) Dispositions We recognized a pretax net gain on the sale of assets of $ 409,000 in the year ended December 31, 2022 compared to $ 701,000 in 2021 and $ 110.8 million in 2020. The following describes the significant divestitures that are included in our consolidated results of operations for each of years in the three-year period ended December 31, 2022. 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 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 sheets 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.

Revenues from Contracts with Cu

Revenues from Contracts with Customers	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 2020 Natural gas sales $ 3,364,111 $ 1,896,231 $ 943,740 NGLs sales 1,308,574 1,135,826 578,454 Oil and condensate sales 238,407 182,970 85,519 Total natural gas, NGLs and oil sales 4,911,092 3,215,027 1,607,713 Sales of purchased natural gas 408,584 342,431 160,122 Sales of purchased NGLs 2,783 6,925 3,776 Other marketing revenue and other income 12,850 16,056 9,375 Total $ 5,335,309 $ 3,580,439 $ 1,780,986 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, 2022, 2021 and 2020, 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 $ 463.3 million at December 31, 2022 compared to $ 460.2 million at December 31, 2021.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	(5) Income Taxes Our income tax expense was $ 230.5 million for the year ended December 31, 2022 compared to a benefit of $ 9.7 million in 2021 and a benefit of $ 25.6 million in 2020. The effective income tax rate is influenced by a variety of factors including geographic sources and relative magnitude of these sources of income. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State, net of federal benefit 1.0 4.0 5.2 State rate and law change — ( 3.4 ) 4.3 Equity compensation — 2.3 ( 1.0 ) Valuation allowances ( 5.5 ) ( 26.8 ) ( 25.9 ) Permanent differences and other ( 0.2 ) 0.5 ( 0.1 ) Consolidated effective tax rate 16.3 % ( 2.4 )% 3.5 % Income tax expense (benefit) attributable to income (loss) before income taxes consists of the following (in thousands): 2022 2021 2020 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ 245,839 $ 245,839 $ — $ 6,297 $ 6,297 $ ( 366 ) $ ( 24,489 ) $ ( 24,855 ) U.S. state and local 14,688 ( 30,067 ) ( 15,379 ) 7,984 ( 24,024 ) ( 16,040 ) ( 157 ) ( 540 ) ( 697 ) Total $ 14,688 $ 215,772 $ 230,460 $ 7,984 $ ( 17,727 ) $ ( 9,743 ) $ ( 523 ) $ ( 25,029 ) $ ( 25,552 ) Significant components of deferred tax assets and liabilities are as follows: December 31, 2022 2021 (in thousands) Deferred tax assets: Net operating loss carryforward $ 581,349 $ 788,375 Divestiture contract obligation 105,227 112,199 Deferred compensation 25,733 22,121 Equity compensation 4,813 4,833 Asset retirement obligations 24,113 21,734 Interest expense carryforward 16,118 53,876 Lease right-of-use liabilities 19,395 9,954 Cumulative mark-to-market loss 30,307 32,221 Other 16,922 12,181 Valuation allowances: Federal ( 21,320 ) ( 67,984 ) State, net of federal benefit ( 171,423 ) ( 203,085 ) Total deferred tax assets 631,234 786,425 Deferred tax liabilities: Depreciation and depletion ( 935,710 ) ( 879,163 ) Lease right-of-use assets ( 18,440 ) ( 9,247 ) Other ( 10,655 ) ( 15,657 ) Total deferred tax liabilities ( 964,805 ) ( 904,067 ) Net deferred tax liability $ ( 333,571 ) $ ( 117,642 ) At December 31, 2022, deferred tax liabilities exceeded deferred tax assets by $ 333.6 million. As of December 31, 2022, we have a state valuation allowance of $ 171.4 million related to state tax attributes in Louisiana, Oklahoma, Pennsylvania, Texas and West Virginia. As of December 31, 2022, we have federal valuation allowances of $ 21.3 million primarily related to our federal basis differences. The net change in our deferred tax asset valuation allowances was a reduction of $ 78.3 million for the year ended December 31, 2022 compared to a reduction in our valuation allowances of $ 108.0 million in 2021 and an increase of $ 188.2 million in 2020. We continue to evaluate the realizability of our federal and state deferred tax assets and, in 2022, based upon significant increases in commodity prices, our 2022 results and other positive evidence, we released a significant portion of our federal and state valuation allowances. At December 31, 2022, we had federal NOL carryforwards of $ 2.0 billion. This includes $ 374.5 million that expires in 2036 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 $ 825.9 million that expire between 2031 and 2042 and in Louisiana, we have state NOL carryforwards of $ 1.6 billion that do not expire. We file a consolidated tax return 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 2018 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 material accrued interest or penalties related to tax amounts as of December 31, 2022 or December 31, 2021. Throughout 2022, 2021 and 2020, our unrecognized tax benefits were not material. On July 12, 2022, the Commonwealth of Pennsylvania enacted legislation to reduce the corporate net income tax rate from 9.99 % to 8.99 % in 2023 and continues to reduce that rate by 0.5 % per year beginning in 2024, with the rate becoming 4.99 % in 2031 and each year thereafter. We recorded a $ 20.7 million tax benefit in third quarter 2022 for the impact of this tax rate reduction which is reflected as a reduction to our Pennsylvania valuation allowance. On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”) into law. The IRA contains a number of revisions to the Internal Revenue Code, including a 15 % corporate minimum income tax for tax years beginning after December 31, 2022. While these tax law changes have no immediate effect and are not expected to have a material adverse effect on our results of operations going forward, we will continue to evaluate their impact as further information becomes available.

Net Income (Loss) Per Common Sh

Net Income (Loss) Per Common Share	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 2020 Net income (loss), as reported $ 1,183,370 $ 411,778 $ ( 711,777 ) Participating basic earnings (a) ( 28,578 ) ( 10,795 ) — Basic net income (loss) attributed to common stockholders 1,154,792 400,983 ( 711,777 ) Reallocation of participating earnings (a) 614 272 — Diluted net income (loss) attributed to common stockholders $ 1,155,406 $ 401,255 $ ( 711,777 ) Net income (loss) per common share: Basic $ 4.79 $ 1.65 $ ( 2.95 ) Diluted $ 4.69 $ 1.61 $ ( 2.95 ) (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, 2022 2021 2020 Denominator: Weighted average common shares outstanding – basic 240,858 242,862 241,373 Effect of dilutive securities 5,521 6,452 — Weighted average common shares outstanding – diluted 246,379 249,314 241,373 Weighted average common shares outstanding – basic excludes 6.1 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for the period ending December 31, 2022 compared to 6.5 million shares for the period ending December 31, 2021 and 5.5 million shares for the period ending December 31, 2020. Due to our net loss for the year ended December 31, 2020, 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 5,000 shares for the year ended December 31, 2022 and equity grants of 18,000 shares 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, 2022
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. 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. For December 31, 2021, deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. No interest was capitalized in the three-year period ended December 31, 2022. The components of our debt outstanding, including the effects of debt issuance costs, is as follows (in thousands): December 31, 2022 2021 Bank debt $ 19,000 $ — Senior notes 4.75 % senior notes due 2030 500,000 — 4.875 % senior notes due 2025 750,000 750,000 5.00 % senior notes due 2022 — 169,589 5.00 % senior notes due 2023 — 532,335 5.875 % senior notes due 2022 — 48,528 8.25 % senior notes due 2029 600,000 600,000 9.25 % senior notes due 2026 — 850,000 Total senior notes 1,850,000 2,950,452 Total debt 1,869,000 2,950,452 Unamortized premium — 188 Unamortized debt issuance costs ( 27,040 ) ( 24,853 ) Total debt (net of debt issuance costs) 1,841,960 2,925,787 Less current maturities of long-term debt — ( 218,017 ) Total long-term debt $ 1,841,960 $ 2,707,770 Bank Debt In April 2022, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, and is secured by substantially all of our assets and has a maturity date of April 14, 2027 . 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 seventeen financial institutions. 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 secured overnight financing rate (“SOFR”), 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 SOFR loans to ABR loans or to convert all or any part of our ABR loans to SOFR loans. The weighted average interest rate was 4.1 % for the year ended December 31, 2022 compared to 2.1 % for the year ended December 31, 2021 and 2.6 % for the year ended December 31, 2020. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375 % to 0.50 %. At December 31, 2022, the commitment fee was 0.375 %, the interest rate margin was 0.75 % on our ABR loans and 1.75 % on our SOFR loans. On December 31, 2022, bank commitments totaled $ 1.5 billion and we had outstanding borrowings under our bank credit facility of $ 19.0 million. Additionally, we had $ 307.4 million of undrawn letters of credit leaving $ 1.2 billion of committed borrowing capacity available under the facility. As part of our redetermination completed in September 2022, our borrowing base was reaffirmed for $ 3.0 billion and our bank commitment was also reaffirmed at $ 1.5 billion. New Senior Notes 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 $ 492.5 million after underwriting discounts and commissions of $ 7.5 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 ended December 31, 2022, we recorded a loss on early extinguishment of debt of approximately $ 69.2 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt. Senior Note Redemptions 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. We currently intend to retire our outstanding long-term debt as it matures, is callable or when market conditions are favorable to repurchase in the open market. In second quarter 2022, we retired our 5.00% senior notes due 2022 and our 5.875% senior notes due 2022 on their maturity dates. In third quarter 2022, we purchased in the open market $ 3.8 million aggregate principal amount of our 5.00 % senior notes due 2023 . In fourth quarter 2022, we announced a call for the redemption of the remaining 5.00 % senior notes due 2023 at par and we recognized a loss on early extinguishment of debt of $ 261,000 reflecting the expensing of the remaining deferred financing costs. 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. The assets, liabilities and results of operations of Range and our guarantor subsidiaries are not materially different than our consolidated financial statements. 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. We are required to maintain a ratio of EBITDAX (as defined in the credit agreement) of 3.75 x and a minimum current ratio (as defined in the credit agreement) of 1.0 x. We were in compliance with applicable covenants under the bank credit facility at December 31, 2022. The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2022 (in thousands): Year Ended 2023 $ — 2024 — 2025 750,000 2026 — 2027 19,000 Thereafter 1,100,000 $ 1,869,000

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(8) Asset Retirement Obligations ARO primarily represents 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, 2022 and 2021 (in thousands): 2022 2021 Beginning of period $ 95,836 $ 79,822 Liabilities incurred 2,589 73 Liabilities settled ( 10,650 ) ( 8,197 ) Accretion expense 6,569 5,511 Change in estimate 15,507 18,627 End of period 109,851 95,836 Less current portion ( 4,570 ) ( 5,310 ) Long-term asset retirement obligations $ 105,281 $ 90,526 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, 2022
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 swaps 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), approximated a net derivative liability of $ 138.6 million at December 31, 2022. These contracts expire monthly through December 2024. The following table sets forth the derivative volumes by year as of December 31, 2022, excluding our basis 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 2023 Swaps 376,384 Mmbtu/day $ 3.44 2023 Collars 278,082 Mmbtu/day $ 3.60 $ 4.78 2023 Three-way Collars 187,233 Mmbtu/day $ 2.67 $ 3.74 $ 4.83 2024 Swaps 110,000 Mmbtu/day $ 4.63 2024 Collars 469,235 Mmbtu/day $ 3.55 $ 5.51 Crude Oil 2023 Swaps 5,123 bbls/day $ 71.39 January-September 2024 Collars 832 bbls/day $ 80.00 $ 90.12 Basis Swap Contracts In addition to the swaps and collars above, at December 31, 2022, 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 2026 and include a total volume of 288,555,000 Mmbtu. The fair value of these contracts was a net derivative asset of $ 521,000 on December 31, 2022. 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 $ 21.0 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 year ending 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, 2022 was a derivative asset of $ 13.1 million. In addition, we currently expect to receive $ 24.5 million for the year ended December 31, 2022 which is reflected in current assets in the accompanying consolidated balance sheet and represents the maximum contingent payment amount for 2022. Derivative Assets and Liabilities The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2022 and 2021 is summarized below (in thousands). As of December 31, 2022, we are conducting derivative activities with fourteen counterparties, of which all but six 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, 2022 Gross Amounts of Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 19,438 $ ( 6,236 ) $ 13,202 –collars 54,222 ( 45,452 ) 8,770 –three-way collars 12,424 ( 12,424 ) — –basis swaps 25,493 ( 20,437 ) 5,056 Crude oil –collars 1,807 — 1,807 Divestiture contingent consideration 13,080 — 13,080 $ 126,464 $ ( 84,549 ) $ 41,915 December 31, 2022 Gross Amounts of Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ ( 115,374 ) $ 6,236 $ ( 109,138 ) –collars ( 72,866 ) 45,452 ( 27,414 ) –three-way collars ( 24,341 ) 12,424 ( 11,917 ) –basis swaps ( 24,972 ) 20,437 ( 4,535 ) Crude oil –swaps ( 13,908 ) — ( 13,908 ) $ ( 251,461 ) $ 84,549 $ ( 166,912 ) December 31, 2021 Gross Amounts of Gross Amounts Offset 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 Amounts of 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 ) 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, 2022 2021 2020 Commodity swaps $ ( 713,122 ) $ ( 466,203 ) $ 158,248 Swaptions 11,149 ( 1,346 ) ( 4,955 ) Collars ( 302,364 ) ( 117,612 ) 3,304 Three-way collars ( 235,335 ) ( 137,443 ) ( 16,346 ) Basis swaps 41,622 33,691 48,278 Calls ( 1,363 ) ( 836 ) ( 558 ) Freight swaps ( 33 ) ( 647 ) ( 1,230 ) Divestiture contingent consideration 10,940 40,180 970 Total $ ( 1,188,506 ) $ ( 650,216 ) $ 187,711

