Range Resources (RRC) 10-K 25 Feb 25 2024 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2024	Feb. 21, 2025	Jun. 30, 2024
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2024
Document Fiscal Year Focus	2024
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		241,330,871
Entity Public Float			$ 8,033,163,000
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 2025 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
Auditor Opinion [Text Block]	We have audited Range Resources Corporation’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Range Resources Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, and the related consolidated statements of income, comprehensive income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes and our report dated February 25, 2025 expressed an unqualified opinion thereon. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Document Financial Statement Error Correction [Flag]	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents		$ 304,490	$ 211,974
Accounts receivable, less allowance for doubtful accounts of $255 and 308		302,212	274,669
Contingent consideration receivable		0	8,000
Derivative assets		84,479	341,330
Prepaid assets		12,722	18,159
Other current assets		17,558	15,992
Total current assets		721,461	870,124
Derivative assets		2,619	101,641
Natural gas and oil properties, successful efforts method	[1]	11,878,427	11,225,482
Accumulated depletion and depreciation	[1]	(5,456,727)	(5,107,801)
Natural gas and oil properties, successful efforts method, net	[1]	6,421,700	6,117,681
Other property and equipment		72,771	72,639
Accumulated depreciation and amortization		(70,306)	(70,943)
Other property and equipment, net		2,465	1,696
Operating lease right-of-use assets		119,838	23,821
Other assets		79,592	88,922
Total assets		7,347,675	7,203,885
Current liabilities:
Accounts payable		133,132	110,134
Asset retirement obligations		1,189	2,395
Accrued liabilities		289,148	290,579
Deferred compensation liabilities		21,649	44,149
Accrued interest		36,920	37,261
Derivative liabilities		9,634	222
Operating lease liabilities		87,138	11,584
Divestiture contract obligation		86,991	86,762
Current maturities of long-term debt	[2]	608,269	0
Total current liabilities		1,274,070	583,086
Senior notes		1,089,614	1,774,229
Deferred tax liabilities		541,378	561,288
Derivative liabilities		10,488	107
Deferred compensation liabilities		65,233	72,976
Operating lease liabilities		35,737	16,064
Asset retirement obligations and other liabilities		137,181	119,896
Divestiture contract obligation		257,317	310,688
Total liabilities		3,411,018	3,438,334
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, 267,435,419 issued at December 31, 2024 and 265,756,369 shares at December 31, 2023		2,674	2,658
Common stock held in treasury, at cost, 26,766,065 shares at December 31, 2024 and 24,716,065 shares at December 31, 2023		(513,941)	(448,681)
Additional paid-in capital		5,927,893	5,879,705
Accumulated other comprehensive income		611	647
Retained deficit		(1,480,580)	(1,668,778)
Total stockholders' equity		3,936,657	3,765,551
Total liabilities and stockholders' equity		$ 7,347,675	$ 7,203,885
[1] (a) Includes capitalized asset retirement costs and the associated accumulated amortization. (a) As of December 31, 2024, current maturities include $ 608.7 million principal amount of our 4.875 % senior notes due 2025 ( $ 608.3 million net of deferred financing costs).

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 255,000	$ 308,000
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	267,435,419	265,756,369
Common stock held in treasury, shares	26,766,065	24,716,065

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenues and other income:
Total Revenues from Contracts with Customers	$ 2,346,898	$ 2,541,213	$ 5,330,868
Derivative fair value income (loss)	56,726	821,154	(1,188,506)
Other income	13,460	12,505	4,850
Total revenues and other income	2,417,084	3,374,872	4,147,212
Costs and expenses:
Taxes other than income	21,625	23,726	35,367
Brokered natural gas and marketing	140,545	202,884	427,048
Exploration	26,843	26,530	26,772
Abandonment and impairment of unproved properties	8,417	46,359	28,608
General and administrative	172,139	164,740	168,085
Exit costs	37,214	99,940	70,337
Deferred compensation plan	9,593	26,593	61,880
Interest	118,758	124,004	165,145
(Gain) loss on early extinguishment of debt	(257)	(438)	69,493
Depletion, depreciation and amortization	358,356	350,165	353,420
Total costs and expenses	2,166,479	2,274,529	2,733,382
Income before income taxes	250,605	1,100,343	1,413,830
Income tax (benefit) expense:
Current	8,165	1,547	14,688
Deferred	(23,900)	227,654	215,772
Income tax (benefit) expense	(15,735)	229,201	230,460
Net income	$ 266,340	$ 871,142	$ 1,183,370
Net income per common share:
Basic	$ 1.1	$ 3.61	$ 4.79
Diluted	$ 1.09	$ 3.57	$ 4.69
Weighted average common shares outstanding:
Basic	240,689	236,986	240,858
Diluted	242,745	239,837	246,379
Natural Gas, NGLs and Oil Sales
Revenues and other income:
Total Revenues from Contracts with Customers	$ 2,213,850	$ 2,334,661	$ 4,911,092
Brokered Natural Gas and Marketing
Revenues and other income:
Total Revenues from Contracts with Customers	133,048	206,552	419,776
Direct Operating
Costs and expenses:
Costs and expenses	95,321	96,085	84,286
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 1,177,925	$ 1,113,941	$ 1,242,941

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income	$ 266,340	$ 871,142	$ 1,183,370
Postretirement benefits:
Actuarial gain (loss)	28	(12)	482
Prior service cost	0	(296)	0
Amortization of prior service costs/actuarial gain	(74)	(41)	292
Income tax expense (benefit)	10	(63)	(157)
Total comprehensive income	$ 266,304	$ 871,322	$ 1,183,987

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating activities:
Net income	$ 266,340,000	$ 871,142,000	$ 1,183,370,000
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income tax (benefit) expense	(23,900,000)	227,654,000	215,772,000
Depletion, depreciation and amortization	358,356,000	350,165,000	353,420,000
Abandonment and impairment of unproved properties	8,417,000	46,359,000	28,608,000
Derivative fair value (income) loss	(56,726,000)	(821,154,000)	1,188,506,000
Cash settlements on derivative financial instruments	432,392,000	253,514,000	(1,190,154,000)
Divestiture contract obligation, including accretion	37,088,000	99,595,000	69,766,000
Allowance for bad debt	50,000	0	(250,000)
Amortization of deferred financing costs and other	4,526,000	4,735,000	7,959,000
Deferred and stock-based compensation	53,864,000	67,849,000	107,959,000
Gain on the sale of assets	(311,000)	(454,000)	(409,000)
(Gain) loss on early extinguishment of debt	(257,000)	(438,000)	69,493,000
Changes in working capital:
Accounts receivable	(19,586,000)	223,081,000	(3,286,000)
Other current assets	3,676,000	(1,285,000)	(18,438,000)
Accounts payable	(443,000)	(77,057,000)	17,077,000
Accrued liabilities and other	(118,972,000)	(265,814,000)	(164,649,000)
Net cash provided from operating activities	944,514,000	977,892,000	1,864,744,000
Investing activities:
Additions to natural gas properties	(570,426,000)	(571,819,000)	(456,505,000)
Additions to field service assets	(2,069,000)	(701,000)	(682,000)
Acreage purchases	(56,085,000)	(34,410,000)	(30,885,000)
Proceeds from disposal of assets	313,000	872,000	518,000
Purchases of marketable securities held by the deferred compensation plan	(41,798,000)	(45,168,000)	(43,691,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	46,232,000	49,521,000	41,413,000
Net cash used in investing activities	(623,833,000)	(601,705,000)	(489,832,000)
Financing activities:
Borrowings on credit facility	0	185,000,000	972,000,000
Repayments on credit facility	0	(204,000,000)	(953,000,000)
Issuance of senior notes	0	0	500,000,000
Repayment of senior notes	(79,272,000)	(60,934,000)	(1,659,422,000)
Dividends paid	(77,463,000)	(77,241,000)	(38,638,000)
Treasury stock purchases	(65,260,000)	(19,042,000)	(399,699,000)
Debt issuance costs	0	0	(16,176,000)
Taxes paid for shares withheld	(25,217,000)	(39,481,000)	(25,492,000)
Change in cash overdrafts	(1,084,000)	(23,923,000)	9,071,000
Proceeds from the sales of common stock held by the deferred compensation plan	20,131,000	75,201,000	22,229,000
Net cash used in financing activities	(228,165,000)	(164,420,000)	(1,589,127,000)
Increase (decrease) in cash and cash equivalents	92,516,000	211,767,000	(214,215,000)
Cash and cash equivalents at beginning of period	211,974,000	207,000	214,422,000
Cash and cash equivalents at end of period	$ 304,490,000	$ 211,974,000	$ 207,000

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Treasury shares	Common stock held in treasury	Additional Paid-in Capital	Accumulated other comprehensive (loss) income	Retained deficit
Beginning balance at Dec. 31, 2021	$ 2,085,663	$ 2,598		$ (30,007)	$ 5,720,277	$ (150)	$ (3,607,055)
Beginning balance Shares at Dec. 31, 2021		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
Issuance of common stock upon vesting of PSUs	0	$ 0		0	78	0	(78)
Issuance of common stock upon vesting of PSUs, shares		2,000
Stock-based compensation expense	31,133	$ 0		0	31,133	0	0
Dividends	(38,638)						(38,638)
Treasury stock issuance	0	0		47	(47)	0	0
Treasury stock issuance, shares			(1,000)
Treasury stock repurchased	(399,699)	0		(399,699)	0	0	0
Treasury stock repurchased, shares			14,000,000
Other comprehensive income (loss)	617	0		0	0	617	0
Net income	1,183,370	0		0	0	0	1,183,370
Ending balance at Dec. 31, 2022	2,876,006	$ 2,629		(429,659)	5,764,970	467	(2,462,401)
Ending balance Shares at Dec. 31, 2022		262,887,000	24,002,000
Issuance of common stock	78,079	$ 29		0	78,050	0	0
Issuance of common stock, shares		2,863,000
Issuance of common stock upon vesting of PSUs	0	$ 0		0	278	0	(278)
Issuance of common stock upon vesting of PSUs, shares		6,000
Stock-based compensation expense	36,427	$ 0		0	36,427	0	0
Dividends	(77,241)						(77,241)
Treasury stock issuance	0			20	(20)	0
Treasury stock issuance, shares			(1,000)
Treasury stock repurchased	(19,042)	0		(19,042)	0	0	0
Treasury stock repurchased, shares			715,000
Other comprehensive income (loss)	180	0		0	0	180	0
Net income	871,142	0		0	0	0	871,142
Ending balance at Dec. 31, 2023	$ 3,765,551	$ 2,658		(448,681)	5,879,705	647	(1,668,778)
Ending balance Shares at Dec. 31, 2023	265,756,369	265,756,000	24,716,000
Issuance of common stock	$ 5,771	$ 16		0	5,755	0	0
Issuance of common stock, shares		1,672,000
Issuance of common stock upon vesting of PSUs	0	$ 0		0	361	0	(361)
Issuance of common stock upon vesting of PSUs, shares		7,000
Stock-based compensation expense	42,072	$ 0		0	42,072	0	0
Dividends	(77,781)						(77,781)
Treasury stock repurchased	(65,260)	0		(65,260)	0	0	0
Treasury stock repurchased, shares			2,050,000
Other comprehensive income (loss)	(36)	0		0	0	(36)	0
Net income	266,340	0		0	0	0	266,340
Ending balance at Dec. 31, 2024	$ 3,936,657	$ 2,674		$ (513,941)	$ 5,927,893	$ 611	$ (1,480,580)
Ending balance Shares at Dec. 31, 2024	267,435,419	267,435,000	26,766,000

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Stockholders' Equity [Abstract]
Cash dividends paid per share	$ 0.32	$ 0.32	$ 0.16

Cybersecurity Risk Management,

Cybersecurity Risk Management, Strategy, and Governance	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	ITEM 1C. CYBERSECURITY We have a comprehensive approach to mitigate cybersecurity risk which primarily focuses on three key elements: • people – security awareness education and readiness-testing throughout the year for employees; • process – incorporating "cyber awareness" in our day-to-day processes which includes constant review of alerting and detection to mitigate constant cybersecurity threats, regular review of security posture and security roadmap to ensure alignment throughout the organization, physical and digital asset protection and security vulnerability remediation via preventable and detective measures; and • technology – investing in industry aligned security technology and threat intelligence capabilities. Cybersecurity governance is supported by our information technology department which includes certified security professionals and seasoned security analysts. This department conducts extensive ongoing reviews of our security initiatives to assess the current state of our program (using a cybersecurity framework) and potential evolution based on current business risks along with detection and communication of cybersecurity threats and actions to mitigate those threats. Our Director of IT Security is responsible for assessing, monitoring and managing risks from cybersecurity threats , overseeing our overall cybersecurity risk management program which includes prevention, mitigation, detection and remediation of cybersecurity incidents and supervises a team of cybersecurity personnel. Our Director of IT Security reports to our VP – Information Technology and is responsible for reporting material incidents to our Cybersecurity Risk Management Committee (“CRMC”) that includes officers charged with reporting responsibilities . Cybersecurity incidents that meet a pre-determined minimum threshold are communicated upward to executive officers to determine overall materiality and disclosure obligations. Our Director of IT Security keeps the CRMC apprised of our processes to prevent, detect, mitigate and remediate cybersecurity incidents at least annually. Our internal cybersecurity team led by our Director of IT Security has over 75 years of combined experience in information security and maintains several cybersecurity certificates. We conduct security assessments, manage user access, perform vulnerability scanning and patching, oversee monitoring and carry out annual penetration testing, in addition to other critical security functions. In conjunction with our internal team, we utilize an independent third-party operations center that is focused on, but not limited to, monitoring alerts, logs, behavior analytics, vulnerability notifications and remediation guidance. Critical infrastructure is continuously monitored to ensure accessibility and appropriate security posture. We also perform reviews and risk analysis for third-party software and platforms which sets a standardized security baseline. We monitor known third-party breaches, known software vulnerabilities that may affect third-party vendors and communicate as necessary with those vendors, allowing us to increase security of our technology assets and our data. In addition, we perform an annual cybersecurity risk assessment of critical third-party systems. Our board of directors oversees our cybersecurity risk and receives, at a minimum, a quarterly cybersecurity report and a bi-annual update from IT leadership, which includes additional discussions of any relevant issues related to the understanding of technology and cybersecurity risk that may be relevant at any given time. This report includes, among other things, information regarding our current security posture and ongoing cybersecurity events. Cybersecurity incidents meeting a pre-determined minimum threshold are communicated to our Board. To date, there have been no risks from cybersecurity threats because of any previous cybersecurity incidents, which have materially affected, or have been reasonably likely to materially affect us, including our business strategy, results of operations or financial condition. Notwithstanding the extensive approach we take to cybersecurity, we may not be successful in preventing or mitigating a cybersecurity incident that could have a material adverse effect on us. For more information on our cybersecurity related risks, see Item 1A. Risk Factors of this Annual Report on Form 10-K.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	process – incorporating "cyber awareness" in our day-to-day processes which includes constant review of alerting and detection to mitigate constant cybersecurity threats, regular review of security posture and security roadmap to ensure alignment throughout the organization, physical and digital asset protection and security vulnerability remediation via preventable and detective measures;
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	Our board of directors oversees our cybersecurity risk and receives, at a minimum, a quarterly cybersecurity report and a bi-annual update from IT leadership, which includes additional discussions of any relevant issues related to the understanding of technology and cybersecurity risk that may be relevant at any given time. This report includes, among other things, information regarding our current security posture and ongoing cybersecurity events. Cybersecurity incidents meeting a pre-determined minimum threshold are communicated to our Board.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our board of directors oversees our cybersecurity risk and receives, at a minimum, a quarterly cybersecurity report and a bi-annual update from IT leadership, which includes additional discussions of any relevant issues related to the understanding of technology and cybersecurity risk that may be relevant at any given time.
Cybersecurity Risk Role of Management [Text Block]	Cybersecurity governance is supported by our information technology department which includes certified security professionals and seasoned security analysts. This department conducts extensive ongoing reviews of our security initiatives to assess the current state of our program (using a cybersecurity framework) and potential evolution based on current business risks along with detection and communication of cybersecurity threats and actions to mitigate those threats. Our Director of IT Security is responsible for assessing, monitoring and managing risks from cybersecurity threats , overseeing our overall cybersecurity risk management program which includes prevention, mitigation, detection and remediation of cybersecurity incidents and supervises a team of cybersecurity personnel. Our Director of IT Security reports to our VP – Information Technology and is responsible for reporting material incidents to our Cybersecurity Risk Management Committee (“CRMC”) that includes officers charged with reporting responsibilities . Cybersecurity incidents that meet a pre-determined minimum threshold are communicated upward to executive officers to determine overall materiality and disclosure obligations. Our Director of IT Security keeps the CRMC apprised of our processes to prevent, detect, mitigate and remediate cybersecurity incidents at least annually. Our internal cybersecurity team led by our Director of IT Security has over 75 years of combined experience in information security and maintains several cybersecurity certificates.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Our Director of IT Security reports to our VP – Information Technology and is responsible for reporting material incidents to our Cybersecurity Risk Management Committee (“CRMC”) that includes officers charged with reporting responsibilities . Cybersecurity incidents that meet a pre-determined minimum threshold are communicated upward to executive officers to determine overall materiality and disclosure obligations. Our Director of IT Security keeps the CRMC apprised of our processes to prevent, detect, mitigate and remediate cybersecurity incidents at least annually.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our internal cybersecurity team led by our Director of IT Security has over 75 years of combined experience in information security and maintains several cybersecurity certificates.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Our Director of IT Security reports to our VP – Information Technology and is responsible for reporting material incidents to our Cybersecurity Risk Management Committee (“CRMC”) that includes officers charged with reporting responsibilities .
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net Income (Loss)	$ 266,340	$ 871,142	$ 1,183,370

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	3 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Summary of Organization and Nat

Summary of Organization and Nature of Business	12 Months Ended
	Dec. 31, 2024
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") and oil 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, 2024
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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 generally accepted accounting principles ("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. Estimated quantities of natural gas, NGLs and oil 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 and oil. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs and oil 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 oil that are ultimately recovered. See Note 16 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, NGLs and oil producing activities. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. Our Chief Executive Officer is the Chief Operating Decision Maker ("CODM"). We measure financial performance as a single enterprise and not on an area-by-area basis. Our exploration and production operations are limited to onshore United States and all of our sales transfer title and control in the onshore United States. Income before income taxes as presented in the consolidated statements of income is the primary measure of segment profit and loss used by the CODM in assessing business performance and making capital allocation decisions by comparing actual amounts to historical results and previously forecasted financial information. 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 for processing. 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-driven price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index-driven 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-driven 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-driven 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 and Marketing. 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 or NGLs purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas or NGLs 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 $ 7.5 million in 2024 compared to income of $ 3.7 million in 2023 and loss of $ 7.3 million in 2022. 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 judgment, 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 $ 255,000 at December 31, 2024 compared to $ 308,000 at December 31, 2023. We recorded bad debt expense of $ 50,000 in the year ended December 31, 2024 , no bad debt expense in the year ended December 31, 2023 and a reduction of $ 250,000 in the year ended December 31, 2022 . 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. Interest earned on cash equivalents is included in other income. 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 acquire mineral interests in natural gas and oil properties, to drill exploratory wells that find proved reserves and to drill development wells are capitalized. 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, NGLs 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 proved property impairment charges for the three-year period ended December 31, 2024. 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 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 $ 819.7 million as of December 31, 2024 compared to $ 789.9 million in 2023. We have recorded abandonment and impairment expense related to unproved properties of $ 8.4 million in the year ended December 31, 2024 compared to $ 46.4 million in 2023 and $ 28.6 million in 2022. 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. Gain or loss recognized on dispositions is included in other income. Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, internal-use software, 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 $ 1.4 million in the year ended December 31, 2024 compared to $ 1.5 million in the year ended December 31, 2023 and $ 2.2 million in the year ended December 31, 2022 . Leases We determine if an arrangement is a lease at the inception of the arrangement. We lease certain drilling or completion equipment, 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 and completion equipment 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. For additional information regarding our leases, see Note 13 . Other Assets 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. Other assets at December 31, 2024 include $ 61.0 million of marketable securities held in our deferred compensation plan, $ 5.0 million of deferred financing costs related to our bank credit facility, $ 7.6 million of investments in surface acreage, $ 4.0 million of deferred tax assets and $ 2.0 million of other. Other assets at December 31, 2023 include $ 72.0 million of marketable securities held in our deferred compensation plan, $ 7.3 million of deferred financing costs related to our bank credit facility and $ 7.7 million of investments in surface acreage and $ 1.9 million of other. 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 10 . Derivative Financial Instruments We enter into financial commodity derivative contracts to manage exposure to price fluctuations on a portion of anticipated production volumes. We do not enter into these arrangements for speculative or trading purposes. 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 income (loss) in the accompanying consolidated statements of income. 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. Our program may also include three-way collars which are 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 price at which time the value of the purchased put is effectively capped. We have also entered into natural gas derivative instruments containing a fixed price swap and a sold option (which we refer to as a swaption). 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. For additional information regarding our derivative instruments, see Note 8 . Fair Value 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 (exit price). To estimate fair value, we utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The fair value standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. The hierarchy gives the highest priority to the unadjusted quoted prices in the active markets ("Level 1" measurements) and the lowest priority to unobservable inputs ("Level 3" measurements). 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. We value trading securities in the deferred compensation plan and derivative assets and liabilities at fair value on a recurring basis. Certain assets are measured at fair value on a non-recurring basis. For example, our proved natural gas properties and other property and equipment are assessed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable. There were no property impairment charges for the three-year period ended December 31, 2024. For additional information regarding the use of fair value, see Note 8 and Note 9 . Concentrations of Credit Risk As of December 31, 2024, 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 may also limit the level of exposure with any single counterparty. We do not anticipate a material impact on our financial results due to non-performance by third parties. For the year ended December 31, 2024, we had two customers that acc ounted for 10% or more of natural gas, NGLs and oil sales compared to one such customer for the year ended December 31, 2023 and no such customers for the year ended December 31, 2022 . Customer A represented 15 % of sales in 2024 and 13 % in 2023. Customer B represented 10 % of sales in 2024. 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. 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, 2024 , our derivative counterparties included fifteen financial institutions and commodity traders, of which all but five are secured lenders in our bank credit f acility. At December 31, 2024 , our net derivative asset includes a payable to the five counterparties not included in our bank credit facility totaling $ 11.5 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, 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 7 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 costs in the accompanying consolidated statements of income. See Note 14 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 13 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. See Note 4 for a more detailed discussion regarding our income taxes. Treasury Stock Treasury stock purchases are recorded at cost. Upon re-issuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. See Note 11 for a more detailed discussion regarding our treasury stock. Recently Adopted Accounting Standards In November 2023, the Financial Accounting Standards Board ("FASB") issued accounting standards update ("ASU") No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures . ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company has adopted ASU 2023-07 and updated our consolidated financial statement disclosures accordingly. Accounting Standards Not Yet Adopted In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures to improve its income tax disclosure requirements. Under this ASU, public business entities must annually (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. This ASU is effective for fiscal years beginning after December 15, 2024, and early adoption is permitted. The Company does not expect adoption of ASU 2023-09 to have a material impact on its financial statements and related disclosures. In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Incom