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
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, 2022 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred $ 57,717 $ — $ — $ 57,717 Derivatives –swaps — ( 109,844 ) — ( 109,844 ) –collars — ( 16,837 ) — ( 16,837 ) –three-way collars — ( 11,917 ) — ( 11,917 ) –basis swaps — 521 — 521 Divestiture contingent consideration — 13,080 — 13,080 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 Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2022 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 but will also utilize unobservable pricing inputs that are significant to overall value. At December 31, 2022, we have no Level 3 measurements. 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, 2021 $ ( 12,421 ) Settlements 1,272 Transfers out of Level 3 11,149 Balance at December 31, 2022 $ — 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, 2022, interest and dividends were $ 1.1 million and mark-to-market was a loss of $ 14.2 million. 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. North Louisiana 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 use 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. 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. Fair Values-Reported The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2022 and 2021 (in thousands): December 31, 2022 December 31, 2021 Carrying Fair Carrying Fair Assets: Commodity swaps, collars and basis swaps $ 28,835 $ 28,835 $ 17,699 $ 17,699 Divestiture contingent consideration 13,080 13,080 26,640 26,640 Marketable securities (a) 57,717 57,717 69,606 69,606 (Liabilities): Commodity swaps, collars and basis swaps ( 166,912 ) ( 166,912 ) ( 170,983 ) ( 170,983 ) Bank credit facility (b) ( 19,000 ) ( 19,000 ) — — 5.00 % senior notes due 2022 (b) — — ( 169,589 ) ( 171,488 ) 5.875 % senior notes due 2022 (b) — — ( 48,528 ) ( 48,955 ) 5.00 % senior notes due 2023 (b) — — ( 532,335 ) ( 543,471 ) 4.875 % senior notes due 2025 (b) ( 750,000 ) ( 714,870 ) ( 750,000 ) ( 776,153 ) 9.25 % senior notes due 2026 (b) — — ( 850,000 ) ( 916,929 ) 8.25 % senior notes due 2029 (b) ( 600,000 ) ( 618,312 ) ( 600,000 ) ( 669,648 ) 4.75 % senior notes due 2030 (b) ( 500,000 ) ( 442,350 ) — — Deferred compensation plan (c) ( 189,241 ) ( 189,241 ) ( 165,395 ) ( 165,395 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are 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 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, 2022
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, 2022 (in thousands): 2022 2021 2020 Direct operating expense $ 1,459 $ 1,310 $ 1,078 Brokered natural gas and marketing expense 2,439 1,794 1,416 Exploration expense 1,578 1,507 1,279 General and administrative expense 42,023 39,673 32,905 Exit costs — — 2,165 Total stock-based compensation $ 47,499 $ 44,284 $ 38,843 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 plan 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 2022, we recorded an additional tax benefit of an estimated $ 7.2 million 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 benefit of $ 340,000 in 2021 and additional tax expense of $ 4.3 million in 2020. 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 with us. 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 the end of 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 (“ TSR” awards). Restricted Stock – Equity Awards In 2022, we granted 1.4 million restricted stock Equity Awards to employees which generally vest over a three-year period compared to 2.3 million in 2021 and 4.5 million in 2020. We recorded compensation expense for these awards of $ 21.0 million in the year ended December 31, 2022 compared to $ 19.6 million in 2021 and $ 17.8 million in 2020. As of December 31, 2022, there was $ 23.3 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.7 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 2022, we granted 650,000 shares of restricted stock Liability Awards as compensation to non-employee directors and employees at an average grant date fair value of $ 20.94 . These grants included 47,000 shares issued to non-employee directors, which vest at the end of one year and 603,000 shares to employees with vesting generally at the end of a three-year period. 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 . This grant included 102,000 shares issued to non-employee directors, which vested at the end of one year and 1.2 million shares to employees with vesting generally at the end of 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 . These grants 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. We recorded compensation expense for these restricted stock Liability Awards of $ 13.6 million in the year ended December 31, 2022 compared to $ 11.4 million in 2021 and $ 10.3 million in 2020. As of December 31, 2022, there was $ 4.6 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of 1.1 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 $ 22.2 million in 2022 compared to $ 5.9 million in 2021 and $ 696,000 in 2020. The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2022: Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2021 2,674,777 $ 7.39 796,629 $ 6.49 Granted 1,405,660 18.66 650,314 20.94 Vested ( 2,283,837 ) 8.88 ( 1,067,310 ) 12.38 Forfeited ( 59,912 ) 10.29 — — Outstanding at December 31, 2022 1,736,688 $ 14.44 379,633 $ 14.71 Stock-Based Performance Units Internal Performance Metric Awards. These awards are earned, or not earned, based on performance metrics set by the compensation committee of our board of directors over a three-year performance period. The actual payout may be between 0 % and 200 % of the performance units granted and each unit represents the value of one share of our common share. Dividend equivalents, if any, accrue during the performance period and are paid in stock at the end of the performance period. Internal performance metric awards granted in 2022 are earned based on: • Net debt (total debt less cash balance); and • GHG emissions intensity. Internal performance metric awards granted in 2021 are earned based on: • Debt/EBITDAX (earnings before interest, taxes, depreciation and amortization, and exploration expense); and • GHG emissions intensity. Internal performance metric awards granted in 2020 were earned based on: • Debt and adjusted per share Production Growth; and • Debt and adjusted per share Reserve Growth. Prior to 2021, the performance period was based on annual performance targets earned over a three-year period. For awards granted in 2021 and 2022, the three-year target was set in the first quarter of the grant year. 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, 2022: Number of Weighted Outstanding at December 31, 2021 1,095,355 $ 7.80 Units granted (a) 153,089 20.38 Vested (b) ( 243,482 ) 9.64 Forfeited — — Outstanding at December 31, 2022 1,004,962 $ 9.27 (a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares may be between zero and 200 % depending on achievement of specifically identified performance targets. (b) For awards granted in 2019, the aggregate payout was approximately 116 % of target with a positive performance adjustment of 158,793 shares. We recorded internal performance metric award compensation expense of $ 6.2 million in the year ended December 31, 2022 compared to $ 6.6 million in the year ended December 31, 2021 and $ 2.7 million in the year ended December 31, 2020. As of December 31, 2022, there was $ 1.8 million of unrecognized compensation related to these internal performance metric awards to be recognized over a weighted average period of 1.1 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. The actual payout of shares may be between zero and 200 % of the performance units granted depending on the total stockholder return ranking compared to our peer companies on the vesting date. 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, 2022, 2021 and 2020: Year Ended December 31, 2022 2021 2020 Risk-free interest rate 1.4 % 0.2 % 1.4 % Expected annual volatility 68 % 75 % 65 % Grant date fair value per unit $ 27.90 $ 12.58 $ 3.85 The following is a summary of our non-vested TSR award activities: Number of Units Weighted Outstanding at December 31, 2021 1,147,994 $ 7.60 Granted (a) 111,828 27.90 Vested and issued (b) ( 314,152 ) 11.34 Forfeited — — Outstanding at December 31, 2022 945,670 $ 8.76 (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 awards issued related to the 2019 performance period where the return on our common stock was 127 % and therefore, the performances multiple and actual payout was 183 %. We recorded TSR award compensation expense of $ 3.2 million in the year ended December 31, 2022 compared to $ 2.6 million in the year ended December 31, 2021 and $ 2.4 million in the year ended December 31, 2020. As of December 31, 2022, there was $ 1.5 million of unrecognized compensation related to these TSR awards to be recognized over a weighted average period of 1.3 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 2022, we contributed $ 4.8 million to the 401(k) Plan compared to $ 4.6 million in 2021 and $ 5.3 million in 2020. 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 at the end of 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 $ 61.9 million in 2022 compared to a loss of $ 68.4 million in 2021 and a loss of $ 12.5 million in 2020. The Rabbi Trust held 5.6 million shares ( 5.3 million of vested shares) of Range stock at December 31, 2022 compared to 6.2 million ( 5.4 million of vested shares) at December 31, 2021.

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2022
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 2021: Year Ended December 31, 2022 2021 Beginning balance 249,792,908 246,348,092 Restricted stock grants 671,303 1,293,892 Restricted stock units vested 1,827,625 1,493,341 Performance stock units vested 590,940 640,468 Performance stock dividends 1,843 13,966 Treasury shares ( 13,998,889 ) 3,149 Ending balance 238,885,730 249,792,908 Common Stock Dividends In January 2020, we announced that the board of directors had suspended our common stock dividend. The quarterly cash dividend was reinstated by our board of directors in third quarter 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 deems 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 of directors approved an increase to this stock purchase plan where the board of directors authorized an additional repurchase of up to $ 430.0 million for an aggregate available amount at that time of $ 500.0 million. In October 2022, our board of directors authorized an additional repurchase of $ 1.0 billion for common stock repurchases. Under this program, we may repurchase shares of our common stock in open market transactions, from time to time, in accordance with applicable SEC rules and federal securities laws. In 2022, we repurchased 14.0 million shares at an aggregate value of $ 399.7 million. The following is a schedule of the change in treasury shares since the beginning of 2021: Year Ended December 31, 2022 2021 Beginning balance 10,002,646 10,005,795 Rabbi trust shares distributed and/or sold ( 1,111 ) ( 3,149 ) Shares repurchased 14,000,000 — Ending balance 24,001,535 10,002,646

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(13) Supplemental Cash Flow Information Year Ended December 31, 2022 2021 2020 (in thousands) Net cash provided from operating activities included: Income taxes paid to taxing authorities $ ( 20,335 ) $ ( 7,061 ) $ ( 343 ) Interest paid ( 193,732 ) ( 196,750 ) ( 168,471 ) Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 18,096 $ 18,634 $ 2,610 Increase (decrease) in accrued capital expenditures 1,966 ( 4,505 ) ( 23,625 )

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021, liabilities for remediation were not material. We are not aware of any environmental claims existing as of December 31, 2022 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. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. 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, 2022, the majority of which is included as part of natural gas and oil properties on our consolidated balance sheets, are as follows (in thousands): Year Ended December 31, 2022 2021 Operating lease cost $ 37,873 $ 26,343 Variable lease expense (1) 22,082 27,243 Short-term lease expense (2) 1,807 1,950 Sublease income ( 137 ) ( 2,380 ) Total lease expense $ 61,625 $ 53,156 Short-term lease costs (3) $ 17,285 $ 18,984 (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 sheets. (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, 2022 2021 Cash paid for amounts included in the measurement of lease $ 37,457 $ 28,118 ROU assets added in exchange for lease obligations $ 78,574 $ 1,059 Supplemental balance sheet information related to our operating leases is included in the table below (in thousands): Year Ended December 31, 2022 2021 Operating lease ROU assets $ 84,070 $ 40,832 Accrued liabilities – current $ ( 67,493 ) $ ( 19,066 ) Operating lease liabilities – long-term $ ( 20,903 ) $ ( 24,861 ) Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows: Year Ended December 31, 2022 2021 Weighted average remaining lease term 2.0 years 3.8 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 2023 $ 70,873 2024 8,119 2025 6,576 2026 6,167 2027 2,626 Total lease payments 94,361 Less effects of discounting ( 5,965 ) Total lease liability $ 88,396 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 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, 2022, future minimum transportation and gathering fees under our commitments are as follows (in thousands): Transportation (a) 2023 $ 801,850 2024 782,445 2025 694,670 2026 635,929 2027 582,580 Thereafter 2,971,614 $ 6,469,088 (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 1.8 bcf per day and is expected to begin in 2024 with a thirteen-year term. Volumes under this agreement decline in the last five years of the contract, ending at 810,000 mcf per day. Not included in the table above is our estimate of accrued contractual 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, Note 10 and Note 15 for more information. As of December 31, 2022, the carrying value of this obligation was $ 390.6 million and is included in divestiture contract obligation in our consolidated balance sheets. As of December 31, 2022, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands): Divestiture 2023 $ 86,546 2024 73,916 2025 64,276 2026 45,773 2027 37,743 Thereafter 82,366 $ 390,620 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, 2022, our delivery commitments through 2037 were as follows: Year Ending December 31, Natural Gas Ethane and Propane 2023 365,000 50,000 2024 261,899 50,000 2025 182,493 50,000 2026 158,301 50,000 2027 100,000 46,233 2028 100,000 45,000 2029 100,000 33,444 2030 — 30,000 2031 — 16,575 2032-2037 — 10,000 (each year) 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 15,000 bbls per day starting in 2027 through 2033. 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 Costs