Revenues from Contracts with Cu

Revenues from Contracts with Customers	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Revenues from Contracts with Customers	(3) Revenues from Contracts with Customers Disaggregation of Revenue We have identified three material revenue streams in our business: natural gas sales, NGLs sales and oil 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, 2024 2023 2022 Natural gas sales $ 1,052,442 $ 1,234,308 $ 3,364,111 NGLs sales 1,020,903 933,791 1,308,574 Oil sales 140,505 166,562 238,407 Total natural gas, NGLs and oil sales 2,213,850 2,334,661 4,911,092 Sales of purchased natural gas 119,767 195,656 408,584 Sales of purchased NGLs 5,370 1,834 2,783 Other marketing revenue 7,911 9,062 8,409 Total $ 2,346,898 $ 2,541,213 $ 5,330,868 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, 2024, 2023 and 2022 , 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 $ 291.5 million at December 31, 2024 compared to $ 263.9 million at December 31, 2023 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Income Taxes	(4) Income Taxes Our income tax benefit was $ 15.7 million for the year ended December 31, 2024 compared to an expense of $ 229.2 million in 2023 and an expense of $ 230.5 million in 2022. The effective income tax rate is influenced by a variety of factors including geographic sources and relative magnitude of these sources of income as well as a reduction in our valuation allowances related to a change in the realizability of our federal and Pennsylvania deferred tax assets. Additionally, in the current year we recorded a tax benefit related to credits generated in the current year and as part of a look-back study. The state tax reconciling item includes tax expense related to a tax rate change in Louisiana which is equally offset by a change in the Louisiana valuation allowance included on the valuation allowance line . Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2024 2023 2022 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State, net of federal benefit 13.9 ( 0.1 ) 1.0 Equity compensation and executive compensation disallowance ( 0.5 ) ( 0.3 ) 0.2 Valuation allowances ( 28.1 ) 0.2 ( 5.5 ) Tax credits ( 12.7 ) — ( 0.4 ) Permanent differences and other 0.1 — — Effective tax rate ( 6.3 ) % 20.8 % 16.3 % Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands): Year Ended December 31, 2024 2023 2022 Current Federal $ 3,329 $ — $ — State 4,836 1,547 14,688 $ 8,165 $ 1,547 $ 14,688 Deferred Federal $ ( 7,310 ) $ 230,563 $ 245,839 State ( 16,590 ) ( 2,909 ) ( 30,067 ) ( 23,900 ) 227,654 215,772 Income tax (benefit) expense $ ( 15,735 ) $ 229,201 $ 230,460 At December 31, 2024, deferred tax liabilities exceeded deferred tax assets by $ 537.4 million . We continue to evaluate the realizability of our federal and state deferred tax assets. As of December 31, 2024 , we have a state valuation allowance of $ 125.0 million related to state tax attributes in Louisiana, Oklahoma, Texas and West Virginia. As of December 31, 2024 , we have no remaining federal or Pennsylvania valuation allowances. The net change in our deferred tax asset valuation allowances was a decrease of $ 70.4 million for the year ended December 31, 2024 compared to an increase of $ 2.7 million in 2023 and a decrease of $ 78.3 million in 2022. The current year decrease in the valuation allowance was a result of our ability to demonstrate strong pre-tax earnings in recent history which resulted in a release of all federal and Pennsylvania valuation allowances. At December 31, 2024 , we have federal NOL carryforwards of $ 1.4 billion, all of which were generated after 2017 that do not expire. We have state NOL carryforwards in Pennsylvania of $ 773.2 million that expire between 2031 and 2042 and in Louisiana, we have state NOL carryforwards of $ 1.7 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 2021 and after, and we are subject to various state tax examinations for years 2019 and after. We hav e 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, 2024 or December 31, 2023. Throughout 2024, 2023 and 2022, 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, further reducing by 0.5 % per year beginning in 2024, and becoming 4.99 % in 2031 and each year thereafter. Significant components of deferred tax assets and liabilities are as follows (in thousands): December 31, 2024 2023 Deferred tax assets: Net operating loss carryforward $ 424,487 $ 538,340 Divestiture contract obligation 87,311 107,067 Deferred compensation 14,480 17,342 Equity compensation 8,155 6,767 Asset retirement obligations 29,096 25,614 Interest expense carryforward 10,830 19,861 Lease right-of-use liabilities 26,726 6,023 Tax credits 31,941 10,104 Other 5,878 6,292 Valuation allowances: Federal — ( 23,396 ) State, net of federal benefit ( 124,979 ) ( 172,001 ) Total deferred tax assets 513,925 542,013 Deferred tax liabilities: Depreciation and depletion ( 1,010,139 ) ( 998,886 ) Unrealized mark-to-market gain ( 14,568 ) ( 96,545 ) Lease right-of-use assets ( 26,065 ) ( 5,184 ) Other ( 531 ) ( 2,686 ) Total deferred tax liabilities ( 1,051,303 ) ( 1,103,301 ) Net deferred tax liability $ ( 537,378 ) $ ( 561,288 )

Net Income Per Common Share

Net Income Per Common Share	12 Months Ended
	Dec. 31, 2024
Earnings Per Share [Abstract]
Net Income per Common Share	(5) Net Income 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 or 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, 2024 2023 2022 Net income as reported $ 266,340 $ 871,142 $ 1,183,370 Participating basic earnings (a) ( 1,298 ) ( 14,971 ) ( 28,578 ) Basic net income attributed to common stockholders 265,042 856,171 1,154,792 Reallocation of participating earnings (a) 8 159 614 Diluted net income attributed to common stockholders $ 265,050 $ 856,330 $ 1,155,406 Net income per common share: Basic $ 1.10 $ 3.61 $ 4.79 Diluted $ 1.09 $ 3.57 $ 4.69 (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, 2024 2023 2022 Denominator: Weighted average common shares outstanding – basic 240,689 236,986 240,858 Effect of dilutive securities 2,056 2,851 5,521 Weighted average common shares outstanding – diluted 242,745 239,837 246,379 Weighted average common shares outstanding – basic excludes 1.2 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 ended December 31, 2024 compared to 4.1 million shares for the period ended December 31, 2023 and 6.1 million shares for the period ended December 31, 2022. Equity grants of 3,000 shares for the year ended December 31, 2023 and 5,000 shares for the year ended December 31, 2022 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, 2024
Debt Disclosure [Abstract]
Indebtedness	(6) Indebtedness We had the following debt outstanding as of the dates shown below. The expenses of issuing debt are generally capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. For December 31, 2024 , deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized in the three-year period ended December 31, 2024. The components of our debt outstanding, including the effects of debt issuance costs, are as follows (in thousands): December 31, 2024 2023 Bank debt $ — $ — Senior notes: 4.875 % senior notes due 2025 608,702 688,388 8.25 % senior notes due 2029 600,000 600,000 4.75 % senior notes due 2030 500,000 500,000 Total senior notes 1,708,702 1,788,388 Unamortized debt issuance costs ( 10,819 ) ( 14,159 ) Total debt, net of deferred financing costs 1,697,883 1,774,229 Less current maturities of long-term debt (a) ( 608,269 ) — Total long-term debt $ 1,089,614 $ 1,774,229 (a) As of December 31, 2024, current maturities include $ 608.7 million principal amount of our 4.875 % senior notes due 2025 ( $ 608.3 million net of deferred financing costs). 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) which 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 re-determinations and for event-driven unscheduled re-determinations. 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. There was no debt outstanding on our bank facility for the year ended December 31, 2024 . The weighted average interest rate was 8.4 % for the year ended December 31, 2023 and 4.1 % for the year ended December 31, 2022 . A commitment fee is paid on the undrawn balance based on an annual rate of 0.375 % to 0.50 %. At December 31, 2024 , the commitment fee was 0.375 % and the interest rate margin was 0.75 % on our ABR loans and 1.75 % on our SOFR loans. On December 31, 2024, bank commitments totaled $ 1.5 billion and we had no outstanding borrowings under our bank credit facility. We had $ 165.3 million of undrawn letters of credit leaving $ 1.3 billion of committed borrowing capacity available under the facility. As part of our re-determination completed in October 2024, our borrowing base was reaffirmed for $ 3.0 billion and our bank commitments were also reaffirmed at $ 1.5 billion . 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. During 2024 , we repurchased in the open market $ 79.7 million aggregate principal amount of our 4.875 % senior notes due 2025 at a discount. We recognized a gain on early extinguishment of debt of $ 257,000 , net of the remaining deferred financing costs on the repurchased debt. 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 debt-to-EBITDAX (as defined in the credit agreement) of less than 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, 2024 . The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2024 (in thousands): Year Ended 2025 $ 608,702 2026 — 2027 — 2028 — 2029 600,000 Thereafter 500,000 $ 1,708,702

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(7) 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, 2024 and 2023 (in thousands): Year Ended December 31, 2024 2023 Beginning of period $ 117,429 $ 109,851 Liabilities incurred 3,871 2,047 Liabilities settled ( 4,655 ) ( 3,039 ) Accretion expense 7,148 6,000 Change in estimate 9,974 2,570 End of period 133,767 117,429 Less current portion ( 1,189 ) ( 2,395 ) Long-term asset retirement obligations $ 132,578 $ 115,034 Accretion expense is recognized within depreciation, depletion and amortization expense in the accompanying consolidated statements of income.