Exit Costs	12 Months Ended
	Dec. 31, 2022
Restructuring and Related Activities [Abstract]
Exit Costs	(15) Exit 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 sheets. In the twelve months ended December 31, 2022, we recorded accretion expense of $ 43.6 million compared to $ 47.9 million in 2021 and $ 20.2 million in 2020. In second quarter 2022, we recorded a net unfavorable adjustment of $ 24.8 million to increase this obligation for a change in our forecasted drilling plans of the buyer along with adjusting the difference between estimated and actual payments. In second quarter 2021, we 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. The present value of our estimated obligations related to these assets was initially recorded in 2020 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 $ 390.6 million at December 31, 2022. 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, 2022 was $ 5.1 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. The following summarizes our exit and termination costs for the three years ended December 31, 2022, 2021 and 2020 (in thousands): Year Ended December 31, 2022 2021 2020 Severance costs $ — $ 567 $ 5,909 Transportation contract capacity releases (including 579 754 10,900 Divestiture contract obligation (including accretion 69,758 20,340 499,935 One-time minimum volume commitment contract — — 28,500 Stock-based compensation and other — — 2,165 $ 70,337 $ 21,661 $ 547,409 The following details the accrued exit and termination cost liability activity for the years ended December 31, 2022 and 2021 (in thousands): Exit Costs Termination Costs 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 Accrued contract obligations-changes in estimate 26,183 — Accretion of discount 44,154 — Payments ( 98,399 ) ( 10 ) Balance at December 31, 2022 $ 395,680 $ —

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2022
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, 2022. 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, 2022
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, 2022 2021 2020 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 9,855,287 $ 9,338,236 $ 8,891,348 Unproved properties 800,592 837,334 859,766 Total 10,655,879 10,175,570 9,751,114 Accumulated depreciation, depletion and ( 4,765,475 ) ( 4,420,914 ) ( 4,064,305 ) Net capitalized costs $ 5,890,404 $ 5,754,656 $ 5,686,809 (a) Includes capitalized asset retirement costs and the associated accumulated amortization. Costs Incurred for Property Acquisition, Exploration and Development (a) December 31, 2022 2021 2020 (in thousands) Acquisitions: Acreage purchases $ 28,735 $ 21,942 $ 26,166 Development 460,668 381,753 369,093 Exploration: Drilling — 6,329 7,709 Expense 25,194 22,048 31,376 Stock-based compensation expense 1,578 1,507 1,279 Gas gathering facilities: Development 1,466 3,402 3,694 Subtotal 517,641 436,981 439,317 Asset retirement obligations 18,096 18,634 2,610 Total costs incurred $ 535,737 $ 455,615 $ 441,927 (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 2022, Netherland, Sewell & Associates, Inc., an independent petroleum consultant, conducted an audit of our 2022 reserves in Appalachia. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2022, our consultant audited approximately 96 % 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, 2022 to estimate reserve information were $ 87.14 per barrel of oil, $ 38.35 per barrel of NGLs and $ 6.08 per mcf for gas using a benchmark (NYMEX) of $ 94.13 per barrel and $ 6.36 per Mmbtu. 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. Natural Gas NGLs Crude Oil Natural (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: 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 Revisions ( 393,165 ) ( 20,251 ) ( 12,885 ) ( 591,983 ) Extensions, discoveries and additions 1,278,499 59,296 5,661 1,668,244 Production ( 539,443 ) ( 36,392 ) ( 2,716 ) ( 774,089 ) Balance, December 31, 2022 11,797,972 1,003,958 42,656 18,077,656 Proved developed reserves: 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 December 31, 2022 7,230,313 594,931 22,213 10,933,180 Proved undeveloped reserves: 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 December 31, 2022 4,567,659 409,027 20,443 7,144,476 (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 2022, we added approximately 1.7 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 77 % of the 2022 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 592.0 Bcfe include a positive revision of 716.2 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan, positive performance revisions of 72.8 Bcfe and positive pricing revisions more than offset by 1.4 Tcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. These wells were removed due to the outperformance of existing wells which resulted in a higher utilization of in-field gathering capacity and a reallocation of capital due to the drilling of longer laterals on existing locations. 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. The following details the changes in proved undeveloped reserves for 2022 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2021 7,357,597 Undeveloped reserves transferred to developed ( 1,091,828 ) Revisions (a) ( 759,281 ) Extension and discoveries 1,637,988 Ending proved undeveloped reserves at December 31, 2022 7,144,476 (a) Includes 1.4 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. Includes 716.2 Bcfe positive revision for previously proved undeveloped properties due to their addition back into our five year development plan. During 2022, we spent approximately $ 430.0 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 $ 3.0 billion over the next five years. As of December 31, 2022, we have 87.8 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 2023. 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 2027. 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 2022, 2021 and 2020, 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, 2022 2021 (in thousands) Future cash inflows $ 113,954,835 $ 69,403,611 Future costs: Production ( 31,991,109 ) ( 27,015,321 ) Development (a) ( 3,313,724 ) ( 2,469,028 ) Future net cash flows before income taxes 78,650,002 39,919,262 Future income tax expense ( 16,651,625 ) ( 8,146,832 ) Total future net cash flows before 10% discount 61,998,377 31,772,430 10% annual discount ( 37,453,094 ) ( 19,287,204 ) Standardized measure of discounted future net cash $ 24,545,283 $ 12,485,226 (a) 2022 includes $ 361.9 million of undiscounted future asset retirement costs as of December 31, 2022, 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, 2022 2021 2020 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ 14,326,997 $ 11,600,850 $ ( 4,868,371 ) Revisions in quantities 109,129 577,737 ( 345,073 ) Changes in future development and abandonment ( 524,847 ) ( 53,818 ) 107,899 Net change in income taxes ( 2,625,699 ) ( 2,248,161 ) 797,816 Accretion of discount 1,486,783 298,077 756,083 Additions to proved reserves from extensions, 2,842,173 1,423,510 280,441 Natural gas, NGLs and oil sales, net of production ( 3,550,632 ) ( 1,934,254 ) ( 402,450 ) Actual development costs incurred during the 471,877 399,681 384,530 Sales of reserves in place — — ( 394,125 ) Timing and other ( 475,724 ) ( 424,718 ) ( 99,001 ) Net change for the year 12,060,057 9,638,904 ( 3,782,251 ) Beginning of year 12,485,226 2,846,322 6,628,573 End of year $ 24,545,283 $ 12,485,226 $ 2,846,322

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
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. These reclassifications have no impact on previously reported stockholders’ equity, net income or cash flows.
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 some of 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 other 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 a loss of $ 5.4 million in 2022 compared to income of $ 1.1 million in 2021 and a loss of $ 14.2 million in 2020. 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 $ 314,000 at December 31, 2022 compared to $ 568,000 at December 31, 2021. We recorded a reduction in our debt expense of $ 250,000 in the year ended December 31, 2022 compared to debt expense of $ 200,000 in the year ended December 31, 2021 and debt expense of $ 400,000 in the year ended December 31, 2020.
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 of value whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying value of the asset, an impairment loss is recognized based on the fair value of the asset. 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. Natural gas and oil properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. There were no indicators of proved property impairment identified in 2022 or 2021. Proved property impairment recorded in the year ended December 31, 2020 reduced the carrying value of our North Louisiana properties to the anticipated sales proceeds. 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. Unproved properties had a net book value of $ 800.6 million as of December 31, 2022 compared to $ 837.3 million in 2021. We have recorded abandonment and impairment expense related to unproved properties of $ 28.6 million in the year ended December 31, 2022 compared to $ 7.2 million in 2021 and $ 19.3 million in 2020. 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 $ 2.2 million in the year ended December 31, 2022 compared to $ 2.4 million in the year ended December 31, 2021 and $ 2.6 million in the year ended December 31, 2020.
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, 2022 include $ 57.7 million of marketable securities held in our deferred compensation plans and $ 10.4 million of other investments. Other assets at December 31, 2021 included $ 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.
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. 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. We did not materially modify any existing derivative contracts in 2022, 2021 or 2020.
Concentrations of Credit Risk	Concentrations of Credit Risk As of December 31, 2022, 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, 2022, we had no customer that accounted for 10% or more of natural gas, NGLs and oil sales compared to one customer for the year ended December 31, 2021 and 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, 2022, our derivative counterparties included fourteen financial institutions and commodity traders, of which all but six are secured lenders in our bank credit facility. At December 31, 2022, our net derivative liability includes a payable to four counterparties not included in our bank credit facility totaling $ 4.0 million and a receivable from the remaining two counterparties of $ 3.3 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 ( “ ARO”) 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 properties 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, federal and state regulatory requirements, inflation rates and credit-adjusted-risk-free interest rates. 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, measured by the enacted tax rates, 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 whether we are in a cumulative loss position in recent years, our reversal of temporary differences and 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, 2022
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, 2022 2021 2020 Natural gas sales $ 3,364,111 $ 1,896,231 $ 943,740 NGLs sales 1,308,574 1,135,826 578,454 Oil and condensate sales 238,407 182,970 85,519 Total natural gas, NGLs and oil sales 4,911,092 3,215,027 1,607,713 Sales of purchased natural gas 408,584 342,431 160,122 Sales of purchased NGLs 2,783 6,925 3,776 Other marketing revenue and other income 12,850 16,056 9,375 Total $ 5,335,309 $ 3,580,439 $ 1,780,986

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax	Our income tax expense was $ 230.5 million for the year ended December 31, 2022 compared to a benefit of $ 9.7 million in 2021 and a benefit of $ 25.6 million in 2020. The effective income tax rate is influenced by a variety of factors including geographic sources and relative magnitude of these sources of income. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State, net of federal benefit 1.0 4.0 5.2 State rate and law change — ( 3.4 ) 4.3 Equity compensation — 2.3 ( 1.0 ) Valuation allowances ( 5.5 ) ( 26.8 ) ( 25.9 ) Permanent differences and other ( 0.2 ) 0.5 ( 0.1 ) Consolidated effective tax rate 16.3 % ( 2.4 )% 3.5 %
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): 2022 2021 2020 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ 245,839 $ 245,839 $ — $ 6,297 $ 6,297 $ ( 366 ) $ ( 24,489 ) $ ( 24,855 ) U.S. state and local 14,688 ( 30,067 ) ( 15,379 ) 7,984 ( 24,024 ) ( 16,040 ) ( 157 ) ( 540 ) ( 697 ) Total $ 14,688 $ 215,772 $ 230,460 $ 7,984 $ ( 17,727 ) $ ( 9,743 ) $ ( 523 ) $ ( 25,029 ) $ ( 25,552 )
Significant Components of Deferred Tax Assets and Liabilities	Significant components of deferred tax assets and liabilities are as follows: December 31, 2022 2021 (in thousands) Deferred tax assets: Net operating loss carryforward $ 581,349 $ 788,375 Divestiture contract obligation 105,227 112,199 Deferred compensation 25,733 22,121 Equity compensation 4,813 4,833 Asset retirement obligations 24,113 21,734 Interest expense carryforward 16,118 53,876 Lease right-of-use liabilities 19,395 9,954 Cumulative mark-to-market loss 30,307 32,221 Other 16,922 12,181 Valuation allowances: Federal ( 21,320 ) ( 67,984 ) State, net of federal benefit ( 171,423 ) ( 203,085 ) Total deferred tax assets 631,234 786,425 Deferred tax liabilities: Depreciation and depletion ( 935,710 ) ( 879,163 ) Lease right-of-use assets ( 18,440 ) ( 9,247 ) Other ( 10,655 ) ( 15,657 ) Total deferred tax liabilities ( 964,805 ) ( 904,067 ) Net deferred tax liability $ ( 333,571 ) $ ( 117,642 )

Net Income (Loss) Per Common _2

Net Income (Loss) Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 2020 Net income (loss), as reported $ 1,183,370 $ 411,778 $ ( 711,777 ) Participating basic earnings (a) ( 28,578 ) ( 10,795 ) — Basic net income (loss) attributed to common stockholders 1,154,792 400,983 ( 711,777 ) Reallocation of participating earnings (a) 614 272 — Diluted net income (loss) attributed to common stockholders $ 1,155,406 $ 401,255 $ ( 711,777 ) Net income (loss) per common share: Basic $ 4.79 $ 1.65 $ ( 2.95 ) Diluted $ 4.69 $ 1.61 $ ( 2.95 ) (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 and 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, 2022 2021 2020 Denominator: Weighted average common shares outstanding – basic 240,858 242,862 241,373 Effect of dilutive securities 5,521 6,452 — Weighted average common shares outstanding – diluted 246,379 249,314 241,373

Indebtedness (Tables)

Indebtedness (Tables)	12 Months Ended
	Dec. 31, 2022
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. 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. For December 31, 2021, deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. No interest was capitalized in the three-year period ended December 31, 2022. The components of our debt outstanding, including the effects of debt issuance costs, is as follows (in thousands): December 31, 2022 2021 Bank debt $ 19,000 $ — Senior notes 4.75 % senior notes due 2030 500,000 — 4.875 % senior notes due 2025 750,000 750,000 5.00 % senior notes due 2022 — 169,589 5.00 % senior notes due 2023 — 532,335 5.875 % senior notes due 2022 — 48,528 8.25 % senior notes due 2029 600,000 600,000 9.25 % senior notes due 2026 — 850,000 Total senior notes 1,850,000 2,950,452 Total debt 1,869,000 2,950,452 Unamortized premium — 188 Unamortized debt issuance costs ( 27,040 ) ( 24,853 ) Total debt (net of debt issuance costs) 1,841,960 2,925,787 Less current maturities of long-term debt — ( 218,017 ) Total long-term debt $ 1,841,960 $ 2,707,770
Schedule for Long-Term Debt Outstanding	The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2022 (in thousands): Year Ended 2023 $ — 2024 — 2025 750,000 2026 — 2027 19,000 Thereafter 1,100,000 $ 1,869,000

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021 (in thousands): 2022 2021 Beginning of period $ 95,836 $ 79,822 Liabilities incurred 2,589 73 Liabilities settled ( 10,650 ) ( 8,197 ) Accretion expense 6,569 5,511 Change in estimate 15,507 18,627 End of period 109,851 95,836 Less current portion ( 4,570 ) ( 5,310 ) Long-term asset retirement obligations $ 105,281 $ 90,526

Derivative Activities (Tables)

Derivative Activities (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, excluding our basis 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 2023 Swaps 376,384 Mmbtu/day $ 3.44 2023 Collars 278,082 Mmbtu/day $ 3.60 $ 4.78 2023 Three-way Collars 187,233 Mmbtu/day $ 2.67 $ 3.74 $ 4.83 2024 Swaps 110,000 Mmbtu/day $ 4.63 2024 Collars 469,235 Mmbtu/day $ 3.55 $ 5.51 Crude Oil 2023 Swaps 5,123 bbls/day $ 71.39 January-September 2024 Collars 832 bbls/day $ 80.00 $ 90.12
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, 2022 and 2021 is summarized below (in thousands). As of December 31, 2022, we are conducting derivative activities with fourteen counterparties, of which all but six 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, 2022 Gross Amounts of Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 19,438 $ ( 6,236 ) $ 13,202 –collars 54,222 ( 45,452 ) 8,770 –three-way collars 12,424 ( 12,424 ) — –basis swaps 25,493 ( 20,437 ) 5,056 Crude oil –collars 1,807 — 1,807 Divestiture contingent consideration 13,080 — 13,080 $ 126,464 $ ( 84,549 ) $ 41,915 December 31, 2022 Gross Amounts of Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ ( 115,374 ) $ 6,236 $ ( 109,138 ) –collars ( 72,866 ) 45,452 ( 27,414 ) –three-way collars ( 24,341 ) 12,424 ( 11,917 ) –basis swaps ( 24,972 ) 20,437 ( 4,535 ) Crude oil –swaps ( 13,908 ) — ( 13,908 ) $ ( 251,461 ) $ 84,549 $ ( 166,912 ) December 31, 2021 Gross Amounts of Gross Amounts Offset 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 Amounts of 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 )
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, 2022 2021 2020 Commodity swaps $ ( 713,122 ) $ ( 466,203 ) $ 158,248 Swaptions 11,149 ( 1,346 ) ( 4,955 ) Collars ( 302,364 ) ( 117,612 ) 3,304 Three-way collars ( 235,335 ) ( 137,443 ) ( 16,346 ) Basis swaps 41,622 33,691 48,278 Calls ( 1,363 ) ( 836 ) ( 558 ) Freight swaps ( 33 ) ( 647 ) ( 1,230 ) Divestiture contingent consideration 10,940 40,180 970 Total $ ( 1,188,506 ) $ ( 650,216 ) $ 187,711

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred $ 57,717 $ — $ — $ 57,717 Derivatives –swaps — ( 109,844 ) — ( 109,844 ) –collars — ( 16,837 ) — ( 16,837 ) –three-way collars — ( 11,917 ) — ( 11,917 ) –basis swaps — 521 — 521 Divestiture contingent consideration — 13,080 — 13,080 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
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, 2021 $ ( 12,421 ) Settlements 1,272 Transfers out of Level 3 11,149 Balance at December 31, 2022 $ —
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, 2022 and 2021 (in thousands): December 31, 2022 December 31, 2021 Carrying Fair Carrying Fair Assets: Commodity swaps, collars and basis swaps $ 28,835 $ 28,835 $ 17,699 $ 17,699 Divestiture contingent consideration 13,080 13,080 26,640 26,640 Marketable securities (a) 57,717 57,717 69,606 69,606 (Liabilities): Commodity swaps, collars and basis swaps ( 166,912 ) ( 166,912 ) ( 170,983 ) ( 170,983 ) Bank credit facility (b) ( 19,000 ) ( 19,000 ) — — 5.00 % senior notes due 2022 (b) — — ( 169,589 ) ( 171,488 ) 5.875 % senior notes due 2022 (b) — — ( 48,528 ) ( 48,955 ) 5.00 % senior notes due 2023 (b) — — ( 532,335 ) ( 543,471 ) 4.875 % senior notes due 2025 (b) ( 750,000 ) ( 714,870 ) ( 750,000 ) ( 776,153 ) 9.25 % senior notes due 2026 (b) — — ( 850,000 ) ( 916,929 ) 8.25 % senior notes due 2029 (b) ( 600,000 ) ( 618,312 ) ( 600,000 ) ( 669,648 ) 4.75 % senior notes due 2030 (b) ( 500,000 ) ( 442,350 ) — — Deferred compensation plan (c) ( 189,241 ) ( 189,241 ) ( 165,395 ) ( 165,395 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are 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 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, 2022
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, 2022 (in thousands): 2022 2021 2020 Direct operating expense $ 1,459 $ 1,310 $ 1,078 Brokered natural gas and marketing expense 2,439 1,794 1,416 Exploration expense 1,578 1,507 1,279 General and administrative expense 42,023 39,673 32,905 Exit costs — — 2,165 Total stock-based compensation $ 47,499 $ 44,284 $ 38,843
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, 2022: Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2021 2,674,777 $ 7.39 796,629 $ 6.49 Granted 1,405,660 18.66 650,314 20.94 Vested ( 2,283,837 ) 8.88 ( 1,067,310 ) 12.38 Forfeited ( 59,912 ) 10.29 — — Outstanding at December 31, 2022 1,736,688 $ 14.44 379,633 $ 14.71
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, 2022, 2021 and 2020: Year Ended December 31, 2022 2021 2020 Risk-free interest rate 1.4 % 0.2 % 1.4 % Expected annual volatility 68 % 75 % 65 % Grant date fair value per unit $ 27.90 $ 12.58 $ 3.85
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, 2022: Number of Weighted Outstanding at December 31, 2021 1,095,355 $ 7.80 Units granted (a) 153,089 20.38 Vested (b) ( 243,482 ) 9.64 Forfeited — — Outstanding at December 31, 2022 1,004,962 $ 9.27 (a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares may be between zero and 200 % depending on achievement of specifically identified performance targets. (b) For awards granted in 2019, the aggregate payout was approximately 116 % of target with a positive performance adjustment of 158,793 shares.
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, 2021 1,147,994 $ 7.60 Granted (a) 111,828 27.90 Vested and issued (b) ( 314,152 ) 11.34 Forfeited — — Outstanding at December 31, 2022 945,670 $ 8.76 (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 awards issued related to the 2019 performance period where the return on our common stock was 127 % and therefore, the performances multiple and actual payout was 183 %.

Capital Stock (Tables)

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2022
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 2021: Year Ended December 31, 2022 2021 Beginning balance 249,792,908 246,348,092 Restricted stock grants 671,303 1,293,892 Restricted stock units vested 1,827,625 1,493,341 Performance stock units vested 590,940 640,468 Performance stock dividends 1,843 13,966 Treasury shares ( 13,998,889 ) 3,149 Ending balance 238,885,730 249,792,908
Schedule of Change in Treasury Shares	The following is a schedule of the change in treasury shares since the beginning of 2021: Year Ended December 31, 2022 2021 Beginning balance 10,002,646 10,005,795 Rabbi trust shares distributed and/or sold ( 1,111 ) ( 3,149 ) Shares repurchased 14,000,000 — Ending balance 24,001,535 10,002,646

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Year Ended December 31, 2022 2021 2020 (in thousands) Net cash provided from operating activities included: Income taxes paid to taxing authorities $ ( 20,335 ) $ ( 7,061 ) $ ( 343 ) Interest paid ( 193,732 ) ( 196,750 ) ( 168,471 ) Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 18,096 $ 18,634 $ 2,610 Increase (decrease) in accrued capital expenditures 1,966 ( 4,505 ) ( 23,625 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, the majority of which is included as part of natural gas and oil properties on our consolidated balance sheets, are as follows (in thousands): Year Ended December 31, 2022 2021 Operating lease cost $ 37,873 $ 26,343 Variable lease expense (1) 22,082 27,243 Short-term lease expense (2) 1,807 1,950 Sublease income ( 137 ) ( 2,380 ) Total lease expense $ 61,625 $ 53,156 Short-term lease costs (3) $ 17,285 $ 18,984 (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 sheets. (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, 2022 2021 Cash paid for amounts included in the measurement of lease $ 37,457 $ 28,118 ROU assets added in exchange for lease obligations $ 78,574 $ 1,059
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, 2022 2021 Operating lease ROU assets $ 84,070 $ 40,832 Accrued liabilities – current $ ( 67,493 ) $ ( 19,066 ) Operating lease liabilities – long-term $ ( 20,903 ) $ ( 24,861 )
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, 2022 2021 Weighted average remaining lease term 2.0 years 3.8 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 2023 $ 70,873 2024 8,119 2025 6,576 2026 6,167 2027 2,626 Total lease payments 94,361 Less effects of discounting ( 5,965 ) Total lease liability $ 88,396
Schedule of Future Minimum Transportation Fees Due	As of December 31, 2022, future minimum transportation and gathering fees under our commitments are as follows (in thousands): Transportation (a) 2023 $ 801,850 2024 782,445 2025 694,670 2026 635,929 2027 582,580 Thereafter 2,971,614 $ 6,469,088 (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, 2022, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands): Divestiture 2023 $ 86,546 2024 73,916 2025 64,276 2026 45,773 2027 37,743 Thereafter 82,366 $ 390,620
Future Delivery Commitments	As of December 31, 2022, our delivery commitments through 2037 were as follows: Year Ending December 31, Natural Gas Ethane and Propane 2023 365,000 50,000 2024 261,899 50,000 2025 182,493 50,000 2026 158,301 50,000 2027 100,000 46,233 2028 100,000 45,000 2029 100,000 33,444 2030 — 30,000 2031 — 16,575 2032-2037 — 10,000 (each year)

Exit Costs (Tables)

Exit Costs (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021 and 2020 (in thousands): Year Ended December 31, 2022 2021 2020 Severance costs $ — $ 567 $ 5,909 Transportation contract capacity releases (including 579 754 10,900 Divestiture contract obligation (including accretion 69,758 20,340 499,935 One-time minimum volume commitment contract — — 28,500 Stock-based compensation and other — — 2,165 $ 70,337 $ 21,661 $ 547,409
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, 2022 and 2021 (in thousands): Exit Costs Termination Costs 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 Accrued contract obligations-changes in estimate 26,183 — Accretion of discount 44,154 — Payments ( 98,399 ) ( 10 ) Balance at December 31, 2022 $ 395,680 $ —