Derivative Activities

Derivative Activities	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Activities	(8) Derivative Activities The following table sets forth the derivative volumes and fair values by expiration year as of December 31, 2024, excluding our basis swaps which are discussed separately below. All fair values presented in the table utilize Level 2 inputs, except where noted: Period Contract Type Volume Hedged Weighted Average Hedge Price Swap Sold Put Floor Ceiling Fair Market Value Natural Gas (a) 2025 Swaps 400,000 Mmbtu/day $ 4.12 $ 84,763 2025 Three-way Collars 158,822 Mmbtu/day $ 2.53 $ 3.30 $ 4.82 $ 11,894 2026 Swaps 200,000 Mmbtu/day $ 4.05 $ 10,154 2027 Swaps 30,000 Mmbtu/day $ 4.10 $ 2,557 (a) We also sold natural gas swaptions of 150,000 Mmbtu/day for calendar year 2026 at a weighted average price of $ 4.00 /Mmbtu that expire between June and August 2025 . The fair value of these contracts as of December 31, 2024, which utilizes Level 3 inputs, was a net derivative liability of $ 13.2 million. 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 use the same approach, but will also utilize unobservable pricing inputs that are significant to overall value. Basis Swap Contracts In addition to the commodity derivatives described above, at December 31, 2024 , 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 2028 and include a total volume of 266,640,000 Mmbtu. The fair value of these contracts, which utilizes Level 2 inputs, was a net derivative liability of $ 29.2 million as of December 31, 2024. Derivative Assets and Liabilities The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2024 and 2023 is summarized below (in thousands). 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, December 31, Derivative assets: Gross amounts of recognized assets $ 112,359 $ 452,378 Gross amounts offset in the consolidated balance sheets ( 25,261 ) ( 9,407 ) Net amounts of assets presented in the consolidated balance sheets $ 87,098 $ 442,971 December 31, December 31, Derivative (liabilities): Gross amounts of recognized (liabilities) $ ( 45,383 ) $ ( 9,736 ) Gross amounts offset in the consolidated balance sheets 25,261 9,407 Net amounts of (liabilities) presented in the consolidated balance sheets $ ( 20,122 ) $ ( 329 ) Derivative Fair Value Income The effects of our derivatives on our consolidated statements of income for the last three years are summarized below (in thousands): Year Ended 2024 2023 2022 Natural gas derivatives $ 54,732 $ 814,113 $ ( 1,122,332 ) NGLs derivatives 3,744 — ( 9,318 ) Oil derivatives ( 1,750 ) 12,121 ( 67,763 ) Freight — — ( 33 ) Divestiture contingent consideration — ( 5,080 ) 10,940 Total derivative fair value income (loss) $ 56,726 $ 821,154 $ ( 1,188,506 )

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2024
Fair Value Disclosures [Abstract]
Fair Value Measurements	(9) Fair Value Measurements 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 inputs are favored. As of December 31, 2024, a portion of our natural gas instruments contain swaptions (Level 3 inputs) where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a pre-determined date. If exercised, the swaption contract becomes a swap treated consistently with our fixed-price swaps. At December 31, 2024 , we used a weighted average implied volatility of 24 % for our swaptions. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Year Ended Balance at December 31, 2023 $ ( 1,161 ) Total gains included in earnings — Additions ( 13,240 ) Settlements 1,161 Balance at December 31, 2024 $ ( 13,240 ) The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2024 and 2023 (in thousands): December 31, 2024 December 31, 2023 Carrying Fair Carrying Fair Assets: Commodity derivatives (a) $ 87,098 $ 87,098 $ 442,971 $ 442,971 Marketable securities (b) 60,989 60,989 71,989 71,989 (Liabilities): Commodity derivatives (a) ( 20,122 ) ( 20,122 ) ( 329 ) ( 329 ) Bank credit facility (c) — — — — 4.875 % senior notes due 2025 (c) ( 608,702 ) ( 607,363 ) ( 688,388 ) ( 679,363 ) 8.25 % senior notes due 2029 (c) ( 600,000 ) ( 618,114 ) ( 600,000 ) ( 624,816 ) 4.75 % senior notes due 2030 (c) ( 500,000 ) ( 469,285 ) ( 500,000 ) ( 463,085 ) Deferred compensation plan (d) ( 86,882 ) ( 86,882 ) ( 117,125 ) ( 117,125 ) (a) Fair values for commodity derivatives utilize Level 2 inputs with the exception of swaptions, which utilize Level 3 inputs. Fair value of swaption contracts as of December 31, 2024 was a net derivative liability of $ 13.2 million. (b) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges, which is a Level 1 input. (c) 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. Debt is presented on the balance sheet at carrying value. (d) The fair value of our deferred compensation plan is updated to 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. See Note 8 for information regarding the fair value of derivative instruments and Note 10 for information regarding the fair value of stock-based compensation awards.