Suspended Exploratory Well Co_2

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022
Extractive Industries [Abstract]
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization	Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2022 2021 2020 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 9,855,287 $ 9,338,236 $ 8,891,348 Unproved properties 800,592 837,334 859,766 Total 10,655,879 10,175,570 9,751,114 Accumulated depreciation, depletion and ( 4,765,475 ) ( 4,420,914 ) ( 4,064,305 ) Net capitalized costs $ 5,890,404 $ 5,754,656 $ 5,686,809 (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, 2022 2021 2020 (in thousands) Acquisitions: Acreage purchases $ 28,735 $ 21,942 $ 26,166 Development 460,668 381,753 369,093 Exploration: Drilling — 6,329 7,709 Expense 25,194 22,048 31,376 Stock-based compensation expense 1,578 1,507 1,279 Gas gathering facilities: Development 1,466 3,402 3,694 Subtotal 517,641 436,981 439,317 Asset retirement obligations 18,096 18,634 2,610 Total costs incurred $ 535,737 $ 455,615 $ 441,927 (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, 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 Revisions ( 393,165 ) ( 20,251 ) ( 12,885 ) ( 591,983 ) Extensions, discoveries and additions 1,278,499 59,296 5,661 1,668,244 Production ( 539,443 ) ( 36,392 ) ( 2,716 ) ( 774,089 ) Balance, December 31, 2022 11,797,972 1,003,958 42,656 18,077,656 Proved developed reserves: 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 December 31, 2022 7,230,313 594,931 22,213 10,933,180 Proved undeveloped reserves: 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 December 31, 2022 4,567,659 409,027 20,443 7,144,476 (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 2022 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2021 7,357,597 Undeveloped reserves transferred to developed ( 1,091,828 ) Revisions (a) ( 759,281 ) Extension and discoveries 1,637,988 Ending proved undeveloped reserves at December 31, 2022 7,144,476 (a) Includes 1.4 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. Includes 716.2 Bcfe positive revision for previously proved undeveloped properties due to their addition back into 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, 2022 2021 (in thousands) Future cash inflows $ 113,954,835 $ 69,403,611 Future costs: Production ( 31,991,109 ) ( 27,015,321 ) Development (a) ( 3,313,724 ) ( 2,469,028 ) Future net cash flows before income taxes 78,650,002 39,919,262 Future income tax expense ( 16,651,625 ) ( 8,146,832 ) Total future net cash flows before 10% discount 61,998,377 31,772,430 10% annual discount ( 37,453,094 ) ( 19,287,204 ) Standardized measure of discounted future net cash $ 24,545,283 $ 12,485,226 (a) 2022 includes $ 361.9 million of undiscounted future asset retirement costs as of December 31, 2022, 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, 2022 2021 2020 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ 14,326,997 $ 11,600,850 $ ( 4,868,371 ) Revisions in quantities 109,129 577,737 ( 345,073 ) Changes in future development and abandonment ( 524,847 ) ( 53,818 ) 107,899 Net change in income taxes ( 2,625,699 ) ( 2,248,161 ) 797,816 Accretion of discount 1,486,783 298,077 756,083 Additions to proved reserves from extensions, 2,842,173 1,423,510 280,441 Natural gas, NGLs and oil sales, net of production ( 3,550,632 ) ( 1,934,254 ) ( 402,450 ) Actual development costs incurred during the 471,877 399,681 384,530 Sales of reserves in place — — ( 394,125 ) Timing and other ( 475,724 ) ( 424,718 ) ( 99,001 ) Net change for the year 12,060,057 9,638,904 ( 3,782,251 ) Beginning of year 12,485,226 2,846,322 6,628,573 End of year $ 24,545,283 $ 12,485,226 $ 2,846,322

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2022 USD ($) Counterparties Customer Counterparty	Dec. 31, 2021 USD ($) Customer	Dec. 31, 2020 USD ($) Customer
Summary Of Significant Accounting Policies [Line Items]
Net brokered margin gain (loss)		$ (5,400,000)	$ 1,100,000	$ (14,200,000)
Allowance for doubtful accounts on accounts receivable		314,000	568,000
Bad debt (income) expense		(250,000)	200,000	400,000
Net book value of unproved properties	[1]	800,592,000	837,334,000	859,766,000
Abandonment and impairment of unproved properties		28,608,000	7,206,000	19,334,000
Depreciation expense		$ 2,200,000	2,400,000	$ 2,600,000
Lessee, operating lease, contract term		12 months
Marketable securities held in deferred compensation plans		$ 57,700,000	69,600,000
Deferred financing cost related to bank credit facility			5,200,000
Other investments including surface acreage		$ 10,400,000	$ 11,500,000
Number of customers accounted more than 10% of total oil and gas revenues | Customer		0	1	0
Number of counterparties | Counterparty		6
Number of financial institutions included in counter parties | Counterparty		14
Number of counterparties amount payable | Counterparties		4
Number of counterparties amount receivable | Counterparties		2
Impairment of proved properties and other assets		$ 0	$ 0	$ 78,955,000
Existing derivative contracts		We did not materially modify any existing derivative contracts in 2022, 2021 or 2020.
Reported Value Measurement
Summary Of Significant Accounting Policies [Line Items]
Marketable securities held in deferred compensation plans	[2]	$ 57,717,000	$ 69,606,000
Counterparties in a Liability position
Summary Of Significant Accounting Policies [Line Items]
Net derivative liability		4,000,000
Counterparties in a Receivable position
Summary Of Significant Accounting Policies [Line Items]
Derivative amount receivable		$ 3,300,000
Other property and equipment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets		3 years
Other property and equipment | Maximum
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets		10 years
[1] Includes capitalized asset retirement costs and the associated accumulated amortization. Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are updated based on end of period closing prices which is a Level 1 input.

Dispositions - Additional Infor

Dispositions - Additional Information (Detail) - USD ($)		3 Months Ended	12 Months Ended
	Aug. 14, 2020	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (Loss) on sale of assets			$ 409,000	$ 701,000	$ 110,791,000
Proceeds from disposal of assets			518,000	303,000	246,127,000
Gross Amounts of Recognized Assets			126,464,000	96,957,000
Contingent Consideration
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gross Amounts of Recognized Assets			$ 13,080,000	26,640,000
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

Revenues from Contracts with _3

Revenues from Contracts with Customers - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) Stream	Dec. 31, 2021 USD ($)
Disaggregation of Revenue [Line Items]
Number of revenue streams | Stream	3
Maximum [Member]
Disaggregation of Revenue [Line Items]
Settlement statements, number of days	90 days
Minimum [Member]
Disaggregation of Revenue [Line Items]
Settlement statements, number of days	30 days
Revenue Contract with Customer
Disaggregation of Revenue [Line Items]
Accounts receivable | $	$ 463.3	$ 460.2

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Total Revenue	$ 5,335,309	$ 3,580,439	$ 1,780,986
Natural Gas, NGLs and Oil Sales
Disaggregation of Revenue [Line Items]
Total Revenue	4,911,092	3,215,027	1,607,713
Natural Gas, NGLs and Oil Sales | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	3,364,111	1,896,231	943,740
Natural Gas, NGLs and Oil Sales | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	1,308,574	1,135,826	578,454
Natural Gas, NGLs and Oil Sales | Oil and condensate sales
Disaggregation of Revenue [Line Items]
Total Revenue	238,407	182,970	85,519
Brokered Natural Gas, Marketing and Other
Disaggregation of Revenue [Line Items]
Total Revenue	424,217	365,412	173,273
Brokered Natural Gas, Marketing and Other | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	408,584	342,431	160,122
Brokered Natural Gas, Marketing and Other | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	2,783	6,925	3,776
Brokered Natural Gas, Marketing and Other | Other Marketing Revenue And Other Income [Member]
Disaggregation of Revenue [Line Items]
Total Revenue	$ 12,850	$ 16,056	$ 9,375

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)			3 Months Ended	12 Months Ended
	Aug. 16, 2022	Jul. 12, 2022	Sep. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Line Items]
Income tax benefit				$ (230,460,000)	$ 9,743,000	$ 25,552,000
Deferred tax liabilities				333,571,000	117,642,000
Accrued interest or penalties related to tax amounts				0
Change in Valuation Allowances				$ (78,300,000)	(108,000,000)	$ 188,200,000
Inflation Reduction Act Of 2022
Income Taxes [Line Items]
Corporate income tax percentage	15%
Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire				Dec. 31, 2036
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				$ 171,423,000	203,085,000
Federal
Income Taxes [Line Items]
Valuation allowances				21,320,000	$ 67,984,000
Federal and State
Income Taxes [Line Items]
Net operating loss carryforwards				2,000,000,000
Net operating loss carryforward subject to expiration				374,500,000
Net operating loss carryforward not subject to expiration				1,700,000,000
Pennsylvania
Income Taxes [Line Items]
Income tax benefit			$ 20,700,000
Net operating loss carryforwards				$ 825,900,000
Reduction in tax rate				0.50%
Final tax rate				4.99%
Pennsylvania | Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire				Dec. 31, 2031
Pennsylvania | Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire				Dec. 31, 2042
Corporate income tax rate, current		9.99%
Corporate income tax rate, expected		8.99%
Louisiana
Income Taxes [Line Items]
Net operating loss carryforward not subject to expiration				$ 1,600,000,000

Income Taxes - Reconciliation B

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory tax rate	21%	21%	21%
State, net of federal benefit	1%	4%	5.20%
State rate and law change	0%	(3.40%)	4.30%
Equity compensation	0%	2.30%	(1.00%)
Valuation allowances	(5.50%)	(26.80%)	(25.90%)
Permanent differences and other	(0.20%)	0.50%	(0.10%)
Consolidated effective tax rate	16.30%	(2.40%)	3.50%

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
U.S. federal, Current	$ 0	$ 0	$ (366)
U.S. state and local, Current	14,688	7,984	(157)
Total, Current	14,688	7,984	(523)
U.S. federal, Deferred	245,839	6,297	(24,489)
U.S. state and local, Deferred	(30,067)	(24,024)	(540)
Total, Deferred	215,772	(17,727)	(25,029)
U.S. federal, Total	245,839	6,297	(24,855)
U.S. state and local, Total	(15,379)	(16,040)	(697)
Total (benefit) expense for income taxes	$ 230,460	$ (9,743)	$ (25,552)

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
Net operating loss carryforward	$ 581,349	$ 788,375
Divestiture contract obligation	105,227	112,199
Deferred compensation	25,733	22,121
Equity compensation	4,813	4,833
Asset retirement obligations	24,113	21,734
Interest expense carryforward	16,118	53,876
Lease right-of-use liabilities	19,395	9,954
Cumulative mark-to-market loss	30,307	32,221
Other	16,922	12,181
Total deferred tax assets	631,234	786,425
Deferred tax liabilities:
Depreciation and depletion	(935,710)	(879,163)
Lease right-of-use assets	(18,440)	(9,247)
Other	(10,655)	(15,657)
Total deferred tax liabilities	(964,805)	(904,067)
Net deferred tax liability	(333,571)	(117,642)
Federal
Valuation allowances:
Valuation allowances	(21,320)	(67,984)
State, net of federal benefit
Valuation allowances:
Valuation allowances	$ (171,423)	$ (203,085)

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share Reconciliation [Abstract]
Net income (loss)		$ 1,183,370	$ 411,778	$ (711,777)
Participating basic earnings	[1]	(28,578)	(10,795)	0
Basic net income (loss) attributed to common stockholders		1,154,792	400,983	(711,777)
Reallocation of participating earnings	[1]	614	272	0
Diluted net income (loss) attributed to common stockholders		$ 1,155,406	$ 401,255	$ (711,777)
Earnings Per Share [Abstract]
Basic		$ 4.79	$ 1.65	$ (2.95)
Diluted		$ 4.69	$ 1.61	$ (2.95)
[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 and Diluted Weighted Average Common Shares Outstanding (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Denominator:
Basic	240,858	242,862	241,373
Effect of dilutive securities	5,521	6,452	0
Weighted average common shares outstanding - diluted	246,379	249,314	241,373

Net Income (Loss) Per Common _5

Net Income (Loss) Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	6,100,000	6,500,000	5,500,000
Equity Grants [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	5,000	18,000

Indebtedness - Additional Infor

Indebtedness - Additional Information (Detail)	36 Months Ended
	Dec. 31, 2022 USD ($)
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0

Indebtedness - Debt Outstanding

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Jan. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Senior notes	$ 1,850,000		$ 2,950,452
Total debt	1,869,000		2,950,452
Unamortized premium	0		188
Unamortized debt issuance costs	(27,040)		(24,853)
Total debt (net of debt issuance costs)	1,841,960		2,925,787
Less current maturities of long-term debt	0		(218,017)
Total long-term debt	1,841,960		2,707,770
Notes Payable to Banks
Debt Instrument [Line Items]
Bank debt	19,000		0
4.75% Senior Notes Due 2030
Debt Instrument [Line Items]
Unamortized debt issuance costs		$ (7,500)
4.75% Senior Notes Due 2030 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	500,000		0
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 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	0		169,589
5.00% Senior Notes Due 2023 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	0		532,335
5.875% Senior Notes Due 2022 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	0		48,528
8.25% Senior Notes Due 2029 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	600,000		600,000
9.25% Senior Notes Due 2026 | Notes Payable to Banks
Debt Instrument [Line Items]
Senior notes	$ 0		$ 850,000

Indebtedness - Debt Outstandi_2

Indebtedness - Debt Outstanding (Parenthetical) (Detail)	Dec. 31, 2022	Sep. 30, 2022	Jan. 31, 2022	Dec. 31, 2021
4.75% Senior Notes Due 2030
Debt Instrument [Line Items]
Interest rate on notes	4.75%		4.75%	4.75%
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate on notes	4.875%			4.875%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5%			5%
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5%	5%		5%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.875%			5.875%
8.25% Senior Notes Due 2029
Debt Instrument [Line Items]
Interest rate on notes	8.25%			8.25%
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Interest rate on notes	9.25%			9.25%

Indebtedness - Bank Debt - Addi

Indebtedness - Bank Debt - Additional Information (Detail) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2022	Dec. 31, 2022 USD ($) Commercialbank	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Sep. 30, 2022 USD ($)
Debt Instrument [Line Items]
Loss on early extinguishment of debt		$ 69,493	$ 98	$ (14,068)
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		1,500,000			$ 1,500,000
Line of Credit Facility Outstanding Amount		$ 19,000
Number of commercial banks included in current bank group | Commercialbank		17
Maturity date of loan		Apr. 14, 2027
Weighted average interest rate on the bank credit facility		4.10%	2.10%	2.60%
Annual rate of commitment fee paid on the undrawn balance		0.375%
Undrawn letters of credit		$ 307,400
Borrowing capacity available under the commitment amount		$ 1,200,000
Bank Credit Facility [Member] | Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin		0.75%
Bank Credit Facility [Member] | SOFR Rate
Debt Instrument [Line Items]
Interest rate margin		1.75%
Bank Credit Facility [Member] | Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance		0.375%
Bank Credit Facility [Member] | Minimum | Alternate Base Rate
Debt Instrument [Line Items]
Interest rate on notes		0.75%
Bank Credit Facility [Member] | Minimum | SOFR Rate
Debt Instrument [Line Items]
Interest rate on notes		1.75%
Bank Credit Facility [Member] | Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance		0.50%
Bank Credit Facility [Member] | Maximum | Alternate Base Rate
Debt Instrument [Line Items]
Interest rate on notes		1.75%
Bank Credit Facility [Member] | Maximum | SOFR Rate
Debt Instrument [Line Items]
Interest rate on notes		2.75%
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Interest rate on notes	9.25%	9.25%	9.25%
Redemption price of notes as percentage of principal amount	106.938%
Loss on early extinguishment of debt		$ 69,200
Debt instrument maturity year	2026

Indebtedness - New Senior Notes

Indebtedness - New Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Unamortized debt issuance costs		$ 27,040	$ 24,853
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Interest rate on notes	9.25%	9.25%	9.25%
Debt instrument maturity year	2026
Redemption price of notes as percentage of principal amount	106.938%
Repayments of senior notes	$ 850,000
4.75% Senior Notes Due 2030
Debt Instrument [Line Items]
Aggregate principal amount	$ 500,000
Interest rate on notes	4.75%	4.75%	4.75%
Debt instrument maturity year	2030
Net proceeds after underwriting discounts	$ 492,500
Unamortized debt issuance costs	$ 7,500
Redemption price of notes as percentage of principal amount		100%

Indebtedness - Early Extinguish

Indebtedness - Early Extinguishment of Debt - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Loss (gain) on early extinguishment of debt		$ (69,493)	$ (98)	$ 14,068
9.25% Senior Notes Due 2026
Debt Instrument [Line Items]
Debt instrument maturity year	2026
Redemption price of notes as percentage of principal amount	106.938%
Loss (gain) on early extinguishment of debt		$ (69,200)
Repayments of senior notes	$ 850,000
Percentage of redemption	9.25%	9.25%	9.25%

Indebtedness - Senior Note Rede

Indebtedness - Senior Note Redemptions - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended	12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Loss (gain) on early extinguishment of debt				$ (69,493)	$ (98)	$ 14,068
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Repurchases of senior notes on the open market		$ 3,800
Interest rate on notes	5%	5%		5%	5%
Debt instrument maturity year	2023	2023
Loss (gain) on early extinguishment of debt			$ (261,000)
Subordinated Debt [Member]
Debt Instrument [Line Items]
Redemption price of notes as percentage of principal amount				101%

Indebtedness - Guarantees and D

Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2022
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. We are required to maintain a ratio of EBITDAX (as defined in the credit agreement) of 3.75x and a minimum current ratio (as defined in the credit agreement) of 1.0x. We were in compliance with applicable covenants under the bank credit facility at December 31, 2022.
Minimum
Debt Instrument [Line Items]
Current ratio	100%
Maximum
Debt Instrument [Line Items]
Ratio of debt to EBITDAX	375%

Indebtedness - Schedule for Lon

Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
2023	$ 0
2024	0
2025	750,000
2026	0
2027	19,000
Thereafter	1,100,000
Total debt	$ 1,869,000	$ 2,950,452

Asset Retirement Obligations -

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation [Abstract]
Beginning of period	$ 95,836	$ 79,822
Liabilities incurred	2,589	73
Liabilities settled	(10,650)	(8,197)
Accretion expense	6,569	5,511
Change in estimate	15,507	18,627
End of period	109,851	95,836
Less current portion	(4,570)	(5,310)
Long-term asset retirement obligations	$ 105,281	$ 90,526

Derivative Activities - Additio

Derivative Activities - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) MMBTU	Dec. 31, 2021 USD ($)
Derivative [Line Items]
Contingent consideration receivable	$ 24,500	$ 29,500
Contingent Consideration
Derivative [Line Items]
Contingent consideration receivable	24,500
Contingent Consideration | Fair Value, Recurring
Derivative [Line Items]
Derivative assets liabilities at fair value net	13,080	$ 26,640
Contingent Consideration | North Louisiana | Maximum
Derivative [Line Items]
Potential contractual payout of contingent consideration	21,000
Derivatives Excluding Contingent Consideration and Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	138,600
Commodity | Natural Gas Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 521,000
Volume Hedged | MMBTU	288,555,000

Derivative Activities - Derivat

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail)	Dec. 31, 2022 MmbtuPerDay BarrelsPerDay $ / MMBTU $ / bbl
Naturals Gas [Member] | 2023 Commodity Contract | Swaps
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	376,384
Weighted Average Hedge Price, Swap	3.44
Naturals Gas [Member] | 2023 Commodity Contract | Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	278,082
Weighted average price of hedge, Floor	3.60
Weighted average price of hedge, Ceiling	4.78
Naturals Gas [Member] | 2023 Commodity Contract | Three Way Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	187,233
Weighted Average Hedge Price, Sold Put	2.67
Weighted average price of hedge, Floor	3.74
Weighted average price of hedge, Ceiling	4.83
Naturals Gas [Member] | 2024 Commodity Contract | Swaps
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	110,000
Weighted Average Hedge Price, Swap	4.63
Naturals Gas [Member] | 2024 Commodity Contract | Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	469,235
Weighted average price of hedge, Floor	3.55
Weighted average price of hedge, Ceiling	5.51
Crude Oil | 2023 Commodity Contract | Swaps
Derivative [Line Items]
Volume Hedged | BarrelsPerDay	5,123
Weighted Average Hedge Price, Swap | $ / bbl	71.39
Crude Oil | January-September 2024 | Collars
Derivative [Line Items]
Volume Hedged | BarrelsPerDay	832
Weighted average price of hedge, Floor	80
Weighted average price of hedge, Ceiling	90.12

Derivative Activities - Combine

Derivative Activities - Combined Fair Value of Derivatives, by Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 126,464	$ 96,957
Gross Amounts Offset in the Balance Sheet	(84,549)	(52,618)
Net Amounts of Assets Presented in the Balance Sheet	41,915	44,339
Gross Amounts of Recognized (Liabilities)	(251,461)	(223,601)
Gross Amounts Offset in the Balance Sheet	84,549	52,618
Net Amounts of (Liabilities) Presented in the Balance Sheet	(166,912)	(170,983)
Contingent Consideration
Derivative [Line Items]
Gross Amounts of Recognized Assets	13,080	26,640
Gross Amounts Offset in the Balance Sheet	0	0
Net Amounts of Assets Presented in the Balance Sheet	13,080	26,640
Commodity | Natural Gas | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	19,438	22,491
Gross Amounts Offset in the Balance Sheet	(6,236)	(18,111)
Net Amounts of Assets Presented in the Balance Sheet	13,202	4,380
Gross Amounts of Recognized (Liabilities)	(115,374)	(121,759)
Gross Amounts Offset in the Balance Sheet	6,236	18,111
Net Amounts of (Liabilities) Presented in the Balance Sheet	(109,138)	(103,648)
Commodity | Natural Gas | Swaptions
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(11,149)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		(11,149)
Commodity | Natural Gas | Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	54,222	12,378
Gross Amounts Offset in the Balance Sheet	(45,452)	(8,600)
Net Amounts of Assets Presented in the Balance Sheet	8,770	3,778
Gross Amounts of Recognized (Liabilities)	(72,866)	(16,579)
Gross Amounts Offset in the Balance Sheet	45,452	8,600
Net Amounts of (Liabilities) Presented in the Balance Sheet	(27,414)	(7,979)
Commodity | Natural Gas | Three Way Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	12,424	12,234
Gross Amounts Offset in the Balance Sheet	(12,424)	(8,449)
Net Amounts of Assets Presented in the Balance Sheet	0	3,785
Gross Amounts of Recognized (Liabilities)	(24,341)	(37,166)
Gross Amounts Offset in the Balance Sheet	12,424	8,449
Net Amounts of (Liabilities) Presented in the Balance Sheet	(11,917)	(28,717)
Commodity | Natural Gas | Basis Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	25,493	18,092
Gross Amounts Offset in the Balance Sheet	(20,437)	(10,487)
Net Amounts of Assets Presented in the Balance Sheet	5,056	7,605
Gross Amounts of Recognized (Liabilities)	(24,972)	(2,064)
Gross Amounts Offset in the Balance Sheet	20,437	10,487
Net Amounts of (Liabilities) Presented in the Balance Sheet	(4,535)	8,423
Commodity | Natural Gas | Calls
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(61)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		(61)
Commodity | Crude Oil | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		368
Gross Amounts Offset in the Balance Sheet		(2,153)
Net Amounts of Assets Presented in the Balance Sheet		(1,785)
Gross Amounts of Recognized (Liabilities)	(13,908)	(27,252)
Gross Amounts Offset in the Balance Sheet	0	2,153
Net Amounts of (Liabilities) Presented in the Balance Sheet	(13,908)	(25,099)
Commodity | Crude Oil | Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	1,807
Gross Amounts Offset in the Balance Sheet	0
Net Amounts of Assets Presented in the Balance Sheet	$ 1,807
Commodity | NGLs (C3-Propane) | Spread Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		4,153
Gross Amounts Offset in the Balance Sheet		(4,153)
Net Amounts of Assets Presented in the Balance Sheet		0
Gross Amounts of Recognized (Liabilities)		(4,030)
Gross Amounts Offset in the Balance Sheet		4,153
Net Amounts of (Liabilities) Presented in the Balance Sheet		123
Commodity | NGLs (C5-Natural Gasoline) | Spread Swaps
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(2,048)
Gross Amounts Offset in the Balance Sheet		363
Net Amounts of (Liabilities) Presented in the Balance Sheet		(1,685)
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)
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		0
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)
Freight | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		114
Gross Amounts Offset in the Balance Sheet		(81)
Net Amounts of Assets Presented in the Balance Sheet		33
Gross Amounts of Recognized (Liabilities)		0
Gross Amounts Offset in the Balance Sheet		81
Net Amounts of (Liabilities) Presented in the Balance Sheet		$ 81

Derivative Activities - Effects

Derivative Activities - Effects of Derivatives on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ (1,188,506)	$ (650,216)	$ 187,711
Contingent Consideration
Derivative [Line Items]
Derivative Fair Value Income (Loss)	10,940	40,180	970
Swaptions
Derivative [Line Items]
Derivative Fair Value Income (Loss)	11,149	(1,346)	(4,955)
Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(302,364)	(117,612)	3,304
Three Way Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(235,335)	(137,443)	(16,346)
Basis Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)	41,622	33,691	48,278
Calls
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(1,363)	(836)	(558)
Commodity | Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(713,122)	(466,203)	158,248
Freight | Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ (33)	$ (647)	$ (1,230)

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - Fair Value, Recurring - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	$ 57,717	$ 69,606
Commodity | Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(109,844)	(127,934)
Commodity | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(16,837)	(5,473)
Commodity | Three Way Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(11,917)	(24,932)
Commodity | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		(61)
Commodity | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	521	16,151
Commodity | Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		(11,149)
Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		114
Contingent Consideration
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	13,080	26,640
Fair Value, Inputs, Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	57,717	69,606
Fair Value, Inputs, Level 1 | Commodity | 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 | 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 | 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 | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Fair Value, Inputs, Level 1 | Commodity | 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 | Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Fair Value, Inputs, Level 1 | Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Fair Value, Inputs, Level 1 | Contingent Consideration
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 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 | Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(109,844)	(127,934)
Fair Value, Inputs, Level 2 | Commodity | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(16,837)	(4,201)
Fair Value, Inputs, Level 2 | Commodity | Three Way Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(11,917)	(24,932)
Fair Value, Inputs, Level 2 | Commodity | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		(61)
Fair Value, Inputs, Level 2 | Commodity | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	521	16,151
Fair Value, Inputs, Level 2 | Commodity | Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Fair Value, Inputs, Level 2 | Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		114
Fair Value, Inputs, Level 2 | Contingent Consideration
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	13,080	26,640
Fair Value, Inputs, Level 3
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 | 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 | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	(1,272)
Fair Value, Inputs, Level 3 | Commodity | 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 | Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Fair Value, Inputs, Level 3 | Commodity | 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 | Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		(11,149)
Fair Value, Inputs, Level 3 | Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Fair Value, Inputs, Level 3 | Contingent Consideration
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 ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends	$ 1,100,000	$ 951,000	$ 713,000
Mark-to-market gain (loss)	$ (14,200,000)	$ 3,000,000	6,300,000
North Louisiana
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Annual discount rate	12%
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

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, 2022 USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at December 31, 2021	$ (12,421)
Settlements	1,272
Transfers out of Level 3	11,149
Balance at December 31, 2022	$ 0