Stock-Based Compensation Plans

Stock-Based Compensation Plans	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation Plans	(10) Stock-Based Compensation Plans Description of the Plans We have two active equity-based stock compensation plans, our Amended and Restated 2005 Equity-Based Compensation Plan and the Amended and Restated 2019 Equity-Based Compensation Plan. Under these plans, various awards may be issued to non-employee directors and employees pursuant to decisions of the Compensation Committee, which is composed of only non-employee, independent directors. We currently award time-based and performance-based stock awards. Time-Based Stock Awards We grant time-based restricted stock awards to employees and non-employee directors. These awards generally vest ratably over a three-year period or at the end of the three-year period for certain employees. The vesting of these awards are typically contingent on the recipient’s continued employment with us. Awards made to non-employee directors vest at the end of a one-year period and the vesting is typically contingent on the recipient's continued service as a non-employee director. These time-based stock awards can have two different types of accounting treatment, depending on whether they are placed into our deferred compensation plan (see further discussion below on the deferred compensation plan). Restricted stock awards that are placed into the deferred compensation plan upon grant are referred to as Liability Awards. Upon vesting, withdrawals are allowed in either cash or stock. Restricted stock awards that are accounted for using equity-classified award accounting are referred to as Equity Awards. Upon vesting, these awards will settle in stock only. Awards granted to employees are accounted for using equity-classified award accounting, as these awards are not placed into the deferred compensation plan. Prior to 2023, employee executives (VPs and above) were awarded time-based awards that were contributed to the deferred compensation plan and were accounted for using liability-classified award accounting. Subsequent annual grants made to employee executives were not contributed to the deferred compensation plan and were accounted for using equity-classified award accounting. Directors can elect to contribute their time-based stock awards to the deferred compensation plan at the time of grant. Awards that are elected to be contributed to the deferred compensation plan are accounted for using liability-classified award accounting. Equity Awards. Equity Awards are expensed ratably over the service period associated with the award based on the fair value of the awards. The grant date fair value of all Equity Awards is based on prevailing market prices on the date of grant. Equity Awards made to employee executives typically earn dividends prior to vesting that are payable in cash upon vesting. These dividends are forfeited and not paid if the associated shares do not vest. We recorded compensation expense for the restricted stock Equity Awards of $ 34.9 million in the year ended December 31, 2024 compared to $ 31.6 million in 2023 and $ 21.0 million in 2022. The vesting date fair value of restricted stock Equity Awards which vested during 2024, 2023 and 2022 was $ 35.7 million, $ 31.9 million and $ 20.3 million, respectively. As of December 31, 2024 , there was $ 34.4 million of unrecognized compensation related to restricted stock Equity Awards expected to be recognized over a weighted average period of 1.7 years. These awards are not issued until such time as they are vested and the grantees do not have the option to receive cash. Liability Awards. Liability Awards are recognized ratably over the service period associated with the award based on the fair value of the awards on the date of grant. The grant date fair value of Liability Awards is based on prevailing market prices at the time of the grant. Prior to vesting, restricted stock Liability Awards recipients have the right to receive dividends thereon. These restricted stock 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 income (see additional discussion below). We recorded compensation expense for these outstanding restricted stock Liability Awards of $ 1.4 million in the year ended December 31, 2024 compared to $ 4.0 million in 2023 and $ 13.6 million in 2022. The vesting date fair value of these restricted stock Liability Awards vested during 2024, 2023 and 2022 was $ 2.1 million, $ 4.3 million and $ 13.2 million, respectively. As of December 31, 2024 , there was $ 228,000 of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of less than one year . Performance-Based Stock Awards We have granted two types of performance share awards ("performance units"): one based on performance conditions measured against internal performance metrics and one based on market conditions measured related to Range’s performance relative to a predetermined peer group ("TSR Awards"). These awards typically vest at the end of the three-year performance period. Each unit granted represents one share of our common stock. These units are settled in stock and the amount of the payout is based on the vesting percentage, which can range from zero to 200 %, and (1) for our internal metric awards, the internal performance metrics achieved, which is determined by the Compensation Committee and (2) for our TSR Awards, the value of our common stock on the performance period ending date compared to our peers. Dividend equivalents accrue during the performance period and are paid in stock at the end of the performance period. The performance period is three years . Internal Performance Metric Awards. The performance metrics are set by the Compensation Committee. If the performance metric for the applicable period is not met, that portion is considered forfeited and an adjustment to expense recorded. Internal performance metric awards granted in 2023 and 2022 are earned based on: • Net debt (total debt less cash on hand balance); and • GHG emissions intensity. Range made significant progress towards long-term net debt and GHG emissions intensity targets in 2022 and 2023, so these internal performance metric awards were not utilized in 2024 . We recorded compensation expense for the prior grants of these awards of $ 3.3 million in the year ended December 31, 2024 compared to $ 2.2 million in the year ended December 31, 2023 and $ 6.2 million in the year ended December 31, 2022. As of December 31, 2024 , there was $ 780,000 of unrecognized compensation related to these internal performance metric awards to be recognized over a weighted average period of 1.2 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 fair value of the TSR awards 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 note 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, 2024, 2023 and 2022: Year Ended December 31, 2024 2023 2022 Risk-free interest rate 4.1 % 3.8 % 1.4 % Expected annual volatility 56 % 61 % 68 % Grant date fair value per unit $ 31.84 $ 30.37 $ 27.90 In 2024 , we granted 254,000 TSR awards as compensation to employees which vest at the end of a three-year period compared to 64,000 in 2023 and 112,000 in 2022 . We recorded TSR award compensation expense of $ 3.9 million in the year ended December 31, 2024 compared to $ 1.7 million in 2023 and $ 3.2 million in 2022. As of December 31, 2024 , there was $ 5.4 million of unrecognized compensation related to these TSR awards to be recognized over a weighted average period of 1.9 years. Total Stock-Based Compensation Expense Stock-based compensation represents amortization of restricted stock and performance units. The following details the allocation of stock-based compensation to functional expense categories for each of the years in the three-year period ended December 31, 2024 (in thousands): 2024 2023 2022 Direct operating expense $ 1,922 $ 1,723 $ 1,459 Brokered natural gas and marketing expense 2,465 2,095 2,439 Exploration expense 1,354 1,250 1,578 General and administrative expense 38,004 35,850 42,023 Total stock-based compensation expense $ 43,745 $ 40,918 $ 47,499 The mark-to-market adjustment of the liability related to the vested restricted stock Liability Awards held in our deferr ed compensation plan is directly tied to the change in our stock price and is not related to functional expenses and, therefore, is not allocated to the functional categories above. Stock Awards Summary The following is a summary of the activity for our time-based and performance-based restricted stock awards for the two years ended December 31, 2024 and 2023: Time-Based Time-Based Performance-Based Shares Weighted Shares Weighted Number (a) Weighted Outstanding at December 31, 2022 1,736,688 $ 14.44 379,633 $ 14.71 1,950,632 $ 9.02 Granted 1,629,816 25.11 21,170 25.41 145,747 26.86 Vested ( 1,863,153 ) 17.10 ( 307,687 ) 14.01 ( 1,158,797 ) 4.80 Forfeited ( 29,546 ) 17.73 — — — — Outstanding at December 31, 2023 1,473,805 $ 22.82 93,116 $ 19.44 937,582 $ 17.01 Granted 1,275,533 30.41 24,186 34.14 254,195 31.84 Vested ( 1,455,086 ) 24.53 ( 98,810 ) 21.25 ( 526,918 ) 10.99 Forfeited ( 18,290 ) 29.07 — — — — Outstanding at December 31, 2024 1,275,962 $ 28.37 18,492 $ 28.98 664,859 $ 27.45 (a) Amounts granted reflect performance units initially granted. The actual payout will be between zero and 200 % depending on achievement of either total stockholder return ranking compared to our peers at the vesting date (TSR awards) or on the achievement of internal performance targets (internal performance metric awards). In 2024, we recorded an additional tax benefit of an estimate d $ 5.2 million for the tax effect of financial accounting expense compared to the corporate income tax deduction for equity compensation that vested d uring the year compared to additional tax benefit of $ 10.6 million in 2023 and additional tax benefit of $ 7.2 million in 2022. 401(k) Plan We maintain a 401(k) benefit plan that allows employees to contribute up to 75 % of their salary and bonus on an annual basis (subject to Internal Revenue Service limitations) on a pretax basis. We match, dollar for dollar, in cash up to 6 % of each participant's contribution and vesting of those contributions is immediate. In 2024 , we contributed $ 5.5 million to the 401(k) Plan compared to $ 5.2 million in 2023 and $ 4.8 million in 2022. Employees have a variety of investment options in the 401(k) benefit plan including investing in Range stock. 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 (as described above under Liability Awards) or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests at the end of three years and can be made in either cash or stock. Any stock contributed through the salary or bonus deferral match are treated as Liability Awards as described above. The assets of the plans are held in trading securities or as stock 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 trading securities held in the deferred compensation plan are exchange traded and are accounted for using the mark-to-market accounting method valued at fair value each reporting period utilizing Level 1 inputs. They 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 or losses are included in deferred compensation plan expense in the accompanying consolidated statements of income. For the year ended December 31, 2024 , interest and dividends were $ 1.3 million and mark-to-market was a gain of $ 4.5 million. For the year ended December 31, 2023 , interest and dividends were $ 1.6 million and mark-to-market was a gain of $ 7.8 million. 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. 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 income. We recorded a mark-to-market loss of $ 9.6 million in 2024 compared to a loss of $ 26.6 million in 2023 and a loss of $ 61.9 million in 2022 . The Rabbi Trust held 742,000 shares ( 724,000 vested shares) of Range stock at December 31, 2024 compared to 1.6 million ( 1.5 million of vested shares) at December 31, 2023 and 5.6 million ( 5.3 million vested shares) at December 31, 2022. The proceeds received from the sale of stock held in our deferred compensation plan were $ 20.1 million in 2024 compared to $ 75.2 million in 2023 and $ 22.2 million in 2022 .

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
Capital Stock	(11) 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 2023: Year Ended December 31, 2024 2023 Beginning balance 241,040,304 238,885,730 Restricted stock grants 24,186 50,238 Restricted stock units vested 1,192,633 1,755,345 Performance stock units vested 455,317 1,057,245 Performance stock dividends 6,914 6,276 Treasury shares ( 2,050,000 ) ( 714,530 ) Ending balance 240,669,354 241,040,304 Common Stock Dividends The payment of dividends is subject to the formal declaration by the board of directors. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and will depend on our financial condition, earnings, capital requirements, levels of indebtedness, our future business prospects and other matters our board of directors 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 repurchase program which was increased in size in 2022. 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 2024 , we repurchased 2,050,000 shares at an aggregate value of $ 65.3 million. As of December 31, 2024, we have approximately $ 1.0 billion of remaining authorization under this program. The following is a schedule of the change in treasury shares since the beginning of 2023: Year Ended December 31, 2024 2023 Beginning balance 24,716,065 24,001,535 Rabbi trust shares distributed/sold — ( 470 ) Shares repurchased 2,050,000 715,000 Ending balance 26,766,065 24,716,065

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2024
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(12) Supplemental Cash Flow Information Year Ended December 31, 2024 2023 2022 (in thousands) Net cash provided from operating activities included: Income taxes paid to taxing authorities $ ( 1,034 ) $ ( 2,200 ) $ ( 20,335 ) Interest paid ( 113,679 ) ( 120,631 ) ( 193,732 ) Non-cash investing activities included: Increase in asset retirement costs capitalized 13,845 4,616 18,096 Increase in accrued capital expenditures 24,525 4,403 1,966

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(13) 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, 2024 and 2023, liabilities for remediation were not material. We are not aware of any environmental claims existing as of December 31, 2024 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 in 2020. These obligations are primarily related to gathering, processing and transportation agreements including certain minimum volume commitments. For additional information see Note 14 . Lease Commitments The components of our total lease expense for the two years ended December 31, 2024, 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, 2024 2023 Operating lease cost $ 90,170 $ 70,781 Variable lease expense (1) 8,942 25,529 Short-term lease expense (2) 649 708 Sublease income ( 103 ) — Total lease expense $ 99,658 $ 97,018 Short-term lease costs (3) $ 10,478 $ 14,032 (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, 2024 2023 Cash paid for amounts included in the measurement of lease liabilities $ 93,137 $ 71,669 ROU assets added in exchange for lease obligations $ 180,342 $ 7,421 Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows: Year Ended December 31, 2024 2023 Weighted average remaining lease term 3.7 years 2.9 years Weighted average discount rate 6 % 7 % Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands): Operating 2025 $ 91,776 2026 7,540 2027 6,141 2028 3,241 2029 3,291 Thereafter 25,122 Total lease payments 137,111 Less effects of discounting ( 14,236 ) Total lease liability $ 122,875 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. 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. In the information below we have not considered any potential future renewals, although at times we will renew these agreements. As of December 31, 2024, future minimum transportation and gathering fees under our commitments are as follows (in thousands): Transportation (a) 2025 $ 835,018 2026 815,463 2027 794,968 2028 777,578 2029 668,391 Thereafter 2,691,096 $ 6,582,514 (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. We have also entered into amendments that are not in the above table, but modify existing contracts and are contingent on additional facility construction which is expected to be complete in 2026. The amendments will expand gathering and processing capacity by 300,000 mcf/day and transportation capacity by 250,000 Mmbtu/day. We will have a contingent related commitment for the de-ethanization capacity associated with this processing expansion. Beginning on the in-service date this capacity will total 40,000 bbl/day, increasing by 5,000 bbls/day after one year of service, and continues through the end of the agreement. We also entered into a new contract for propane export terminal capacity that is contingent on the construction of the relevant facilities and is expected to be in service in 2026. This capacity will be 10,000 bbls/day for the first year and increases to 20,000 bbls/day for the remainder of the term. Delivery Commitments We have various volume delivery commitments that we expect to be able to fulfill 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. In the information below we have not considered any potential future renewals, although at times we will renew these agreements. As of December 31, 2024, our delivery commitments through 2037 were as follows: Year Ending December 31, Natural Gas Ethane and Propane 2025 338,123 50,000 2026 243,739 50,000 2027 108,630 46,233 2028 100,000 45,000 2029 100,000 33,444 2030 — 30,000 2031 — 16,575 2032 — 10,000 2033-2037 — 10,000 (each year) 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, including the cost of infrastructure to connect production, 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. We also regularly provide letters of credit in the normal course of business under certain contracts that may be drawn if we fail to perform under those contracts.