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($) $ in Thousands		Dec. 31, 2022	Dec. 31, 2021
Assets:
Marketable securities		$ 57,700	$ 69,600
Reported Value Measurement
Assets:
Commodity swaps, collar, options and basis swaps		28,835	17,699
Marketable securities	[1]	$ 57,717	$ 69,606
Derivative Asset, Statement of Financial Position [Extensible Enumeration]		Derivative Asset, Noncurrent	Derivative Asset, Noncurrent
(Liabilities):
Commodity swaps, collar, options and basis swaps		$ (166,912)	$ (170,983)
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Derivative Liability, Noncurrent	Derivative Liability, Noncurrent
Bank credit facility	[2]	$ (19,000)	$ 0
Senior notes	[2]	(500,000)	0
Deferred compensation plan	[3]	(189,241)	(165,395)
Reported Value Measurement | Contingent Consideration
Assets:
Commodity swaps, collar, options and basis swaps		13,080	26,640
Estimate of Fair Value Measurement
Assets:
Commodity swaps, collar, options and basis swaps		28,835	17,699
Marketable securities	[1]	57,717	69,606
(Liabilities):
Commodity swaps, collar, options and basis swaps		(166,912)	(170,983)
Bank credit facility	[2]	(19,000)	0
Senior notes	[2]	(442,350)	0
Deferred compensation plan	[3]	(189,241)	(165,395)
Estimate of Fair Value Measurement | Contingent Consideration
Assets:
Commodity swaps, collar, options and basis swaps		13,080	26,640
5.00% Senior Notes Due 2022 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	0	(169,589)
5.00% Senior Notes Due 2022 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	0	(171,488)
5.875% Senior Notes Due 2022 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	0	(48,528)
5.875% Senior Notes Due 2022 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	0	(48,955)
5.00% Senior Notes Due 2023 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	0	(532,335)
5.00% Senior Notes Due 2023 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	0	(543,471)
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]	(714,870)	(776,153)
9.25% Senior Notes Due 2026 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	0	(850,000)
9.25% Senior Notes Due 2026 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	0	(916,929)
8.25% Senior Notes Due 2029 | Reported Value Measurement
(Liabilities):
Senior notes	[2]	(600,000)	(600,000)
8.25% Senior Notes Due 2029 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[2]	$ (618,312)	$ (669,648)
[1] Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges and are updated based on end of period closing prices which is a Level 1 input. The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes is based on end of period market quotes which are Level 2 inputs. 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, 2022	Sep. 30, 2022	Jan. 31, 2022	Dec. 31, 2021
5.00% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	5%			5%
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%	5%		5%
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%	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%
4.75% senior notes due 2030
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Percentage of redemption	4.75%			4.75%

Stock-Based Compensation Plan_2

Stock-Based Compensation Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2022 USD ($) Plans	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Active equity-based stock plans | Plans	2
Income tax expense (benefit)	$ 230,460,000	$ (9,743,000)	$ (25,552,000)
Equity Compensation
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax expense (benefit)	$ (7,200,000)	$ (340,000)	$ 4,300,000

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 47,499	$ 44,284	$ 38,843
Direct Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,459	1,310	1,078
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	2,439	1,794	1,416
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,578	1,507	1,279
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	42,023	39,673	32,905
Exit Costs
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 0	$ 0	$ 2,165

Stock-Based Compensation Plan_4

Stock-Based Compensation Plans - Additional Information 1 (Detail)	12 Months Ended
	Dec. 31, 2022 Award
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]
Number of awards available for grant	2
Performance based PSUs and TSRs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of awards available for grant	1
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	1
Performance Based TSR - PSUs | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0%
Performance Based TSR - PSUs | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200%

Stock-Based Compensation Plan_5

Stock-Based Compensation Plans - Additional Information 2 (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Proceeds from the sales of common stock held by the deferred compensation plan	$ 22,229,000	$ 5,879,000	$ 696,000
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	1,405,660	2,300,000	4,500,000
Vesting period	3 years
Stock-based compensation expense	$ 21,000,000	$ 19,600,000	$ 17,800,000
Unrecognized compensation related to Awards	$ 23,300,000
Weighted average period	1 year 8 months 12 days
Granted, weighted average grant date fair value	$ 18.66
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	650,314	1,300,000	3,500,000
Stock-based compensation expense	$ 13,600,000	$ 11,400,000	$ 10,300,000
Unrecognized compensation related to Awards	$ 4,600,000
Weighted average period	1 year 1 month 6 days
Granted, weighted average grant date fair value	$ 20.94	$ 9.56	$ 3.18
Proceeds from the sales of common stock held by the deferred compensation plan	$ 22,200,000	$ 5,900,000	$ 696,000
Restricted Stock Liability Awards | Non-Employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	47,000	102,000	217,000
Vesting period	1 year	1 year	1 year
Restricted Stock Liability Awards | Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	603,000	1,200,000	3,300,000
Vesting period	3 years	3 years	3 years
Restricted Stock Liability Awards | Non Employee Directors and Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	650,000

Stock-Based Compensation Plan_6

Stock-Based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	2,674,777
Granted	1,405,660	2,300,000	4,500,000
Vested	(2,283,837)
Forfeited	(59,912)
Outstanding, Ending Balance	1,736,688	2,674,777
Outstanding, Beginning Balance, weighted average grant date fair value	$ 7.39
Granted, weighted average grant date fair value	18.66
Vested and issued, weighted average grant date fair value	8.88
Forfeited, weighted average grant date fair value	10.29
Outstanding, Ending Balance, weighted average grant date fair value	$ 14.44	$ 7.39
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	796,629
Granted	650,314	1,300,000	3,500,000
Vested	(1,067,310)
Forfeited	0
Outstanding, Ending Balance	379,633	796,629
Outstanding, Beginning Balance, weighted average grant date fair value	$ 6.49
Granted, weighted average grant date fair value	20.94	$ 9.56	$ 3.18
Vested and issued, weighted average grant date fair value	12.38
Forfeited, weighted average grant date fair value	0
Outstanding, Ending Balance, weighted average grant date fair value	$ 14.71	$ 6.49

Stock-Based Compensation Plan_7

Stock-Based Compensation Plans - Additional Information 3 (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares granted	200%
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares granted	0%
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 6.2	$ 6.6	$ 2.7
Unrecognized compensation related to Awards	$ 1.8
Weighted average period	1 year 1 month 6 days
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Stock-based compensation expense	$ 3.2	$ 2.6	$ 2.4
Unrecognized compensation related to Awards	$ 1.5
Performance Based TSR - PSUs | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares granted	200%
Performance Based TSR - PSUs | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares granted	0%
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average period	1 year 3 months 18 days

Stock-Based Compensation Plan_8

Stock-Based Compensation Plans - Internal Performance Activities (Detail) - Performance-based Internal Performance Awards	12 Months Ended
	Dec. 31, 2022 $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance | shares	1,095,355
Granted | shares	153,089	[1]
Vested | shares	(243,482)	[2]
Forfeited | shares	0
Outstanding, Ending Balance | shares	1,004,962
Outstanding, Beginning Balance, weighted average grant date fair value | $ / shares	$ 7.80
Granted, weighted average grant date fair value | $ / shares	20.38	[1]
Vested and issued, weighted average grant date fair value | $ / shares	9.64	[2]
Forfeited, weighted average grant date fair value | $ / shares	0
Outstanding, Ending Balance, weighted average grant date fair value | $ / shares	$ 9.27
[1] Amounts granted reflect the number of performance units granted; however, the actual payout of shares may be between zero and 200 % depending on achievement of specifically identified performance targets. For awards granted in 2019, the aggregate payout was approximately 116 % of target with a positive performance adjustment of 158,793 shares.

Stock-Based Compensation Plan_9

Stock-Based Compensation Plans - Internal Performance Activities (Parenthetical) (Detail) - Performance-based Internal Performance Awards	12 Months Ended
	Dec. 31, 2022 shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares vested and issued related to performance period number of common stock	243,482	[1]
March 2019 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares	116%
Shares vested and issued related to performance period number of common stock	158,793
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200%
[1] For awards granted in 2019, the aggregate payout was approximately 116 % of target with a positive performance adjustment of 158,793 shares.

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	1.40%	0.20%	1.40%
Expected annual volatility	68%	75%	65%
Grant date fair value per unit	$ 27.90	$ 12.58	$ 3.85

Stock-Based Compensation Pla_11

Stock-Based Compensation Plans - TSR - PSUs Activities (Detail) - Performance Based TSR - PSUs	12 Months Ended
	Dec. 31, 2022 $ / shares shares
Summary of Performance Share Unit Awards outstanding, Number of Units
Outstanding, Beginning Balance | shares	1,147,994
Granted | shares	111,828	[1]
Vested and issued | shares	(314,152)	[2]
Forfeited | shares	0
Outstanding, Ending Balance | shares	945,670
Summary of Performance Share Unit Awards outstanding, Weighted Average Grant Date Fair Value
Outstanding, Beginning Balance, weighted average grant date fair value | $ / shares	$ 7.60
Granted, weighted average grant date fair value | $ / shares	27.90	[1]
Vested and issued, weighted average grant date fair value | $ / shares	11.34	[2]
Forfeited, weighted average grant date fair value | $ / shares	0
Outstanding, Ending Balance, weighted average grant date fair value | $ / shares	$ 8.76
[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. Includes TSR awards issued related to the 2019 performance period where the return on our common stock was 127 % and therefore, the performances multiple and actual payout was 183 %.

Stock-Based Compensation Pla_12

Stock-Based Compensation Plans - TSR - PSUs Activities (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2022
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares granted	0%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares granted	200%
Performance Based TSR - PSUs | March 2019 Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Return on common stock percentile	127%
Actual payout of shares granted	183%
Performance Based TSR - PSUs | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares on performance units granted	0%
Actual payout of shares granted	0%
Performance Based TSR - PSUs | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares on performance units granted	200%
Actual payout of shares granted	200%

Stock-Based Compensation Pla_13

Stock-Based Compensation Plans - Additional Information 4 (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Retirement Benefits [Abstract]
Maximum percentage of employees contribution	75%
Maximum percentage of employers contribution in cash	6%
Employer contribution	$ 4.8	$ 4.6	$ 5.3
Deferred compensation plan vesting period	3 years
Deferred compensation plan	$ 61.9	$ 68.4	$ 12.5
Shares held in rabbi trust total	5,600,000	6,200,000
Vested shares held in rabbi trust	5,300,000	5,400,000

Capital Stock - Additional Info

Capital Stock - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	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
Stock repurchases during period value	$ 399.7
Stock repurchase program, additional authorized amount	430		$ 1,000
Stock repurchase program, authorized amount	$ 500		$ 100
Shares repurchased	14,000,000	0

Capital Stock - Schedule of Cha

Capital Stock - Schedule of Changes in Number of Common Shares Outstanding (Detail) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Class Of Stock [Line Items]
Beginning balance	249,792,908	246,348,092
Treasury shares	(13,998,889)	3,149
Ending balance	238,885,730	249,792,908
Restricted Stock
Class Of Stock [Line Items]
Restricted stock grants	671,303	1,293,892
Restricted stock units vested	1,827,625	1,493,341
Performance Share
Class Of Stock [Line Items]
Performance stock units vested	590,940	640,468
Performance stock dividends	1,843	13,966

Capital Stock - Schedule of C_2

Capital Stock - Schedule of Change in Treasury Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Stockholders' Equity Note [Abstract]
Beginning balance	10,002,646	10,005,795
Rabbi trust shares distributed and/or sold	(1,111)	(3,149)
Shares repurchased	14,000,000	0
Ending balance	24,001,535	10,002,646

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net cash provided from operating activities included:
Income taxes paid to taxing authorities		$ (20,335)	$ (7,061)	$ (343)
Interest paid		(193,732)	(196,750)	(168,471)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	[1]	18,096	18,634	2,610
Increase (decrease) in accrued capital expenditures		$ 1,966	$ (4,505)	$ (23,625)
[1] Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) McfD BblD
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	1,800
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
2027-2033
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day | BblD	15,000
Divestiture Contract Obligation [Member]
Commitments And Contingencies Disclosure [Line Items]
Accrued obligations | $	$ 390.6
Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	13 years
Transportation and gathering commitments contingent upon pipeline construction or modification, expiration period	5 years
Transportation commitments contingent upon pipeline construction or modification declined amount	810,000

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Components of Lease Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Commitments And Contingencies Disclosure [Line Items]
Operating lease cost		$ 37,873	$ 26,343
Variable lease expense	[1]	22,082	27,243
Sublease income		(137)	(2,380)
Total lease expense		61,625	53,156
Natural Gas and Oil Properties
Commitments And Contingencies Disclosure [Line Items]
Short-term lease expense / costs	[2]	17,285	18,984
Leases with Contract Term of One Year or Less
Commitments And Contingencies Disclosure [Line Items]
Short-term lease expense / costs	[3]	$ 1,807	$ 1,950
[1] Variable lease payments that are not dependent on an index or rate and are not included in the lease liability or ROU assets. 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. 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 sheets.