Exit Costs

Exit Costs	12 Months Ended
	Dec. 31, 2024
Restructuring and Related Activities [Abstract]
Exit Costs	(14) 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 year ended December 31, 2024, we recorded accretion expense of $ 39.2 million compared to $ 41.9 million in 2023 and $ 43.6 million in 2022 . In 2024, we recorded a net adjustment of $ 2.1 million to decrease the obligation mainly due to a decrease in forecasted electricity costs. In 2023, we recorded net adjustments of $ 57.7 million to increase this obligation primarily for higher rates due to inflation and to increase the obligation for a change to our forecasted 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. There are inherent uncertainties surrounding the retained obligation and, as a result, the determination of the accrued obligation required judgment and estimation. The actual settlement amount and timing may differ from our estimates. The estimated discounted value for this divestiture contract obligation was $ 344.3 million at December 31, 2024 , of which $ 87.0 million is classified as short-term. 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 in 2020 which represented the discounted present value of our remaining obligations to the third party. As of December 31, 2024, this obligation is complete and has no remaining carrying value. The following summarizes our exit costs for the three years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 2023 2022 Transportation contract capacity releases 126 $ 345 $ 579 Divestiture contract obligation 37,088 99,595 69,758 Total exit costs $ 37,214 $ 99,940 $ 70,337 The following details the accrued exit cost liability activity for the years ended December 31, 2024 and 2023 (in thousands): Exit Costs Louisiana Pennsylvania Pipeline Balance at December 31, 2022 $ 390,620 $ 5,060 Accretion of discount 41,860 345 Changes in estimate 57,735 — Payments ( 92,766 ) ( 2,865 ) Balance at December 31, 2023 397,449 2,540 Accretion of discount 39,185 126 Changes in estimate ( 2,097 ) — Payments ( 90,229 ) ( 2,666 ) Balance at December 31, 2024 $ 344,308 $ — As of December 31, 2024, our estimated settlement of the remaining divestiture contract obligation based on a discounted value is as follows (in thousands): Divestiture 2025 $ 86,991 2026 68,458 2027 58,781 2028 53,756 2029 48,814 Thereafter 27,508 $ 344,308

Suspended Exploratory Well Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2024
Oil and Gas, Capitalized Exploratory Well Cost [Abstract]
Suspended Exploratory Well Costs	( 15) 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 income. There were no capitalized exploratory well costs in 2022 or 2023. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2024 (in thousands): Year Ended Balance at beginning of period $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 12,569 Reclassifications to wells, facilities and equipment based on determination of proved reserves — Capitalized exploratory well costs, charged to expense — Balance at end of period $ 12,569 Less exploratory well costs that have been capitalized for a period of one year or less $ 12,569 Capitalized exploratory well costs that have been capitalized for a period greater than one year $ —

Supplemental Information on Nat

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	(16) 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, 2024 2023 2022 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 11,058,771 $ 10,435,611 $ 9,855,287 Unproved properties 819,656 789,871 800,592 Total 11,878,427 11,225,482 10,655,879 Accumulated depreciation, depletion and amortization ( 5,456,727 ) ( 5,107,801 ) ( 4,765,475 ) Net capitalized costs $ 6,421,700 $ 6,117,681 $ 5,890,404 (a) Includes capitalized asset retirement costs and the associated accumulated amortization. Costs Incurred for Property Acquisition, Exploration and Development (a) December 31, 2024 2023 2022 (in thousands) Acquisitions: Acreage purchases $ 57,869 $ 40,067 $ 28,735 Development 577,093 568,484 460,668 Exploration: Drilling 12,569 — — Expense 25,489 25,280 25,194 Stock-based compensation expense 1,354 1,250 1,578 Gas gathering facilities: Development 4,336 3,123 1,466 Subtotal 678,710 638,204 517,641 Asset retirement obligations 13,845 4,616 18,096 Total costs incurred $ 692,555 $ 642,820 $ 535,737 (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 2024, Netherland, Sewell & Associates, Inc., an independent petroleum consultant, conducted an audit of our 2024 reserves in Appalachia. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. The proved reserve audits performed for 2024, 2023 and 2022, in the aggregate, represented 96 % for each of the three years. The reserve audits performed for 2024, 2023 and 2022, in the aggregate, represented 99 %, 99 % and 96 %, respectively, of our 2024, 2023, and 2022 associated pre-tax present value of proved reserves discounted at ten percent . A copy of the reserve summary report prepared by the independent petroleum consultant is included as an exhibit to this Annual Report on Form 10-K. The technical person at our independent petroleum consulting firm responsible for reviewing the reserves 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. Additionally, on an annual basis the board of directors approves the development plan. 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 approximately 5% . All of o ur 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 Natural Gas, NGLs and Oil Reserves Reserves of natural gas, NGLs, and oil 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, and oil that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. The term "reasonable certainty" implies a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal technical staff employs technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, decline curve analysis, well logs, geologic maps and available downhole and production data, seismic data, well test data, reservoir simulation modeling and implementation and application of enhanced data analytics. 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. We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2024 , NGLs represented approximately 35 % of our total proved reserves on an mcf equivalent basis. NGLs are products priced by the gallon (and sold by the barrel) to our customers. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels. Prices for a barrel of NGLs in 2024 averaged approximat ely 34 % of the av erage price for equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs. We currently include ethane in our proved reserves which match volumes to be delivered under our existing long-term, extendable ethane contracts. The average realized prices used at December 31, 2024 to estimate reserve information were $ 63.39 per barrel of oil, $ 24.40 per barrel of NGLs and $ 1.74 per mcf for gas using a benchmark (NYMEX) of $ 74.88 per barrel and $ 2.13 per Mmbtu. The a verage realized prices used at December 31, 2023 to estimate reserve information were $ 68.32 per barrel of oil, $ 24.91 per barrel of NGLs and $ 2.20 per mcf for gas using a benchmark of $ 78.10 per barrel and $ 2.62 per Mmbtu. 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 of $ 94.13 per barrel and $ 6.36 per Mmbtu. Natural Gas NGLs Oil Natural (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: 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 Revisions 326,783 44,515 2,485 608,784 Extensions, discoveries and additions 24,078 30,234 296 207,260 Production ( 538,085 ) ( 37,940 ) ( 2,475 ) ( 780,575 ) Balance, December 31, 2023 11,610,748 1,040,767 42,962 18,113,125 Revisions 17,299 16,530 ( 6,785 ) 75,765 Extensions, discoveries and additions 578,660 25,659 2,792 749,362 Property sales ( 10,542 ) — — ( 10,542 ) Production ( 545,416 ) ( 39,623 ) ( 2,181 ) ( 796,235 ) Balance, December 31, 2024 11,650,749 1,043,333 36,788 18,131,475 Proved developed reserves: December 31, 2021 6,809,849  577,507  23,833  10,417,887 December 31, 2022 7,230,313 594,931 22,213 10,933,180 December 31, 2023 7,631,202 629,379 21,396 11,535,852 December 31, 2024 7,929,452 647,430 19,460 11,930,793 Proved undeveloped reserves: December 31, 2021 4,642,232  423,798  28,763  7,357,597 December 31, 2022 4,567,659 409,027 20,443 7,144,476 December 31, 2023 3,979,546 411,388 21,566 6,577,273 December 31, 2024 3,721,297 395,903 17,328 6,200,682 (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 2024, revisions of previous estimates of a positive 75.8 Bcfe includes a positive revision of 457.2 Bcfe for previously undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan and positive performance revisions of 391.4 Bcfe due to improved well performance and longer lateral lengths partially offset by negative pricing revisions of 1.3 Bcfe and 771.5 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. We added 749.4 Bcfe of proved reserves from drilling activities and evaluation of proved areas in Pennsylvania. Our ethane reserves are intended to match volumes delivered under our existing long-term, extendable contracts along with meeting pipeline specificat ions. During 2023, revisions of previous estimates of a positive 608.8 Bcfe include a positive revision of 280.2 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan and positive performance revisions of 701.4 Bcfe due to improved well performance and longer lateral lengths partially offset by negative pricing revisions of 2.2 Bcfe and 370.6 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. We added approximately 207.3 Bcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. 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 included 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 of 0.9 Bcfe more than offset by 1,381.9 Bcfe 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 out-performance 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. The following details the changes in proved undeveloped reserves for 2024 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2023 6,577,273 Undeveloped reserves transferred to developed ( 998,927 ) Revisions (a) ( 116,052 ) Extension and discoveries 738,388 Ending proved undeveloped reserves at December 31, 2024 6,200,682 (a) Includes 457.2 Bcfe positive revision for previously proved undeveloped properties due to their addition back into our five year development plan along with 183.2 Bcfe of positive revisions due to improved recovery associated with extended lateral lengths and 15.0 Bcfe of revisions due to increased ethane recoveries. These are offset by 771.5 Bcfe of proved undeveloped reserves removed and deferred due to the five-year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan. During 2024, we spent $ 512.1 million on develo pment costs related to proved undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $ 2.3 billion. As of December 31, 2024 , we have no proved undeveloped reserves that have been reported for more than five years from their original date of booking. All of our recorded proved undeveloped drilling locations are scheduled to be drilled within five years of initial disclosure. 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 and oil 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, and oil 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 2024, 2023 and 2022, 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, and oil 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, 2024 2023 (in thousands) Future cash inflows $ 48,101,796 $ 54,389,915 Future costs: Production ( 30,097,778 ) ( 29,663,691 ) Development (a) ( 2,742,638 ) ( 2,978,183 ) Future net cash flows before income taxes 15,261,380 21,748,041 Future income tax expense ( 2,876,562 ) ( 4,176,604 ) Total future net cash flows before 10% discount 12,384,818 17,571,437 10% annual discount ( 7,693,744 ) ( 10,732,951 ) Standardized measure of discounted future net cash flows $ 4,691,074 $ 6,838,486 (a) 2024 includes $ 413.3 million of undiscounted future asset retirement costs as of December 31, 2024, using current estimates of future abandonment costs. The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2024 2023 2022 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ ( 2,601,024 ) $ ( 23,584,574 ) $ 14,326,997 Revisions in quantities ( 78,775 ) ( 131,078 ) 109,129 Changes in future development and abandonment costs ( 167,061 ) ( 123,529 ) ( 524,847 ) Net change in income taxes 324,863 3,920,556 ( 2,625,699 ) Accretion of discount 792,623 2,955,359 1,486,783 Additions to proved reserves from extensions, 265,917 103,116 2,842,173 Natural gas, NGLs and oil sales, net of production costs ( 918,980 ) ( 1,100,908 ) ( 3,550,632 ) Actual development costs incurred during the period 598,635 574,646 471,877 Sales of reserves in place ( 5,265 ) — — Changes in timing and other ( 358,345 ) ( 320,385 ) ( 475,724 ) Net change for the year ( 2,147,412 ) ( 17,706,797 ) 12,060,057 Beginning of year 6,838,486 24,545,283 12,485,226 End of year $ 4,691,074 $ 6,838,486 $ 24,545,283