Commitments and Contingencies_3

Commitments and Contingencies - Supplemental Cash Flow Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 37,457	$ 28,118
ROU assets added in exchange for lease obligations	$ 78,574	$ 1,059

Commitments and Contingencies_4

Commitments and Contingencies - Supplemental Balance Sheet Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Loss Contingencies [Line Items]
Operating lease ROU assets	$ 84,070	$ 40,832
Accrued liabilities – current	$ (67,493)	$ (19,066)
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued Liabilities, Current	Accrued Liabilities, Current
Operating lease liabilities – long-term	$ (20,903)	$ (24,861)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Operating lease liabilities – long-term	Operating lease liabilities – long-term

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, 2022	Dec. 31, 2021
Lessee Disclosure [Abstract]
Weighted average remaining lease term	2 years	3 years 9 months 18 days
Weighted average discount rate	6%	6%

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, 2022 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2023	$ 70,873
2024	8,119
2025	6,576
2026	6,167
2027	2,626
Total lease payments	94,361
Less effects of discounting	(5,965)
Total lease liability	$ 88,396

Commitments and Contingencies_7

Commitments and Contingencies - Schedule of Future Minimum Transportation Fees Due (Detail) $ in Thousands	Dec. 31, 2022 USD ($)	[1]
Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]
2023	$ 801,850
2024	782,445
2025	694,670
2026	635,929
2027	582,580
Thereafter	2,971,614
Transportation and Gathering Contracts	$ 6,469,088
[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, 2022 USD ($)
Disclosure Commitments And Contingencies Schedule Of Estimated Settlement Of Divestiture Contract Obligation [Abstract]
2023	$ 86,546
2024	73,916
2025	64,276
2026	45,773
2027	37,743
Thereafter	82,366
Divestiture Contract Obligation	$ 390,620

Commitments and Contingencies_9

Commitments and Contingencies - Future Delivery Commitments (Detail)	12 Months Ended
	Dec. 31, 2022 bbl / d MmbtuPerDay
2023 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	365,000
2023 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	50,000
2024 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	261,899
2024 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	50,000
2025 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	182,493
2025 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	50,000
2026 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	158,301
2026 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	50,000
2027 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	100,000
2027 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	46,233
2028 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	100,000
2028 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	45,000
2029 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	100,000
2029 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	33,444
2030 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	0
2030 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	30,000
2031 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	0
2031 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	16,575
2032-2037 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	0
2032-2037 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	10,000

Exit Costs - Additional Informa

Exit Costs - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Restructuring Cost And Reserve [Line Items]
One-time minimum volume commitment contract payment			$ 28,500			$ 0	$ 0	$ 28,500
Severance costs						0	567	5,909
Restructuring Charges						70,337	21,661	547,409
Workforce Reduction
Restructuring Cost And Reserve [Line Items]
Severance costs			3,700
North Louisiana
Restructuring Cost And Reserve [Line Items]
Accretion expense						43,600	47,900	20,200
Exit and termination costs	$ 24,800	$ 28,200
Exit cost			479,800			390,600
Severance costs			$ 2,500
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost						579	$ 754	$ 10,900
Pennsylvania | Capacity Releases on Transportation Pipelines
Restructuring Cost And Reserve [Line Items]
Exit cost				$ 10,400		$ 5,100
Northwest Pennsylvania
Restructuring Cost And Reserve [Line Items]
Severance costs					$ 1,400

Exit Costs - Summary of Exit an

Exit Costs - Summary of Exit and Termination Costs (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Restructuring Cost And Reserve [Line Items]
Severance costs		$ 0	$ 567	$ 5,909
One-time minimum volume commitment contract payment	$ 28,500	0	0	28,500
Stock-based compensation and other		0	0	2,165
Total termination costs		70,337	21,661	547,409
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost		579	754	10,900
North Louisiana Contract Release
Restructuring Cost And Reserve [Line Items]
Exit cost		$ 69,758	$ 20,340	$ 499,935

Exit Costs - Exit and Terminati

Exit Costs - Exit and Termination Costs Included in Accrued Liabilities in Consolidated Balance Sheet - (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Exit costs included in accrued liabilities in consolidated balance sheet
Accrued severance costs	$ 0	$ 567	$ 5,909
Exit Costs
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	423,742	493,543
Accrued severance costs		0
Accrued contract obligations	26,183	(27,575)
Accretion of discount	44,154	48,669
Payments	(98,399)	(90,895)
Ending balance	395,680	423,742	493,543
Termination Costs
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	10	1,454
Accrued severance costs		567
Accrued contract obligations	0	0
Accretion of discount	0	0
Payments	(10)	(2,011)
Ending balance	$ 0	$ 10	$ 1,454

Suspended Exploratory Well Co_3

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Natural gas and oil properties:
Properties subject to depletion	[1]	$ 9,855,287	$ 9,338,236	$ 8,891,348
Unproved properties	[1]	800,592	837,334	859,766
Total	[1]	10,655,879	10,175,570	9,751,114
Accumulated depreciation, depletion and amortization	[1]	(4,765,475)	(4,420,914)	(4,064,305)
Natural gas and oil properties, successful efforts method, net	[1]	$ 5,890,404	$ 5,754,656	$ 5,686,809
[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, 2022	Dec. 31, 2021	Dec. 31, 2020
Acquisitions
Acreage purchases	[1]	$ 28,735	$ 21,942	$ 26,166
Development	[1]	460,668	381,753	369,093
Gas gathering facilities:
Development	[1]	1,466	3,402	3,694
Subtotal	[1]	517,641	436,981	439,317
Asset retirement obligations	[1]	18,096	18,634	2,610
Total costs incurred	[1]	535,737	455,615	441,927
Exploration Expense
Exploration:
Exploration drilling costs incurred	[1]	0	6,329	7,709
Exploration costs incurred	[1]	25,194	22,048	31,376
Stock-based compensation expense	[1]	$ 1,578	$ 1,507	$ 1,279
[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) $ in Millions		12 Months Ended
		Dec. 31, 2022 USD ($) MMcfe Bcfe $ / Mcf $ / MMBTU $ / bbl MMBbls MMcf	Dec. 31, 2021 MMcfe $ / MMBTU $ / Mcf $ / bbl MMBbls MMcf	Dec. 31, 2020 MMcfe $ / bbl $ / MMBTU $ / Mcf MMcf MMBbls	Dec. 31, 2019 MMcfe MMBbls MMcf
Reserve Quantities [Line Items]
Percentage of proved resources reviewed by consultants		96%
Proved reserve and pretax present value of reserve discounted		10%
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		77%	72%	80%
Proved undeveloped reserves dropped		1,400	1,300	961,100
Revision of negative pricing				67,900
Revisions of positive pricing			22,600
Cost spent on undeveloped reserves transferred to developed reserves | $		$ 430
Estimated future development costs over next five years | $		$ 3,000
Proved undeveloped reserves reported for more than five years | Bcfe		87,800
Crude Oil and NGL
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / bbl		94.13	66.34	39.77
Crude Oil and Condensate
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		87.14	59.35	30.13
Proved developed and undeveloped reserves | MMBbls		42,656	52,596	57,626	74,532
NGLs
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		38.35	28.41	16.14
Proved developed and undeveloped reserves | MMBbls		1,003,958	1,001,305	951,466	938,236
Natural Gas
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / Mcf		6.08	3.30	1.68
Proved developed and undeveloped reserves | MMcf		11,797,972	11,452,081	11,148,560	12,114,977
Natural Gas, Per Thousand Cubic Feet
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / MMBTU		6.36	3.60	1.98
Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved reserves from drilling activities and evaluations of proved areas	[1]	1,668,244	1,602,769	1,264,282
Proved developed and undeveloped reserve balances	[1]	18,077,656	17,775,484	17,203,114	18,191,583
Revisions of previous estimates	[1]	(591,983)	(252,876)	(608,211)
Revision of positive performance		72,800	1,000	420,900
Additional undeveloped properties reclassified		716,200
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, 2022 MMcfe MMBbls MMcf	Dec. 31, 2021 MMcfe MMBbls MMcf	Dec. 31, 2020 MMcfe MMBbls MMcf
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe		7,144,476	7,357,597
Natural Gas
Reserve Quantities [Line Items]
Beginning Balance | MMcf		11,452,081	11,148,560	12,114,977
Revisions | MMcf		(393,165)	(311,410)	(789,992)
Extensions, discoveries and additions | MMcf		1,278,499	1,155,952	1,007,415
Property sales | MMcf				(609,311)
Production | MMcf		(539,443)	(541,021)	(574,529)
Ending Balance | MMcf		11,797,972	11,452,081	11,148,560
Proved developed reserves:
Proved developed reserves | MMcf		7,230,313	6,809,849	6,350,057
Proved undeveloped reserves:
Proved undeveloped reserves | MMcf		4,567,659	4,642,232	4,798,503
NGLs
Reserve Quantities [Line Items]
Beginning Balance		1,001,305	951,466	938,236
Revisions		(20,251)	16,845	42,741
Extensions, discoveries and additions		59,296	69,367	38,298
Property sales				(30,317)
Production		(36,392)	(36,373)	(37,492)
Ending Balance		1,003,958	1,001,305	951,466
Proved developed reserves:
Proved developed reserves		594,931	577,506	550,771
Proved undeveloped reserves:
Proved undeveloped reserves		409,027	423,798	400,695
Crude Oil and Condensate
Reserve Quantities [Line Items]
Beginning Balance		52,596	57,626	74,532
Revisions		(12,885)	(7,089)	(12,444)
Extensions, discoveries and additions		5,661	5,103	4,512
Property sales				(6,145)
Production		(2,716)	(3,044)	(2,829)
Ending Balance		42,656	52,596	57,626
Proved developed reserves:
Proved developed reserves		22,213	23,833	22,976
Proved undeveloped reserves:
Proved undeveloped reserves		20,443	28,762	34,650
Natural Gas Equivalents
Proved developed reserves:
Proved developed reserves | MMcfe	[1]	10,933,180	10,417,887	9,792,540
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe	[1]	7,144,476	7,357,597	7,410,574
Beginning Balance | MMcfe	[1]	17,775,484	17,203,114	18,191,583
Revisions | MMcfe	[1]	(591,983)	(252,876)	(608,211)
Extensions, discoveries and additions | MMcfe	[1]	1,668,244	1,602,769	1,264,282
Property sales | MMcfe	[1]			(828,084)
Production | MMcfe	[1]	(774,089)	(777,523)	(816,456)
Ending Balance | MMcfe	[1]	18,077,656	17,775,484	17,203,114
[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, 2022 MMcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves at December 31, 2021	7,357,597
Undeveloped reserves transferred to developed	(1,091,828)
Revisions	(759,281)	[1]
Extension and discoveries	1,637,988
Ending proved undeveloped reserves at December 31, 2022	7,144,476
[1] Includes 1.4 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. Includes 716.2 Bcfe positive revision for previously proved undeveloped properties due to their addition back into 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, 2022 MMcfe
Reserve Quantities [Line Items]
Proved undeveloped reserves removed and deferred	1,400
Natural Gas Equivalents
Reserve Quantities [Line Items]
Additional undeveloped properties reclassified	716,200

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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Future cash inflows		$ 113,954,835	$ 69,403,611
Future costs:
Production		(31,991,109)	(27,015,321)
Development	[1]	(3,313,724)	(2,469,028)
Future net cash flows before income taxes		78,650,002	39,919,262
Future income tax expense		(16,651,625)	(8,146,832)
Total future net cash flows before 10% discount		61,998,377	31,772,430
10% annual discount		(37,453,094)	(19,287,204)
Standardized measure of discounted future net cash flows		$ 24,545,283	$ 12,485,226	$ 2,846,322	$ 6,628,573
[1] 2022 includes $ 361.9 million of undiscounted future asset retirement costs as of December 31, 2022, using current estimates of future abandonment costs.

Supplemental Information on _10

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail) $ in Millions	Dec. 31, 2022 USD ($)
Extractive Industries [Abstract]
Undiscounted future asset retirement costs estimation	$ 361.9

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Revisions of previous estimates
Changes in prices and production costs	$ 14,326,997	$ 11,600,850	$ (4,868,371)
Revisions in quantities	109,129	577,737	(345,073)
Changes in future development and abandonment costs	(524,847)	(53,818)	107,899
Net change in income taxes	(2,625,699)	(2,248,161)	797,816
Accretion of discount	1,486,783	298,077	756,083
Additions to proved reserves from extensions, discoveries and improved recovery	2,842,173	1,423,510	280,441
Natural gas, NGLs and oil sales, net of production costs	3,550,632	1,934,254	402,450
Actual development costs incurred during the period	471,877	399,681	384,530
Sales of reserves in place	0	0	(394,125)
Timing and other	(475,724)	(424,718)	(99,001)
Net change for the year	12,060,057	9,638,904	(3,782,251)
Beginning of year	12,485,226	2,846,322	6,628,573
End of year	$ 24,545,283	$ 12,485,226	$ 2,846,322