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2024
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 generally accepted accounting principles ("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. Estimated quantities of natural gas, NGLs and oil 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 and oil. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs and oil 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 oil that are ultimately recovered. See Note 16 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	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, NGLs and oil producing activities. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. Our Chief Executive Officer is the Chief Operating Decision Maker ("CODM"). We measure financial performance as a single enterprise and not on an area-by-area basis. Our exploration and production operations are limited to onshore United States and all of our sales transfer title and control in the onshore United States. Income before income taxes as presented in the consolidated statements of income is the primary measure of segment profit and loss used by the CODM in assessing business performance and making capital allocation decisions by comparing actual amounts to historical results and previously forecasted financial information.
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 for processing. 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-driven price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index-driven 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-driven 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-driven 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 and Marketing. 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 or NGLs purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas or NGLs 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 $ 7.5 million in 2024 compared to income of $ 3.7 million in 2023 and loss of $ 7.3 million in 2022. 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 judgment, 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 $ 255,000 at December 31, 2024 compared to $ 308,000 at December 31, 2023. We recorded bad debt expense of $ 50,000 in the year ended December 31, 2024 , no bad debt expense in the year ended December 31, 2023 and a reduction of $ 250,000 in the year ended December 31, 2022 .
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. Interest earned on cash equivalents is included in other income.
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 acquire mineral interests in natural gas and oil properties, to drill exploratory wells that find proved reserves and to drill development wells are capitalized. 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, NGLs 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 proved property impairment charges for the three-year period ended December 31, 2024. 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 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 $ 819.7 million as of December 31, 2024 compared to $ 789.9 million in 2023. We have recorded abandonment and impairment expense related to unproved properties of $ 8.4 million in the year ended December 31, 2024 compared to $ 46.4 million in 2023 and $ 28.6 million in 2022. 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. Gain or loss recognized on dispositions is included in other income.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, internal-use software, 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 $ 1.4 million in the year ended December 31, 2024 compared to $ 1.5 million in the year ended December 31, 2023 and $ 2.2 million in the year ended December 31, 2022 .
Leases	Leases We determine if an arrangement is a lease at the inception of the arrangement. We lease certain drilling or completion equipment, 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 and completion equipment 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. For additional information regarding our leases, see Note 13 .
Other Assets	Other Assets 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. Other assets at December 31, 2024 include $ 61.0 million of marketable securities held in our deferred compensation plan, $ 5.0 million of deferred financing costs related to our bank credit facility, $ 7.6 million of investments in surface acreage, $ 4.0 million of deferred tax assets and $ 2.0 million of other. Other assets at December 31, 2023 include $ 72.0 million of marketable securities held in our deferred compensation plan, $ 7.3 million of deferred financing costs related to our bank credit facility and $ 7.7 million of investments in surface acreage and $ 1.9 million of other.
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 10 .
Derivative Financial Instruments	Derivative Financial Instruments We enter into financial commodity derivative contracts to manage exposure to price fluctuations on a portion of anticipated production volumes. We do not enter into these arrangements for speculative or trading purposes. 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 income (loss) in the accompanying consolidated statements of income. 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. Our program may also include three-way collars which are 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 price at which time the value of the purchased put is effectively capped. We have also entered into natural gas derivative instruments containing a fixed price swap and a sold option (which we refer to as a swaption). 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. For additional information regarding our derivative instruments, see Note 8 .
Fair Value	Fair Value 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 (exit price). To estimate fair value, we utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The fair value standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. The hierarchy gives the highest priority to the unadjusted quoted prices in the active markets ("Level 1" measurements) and the lowest priority to unobservable inputs ("Level 3" measurements). 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. We value trading securities in the deferred compensation plan and derivative assets and liabilities at fair value on a recurring basis. Certain assets are measured at fair value on a non-recurring basis. For example, our proved natural gas properties and other property and equipment are assessed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable. There were no property impairment charges for the three-year period ended December 31, 2024. For additional information regarding the use of fair value, see Note 8 and Note 9 .
Concentrations of Credit Risk	Concentrations of Credit Risk As of December 31, 2024, 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 may also limit the level of exposure with any single counterparty. We do not anticipate a material impact on our financial results due to non-performance by third parties. For the year ended December 31, 2024, we had two customers that acc ounted for 10% or more of natural gas, NGLs and oil sales compared to one such customer for the year ended December 31, 2023 and no such customers for the year ended December 31, 2022 . Customer A represented 15 % of sales in 2024 and 13 % in 2023. Customer B represented 10 % of sales in 2024. 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. 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, 2024 , our derivative counterparties included fifteen financial institutions and commodity traders, of which all but five are secured lenders in our bank credit f acility. At December 31, 2024 , our net derivative asset includes a payable to the five counterparties not included in our bank credit facility totaling $ 11.5 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, 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 7 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 costs in the accompanying consolidated statements of income. See Note 14 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 13 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. See Note 4 for a more detailed discussion regarding our income taxes.
Treasury Stock	Treasury Stock Treasury stock purchases are recorded at cost. Upon re-issuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. See Note 11 for a more detailed discussion regarding our treasury stock.
Recently Adopted Accounting Standards	Recently Adopted Accounting Standards In November 2023, the Financial Accounting Standards Board ("FASB") issued accounting standards update ("ASU") No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures . ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company has adopted ASU 2023-07 and updated our consolidated financial statement disclosures accordingly. Accounting Standards Not Yet Adopted In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures to improve its income tax disclosure requirements. Under this ASU, public business entities must annually (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. This ASU is effective for fiscal years beginning after December 15, 2024, and early adoption is permitted. The Company does not expect adoption of ASU 2023-09 to have a material impact on its financial statements and related disclosures. In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) to improve its expense disclosure requirements. Under this ASU, public business entities at interim and annual reporting periods must (1) disclose the amounts for specific categories of expenses within relevant expense captions, (2) include certain amounts that are already required to be disclosed under current GAAP in the same disclosure as the other disaggregation requirements, (3) disclose a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively and (4) disclose the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. This ASU is effective for annual reporting periods beginning after December 15, 2026, and for interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is evaluating the impact that ASU 2024-03 will have on the consolidated financial statements and its plans for adoption, including the adoption date. There are no other accounting standards applicable to us that would have a material effect on our consolidated financial statements and disclosures that have been issued but not yet adopted by us as of December 31, 2024, and through the filing date of this report.

Revenues from Contracts with _2

Revenues from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2022 Natural gas sales $ 1,052,442 $ 1,234,308 $ 3,364,111 NGLs sales 1,020,903 933,791 1,308,574 Oil sales 140,505 166,562 238,407 Total natural gas, NGLs and oil sales 2,213,850 2,334,661 4,911,092 Sales of purchased natural gas 119,767 195,656 408,584 Sales of purchased NGLs 5,370 1,834 2,783 Other marketing revenue 7,911 9,062 8,409 Total $ 2,346,898 $ 2,541,213 $ 5,330,868

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax	Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2024 2023 2022 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State, net of federal benefit 13.9 ( 0.1 ) 1.0 Equity compensation and executive compensation disallowance ( 0.5 ) ( 0.3 ) 0.2 Valuation allowances ( 28.1 ) 0.2 ( 5.5 ) Tax credits ( 12.7 ) — ( 0.4 ) Permanent differences and other 0.1 — — Effective tax rate ( 6.3 ) % 20.8 % 16.3 %
Income Tax (Benefit) Expense Attributable to Income Before Income Taxes	Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands): Year Ended December 31, 2024 2023 2022 Current Federal $ 3,329 $ — $ — State 4,836 1,547 14,688 $ 8,165 $ 1,547 $ 14,688 Deferred Federal $ ( 7,310 ) $ 230,563 $ 245,839 State ( 16,590 ) ( 2,909 ) ( 30,067 ) ( 23,900 ) 227,654 215,772 Income tax (benefit) expense $ ( 15,735 ) $ 229,201 $ 230,460
Significant Components of Deferred Tax Assets and Liabilities	Significant components of deferred tax assets and liabilities are as follows (in thousands): December 31, 2024 2023 Deferred tax assets: Net operating loss carryforward $ 424,487 $ 538,340 Divestiture contract obligation 87,311 107,067 Deferred compensation 14,480 17,342 Equity compensation 8,155 6,767 Asset retirement obligations 29,096 25,614 Interest expense carryforward 10,830 19,861 Lease right-of-use liabilities 26,726 6,023 Tax credits 31,941 10,104 Other 5,878 6,292 Valuation allowances: Federal — ( 23,396 ) State, net of federal benefit ( 124,979 ) ( 172,001 ) Total deferred tax assets 513,925 542,013 Deferred tax liabilities: Depreciation and depletion ( 1,010,139 ) ( 998,886 ) Unrealized mark-to-market gain ( 14,568 ) ( 96,545 ) Lease right-of-use assets ( 26,065 ) ( 5,184 ) Other ( 531 ) ( 2,686 ) Total deferred tax liabilities ( 1,051,303 ) ( 1,103,301 ) Net deferred tax liability $ ( 537,378 ) $ ( 561,288 )

Net Income Per Common Share (Ta

Net Income Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2024
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 or 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, 2024 2023 2022 Net income as reported $ 266,340 $ 871,142 $ 1,183,370 Participating basic earnings (a) ( 1,298 ) ( 14,971 ) ( 28,578 ) Basic net income attributed to common stockholders 265,042 856,171 1,154,792 Reallocation of participating earnings (a) 8 159 614 Diluted net income attributed to common stockholders $ 265,050 $ 856,330 $ 1,155,406 Net income per common share: Basic $ 1.10 $ 3.61 $ 4.79 Diluted $ 1.09 $ 3.57 $ 4.69 (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, 2024 2023 2022 Denominator: Weighted average common shares outstanding – basic 240,689 236,986 240,858 Effect of dilutive securities 2,056 2,851 5,521 Weighted average common shares outstanding – diluted 242,745 239,837 246,379

Indebtedness (Tables)

Indebtedness (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Debt Outstanding	We had the following debt outstanding as of the dates shown below. The expenses of issuing debt are generally capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. For December 31, 2024 , deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized in the three-year period ended December 31, 2024. The components of our debt outstanding, including the effects of debt issuance costs, are as follows (in thousands): December 31, 2024 2023 Bank debt $ — $ — Senior notes: 4.875 % senior notes due 2025 608,702 688,388 8.25 % senior notes due 2029 600,000 600,000 4.75 % senior notes due 2030 500,000 500,000 Total senior notes 1,708,702 1,788,388 Unamortized debt issuance costs ( 10,819 ) ( 14,159 ) Total debt, net of deferred financing costs 1,697,883 1,774,229 Less current maturities of long-term debt (a) ( 608,269 ) — Total long-term debt $ 1,089,614 $ 1,774,229 (a) As of December 31, 2024, current maturities include $ 608.7 million principal amount of our 4.875 % senior notes due 2025 ( $ 608.3 million net of deferred financing costs).
Schedule for Long-Term Debt Outstanding	The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2024 (in thousands): Year Ended 2025 $ 608,702 2026 — 2027 — 2028 — 2029 600,000 Thereafter 500,000 $ 1,708,702

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2024 and 2023 (in thousands): Year Ended December 31, 2024 2023 Beginning of period $ 117,429 $ 109,851 Liabilities incurred 3,871 2,047 Liabilities settled ( 4,655 ) ( 3,039 ) Accretion expense 7,148 6,000 Change in estimate 9,974 2,570 End of period 133,767 117,429 Less current portion ( 1,189 ) ( 2,395 ) Long-term asset retirement obligations $ 132,578 $ 115,034

Derivative Activities (Tables)

Derivative Activities (Tables)	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Volumes Hedged and Average Hedge Prices	The following table sets forth the derivative volumes and fair values by expiration year as of December 31, 2024, excluding our basis swaps which are discussed separately below. All fair values presented in the table utilize Level 2 inputs, except where noted: Period Contract Type Volume Hedged Weighted Average Hedge Price Swap Sold Put Floor Ceiling Fair Market Value Natural Gas (a) 2025 Swaps 400,000 Mmbtu/day $ 4.12 $ 84,763 2025 Three-way Collars 158,822 Mmbtu/day $ 2.53 $ 3.30 $ 4.82 $ 11,894 2026 Swaps 200,000 Mmbtu/day $ 4.05 $ 10,154 2027 Swaps 30,000 Mmbtu/day $ 4.10 $ 2,557 (a) We also sold natural gas swaptions of 150,000 Mmbtu/day for calendar year 2026 at a weighted average price of $ 4.00 /Mmbtu that expire between June and August 2025 . The fair value of these contracts as of December 31, 2024, which utilizes Level 3 inputs, was a net derivative liability of $ 13.2 million.
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, 2024 and 2023 is summarized below (in thousands). 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, December 31, Derivative assets: Gross amounts of recognized assets $ 112,359 $ 452,378 Gross amounts offset in the consolidated balance sheets ( 25,261 ) ( 9,407 ) Net amounts of assets presented in the consolidated balance sheets $ 87,098 $ 442,971 December 31, December 31, Derivative (liabilities): Gross amounts of recognized (liabilities) $ ( 45,383 ) $ ( 9,736 ) Gross amounts offset in the consolidated balance sheets 25,261 9,407 Net amounts of (liabilities) presented in the consolidated balance sheets $ ( 20,122 ) $ ( 329 ) Derivative Fair Value Income
Effects of Derivatives on Consolidated Statements of Income	The effects of our derivatives on our consolidated statements of income for the last three years are summarized below (in thousands): Year Ended 2024 2023 2022 Natural gas derivatives $ 54,732 $ 814,113 $ ( 1,122,332 ) NGLs derivatives 3,744 — ( 9,318 ) Oil derivatives ( 1,750 ) 12,121 ( 67,763 ) Freight — — ( 33 ) Divestiture contingent consideration — ( 5,080 ) 10,940 Total derivative fair value income (loss) $ 56,726 $ 821,154 $ ( 1,188,506 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2024
Fair Value Disclosures [Abstract]
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, 2023 $ ( 1,161 ) Total gains included in earnings — Additions ( 13,240 ) Settlements 1,161 Balance at December 31, 2024 $ ( 13,240 )
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, 2024 and 2023 (in thousands): December 31, 2024 December 31, 2023 Carrying Fair Carrying Fair Assets: Commodity derivatives (a) $ 87,098 $ 87,098 $ 442,971 $ 442,971 Marketable securities (b) 60,989 60,989 71,989 71,989 (Liabilities): Commodity derivatives (a) ( 20,122 ) ( 20,122 ) ( 329 ) ( 329 ) Bank credit facility (c) — — — — 4.875 % senior notes due 2025 (c) ( 608,702 ) ( 607,363 ) ( 688,388 ) ( 679,363 ) 8.25 % senior notes due 2029 (c) ( 600,000 ) ( 618,114 ) ( 600,000 ) ( 624,816 ) 4.75 % senior notes due 2030 (c) ( 500,000 ) ( 469,285 ) ( 500,000 ) ( 463,085 ) Deferred compensation plan (d) ( 86,882 ) ( 86,882 ) ( 117,125 ) ( 117,125 ) (a) Fair values for commodity derivatives utilize Level 2 inputs with the exception of swaptions, which utilize Level 3 inputs. Fair value of swaption contracts as of December 31, 2024 was a net derivative liability of $ 13.2 million. (b) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges, which is a Level 1 input. (c) 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. Debt is presented on the balance sheet at carrying value. (d) The fair value of our deferred compensation plan is updated to 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, 2024
Allocation of Stock-Based Compensation by Functional Category	The following details the allocation of stock-based compensation to functional expense categories for each of the years in the three-year period ended December 31, 2024 (in thousands): 2024 2023 2022 Direct operating expense $ 1,922 $ 1,723 $ 1,459 Brokered natural gas and marketing expense 2,465 2,095 2,439 Exploration expense 1,354 1,250 1,578 General and administrative expense 38,004 35,850 42,023 Total stock-based compensation expense $ 43,745 $ 40,918 $ 47,499 The mark-to-market adjustment of the liability related to the vested restricted stock Liability Awards held in our deferr
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, 2024, 2023 and 2022: Year Ended December 31, 2024 2023 2022 Risk-free interest rate 4.1 % 3.8 % 1.4 % Expected annual volatility 56 % 61 % 68 % Grant date fair value per unit $ 31.84 $ 30.37 $ 27.90
Time Based and Performance Based Restricted Stock Awards Outstanding	The following is a summary of the activity for our time-based and performance-based restricted stock awards for the two years ended December 31, 2024 and 2023: Time-Based Time-Based Performance-Based Shares Weighted Shares Weighted Number (a) Weighted Outstanding at December 31, 2022 1,736,688 $ 14.44 379,633 $ 14.71 1,950,632 $ 9.02 Granted 1,629,816 25.11 21,170 25.41 145,747 26.86 Vested ( 1,863,153 ) 17.10 ( 307,687 ) 14.01 ( 1,158,797 ) 4.80 Forfeited ( 29,546 ) 17.73 — — — — Outstanding at December 31, 2023 1,473,805 $ 22.82 93,116 $ 19.44 937,582 $ 17.01 Granted 1,275,533 30.41 24,186 34.14 254,195 31.84 Vested ( 1,455,086 ) 24.53 ( 98,810 ) 21.25 ( 526,918 ) 10.99 Forfeited ( 18,290 ) 29.07 — — — — Outstanding at December 31, 2024 1,275,962 $ 28.37 18,492 $ 28.98 664,859 $ 27.45 (a) Amounts granted reflect performance units initially granted. The actual payout will be between zero and 200 % depending on achievement of either total stockholder return ranking compared to our peers at the vesting date (TSR awards) or on the achievement of internal performance targets (internal performance metric awards).

Capital Stock (Tables)

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2024
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 2023: Year Ended December 31, 2024 2023 Beginning balance 241,040,304 238,885,730 Restricted stock grants 24,186 50,238 Restricted stock units vested 1,192,633 1,755,345 Performance stock units vested 455,317 1,057,245 Performance stock dividends 6,914 6,276 Treasury shares ( 2,050,000 ) ( 714,530 ) Ending balance 240,669,354 241,040,304
Schedule of Change in Treasury Shares	The following is a schedule of the change in treasury shares since the beginning of 2023: Year Ended December 31, 2024 2023 Beginning balance 24,716,065 24,001,535 Rabbi trust shares distributed/sold — ( 470 ) Shares repurchased 2,050,000 715,000 Ending balance 26,766,065 24,716,065

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2024
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Year Ended December 31, 2024 2023 2022 (in thousands) Net cash provided from operating activities included: Income taxes paid to taxing authorities $ ( 1,034 ) $ ( 2,200 ) $ ( 20,335 ) Interest paid ( 113,679 ) ( 120,631 ) ( 193,732 ) Non-cash investing activities included: Increase in asset retirement costs capitalized 13,845 4,616 18,096 Increase in accrued capital expenditures 24,525 4,403 1,966

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024, 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, 2024 2023 Operating lease cost $ 90,170 $ 70,781 Variable lease expense (1) 8,942 25,529 Short-term lease expense (2) 649 708 Sublease income ( 103 ) — Total lease expense $ 99,658 $ 97,018 Short-term lease costs (3) $ 10,478 $ 14,032 (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, 2024 2023 Cash paid for amounts included in the measurement of lease liabilities $ 93,137 $ 71,669 ROU assets added in exchange for lease obligations $ 180,342 $ 7,421
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, 2024 2023 Weighted average remaining lease term 3.7 years 2.9 years Weighted average discount rate 6 % 7 %
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 2025 $ 91,776 2026 7,540 2027 6,141 2028 3,241 2029 3,291 Thereafter 25,122 Total lease payments 137,111 Less effects of discounting ( 14,236 ) Total lease liability $ 122,875
Schedule of Future Minimum Transportation Fees Due	As of December 31, 2024, future minimum transportation and gathering fees under our commitments are as follows (in thousands): Transportation (a) 2025 $ 835,018 2026 815,463 2027 794,968 2028 777,578 2029 668,391 Thereafter 2,691,096 $ 6,582,514 (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.
Future Delivery Commitments	As of December 31, 2024, our delivery commitments through 2037 were as follows: Year Ending December 31, Natural Gas Ethane and Propane 2025 338,123 50,000 2026 243,739 50,000 2027 108,630 46,233 2028 100,000 45,000 2029 100,000 33,444 2030 — 30,000 2031 — 16,575 2032 — 10,000 2033-2037 — 10,000 (each year)

Exit Costs (Tables)

Exit Costs (Tables)	12 Months Ended
	Dec. 31, 2024
Restructuring and Related Activities [Abstract]
Summary of Exit Costs	The following summarizes our exit costs for the three years ended December 31, 2024, 2023 and 2022 (in thousands): Year Ended December 31, 2024 2023 2022 Transportation contract capacity releases 126 $ 345 $ 579 Divestiture contract obligation 37,088 99,595 69,758 Total exit costs $ 37,214 $ 99,940 $ 70,337
Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet	The following details the accrued exit cost liability activity for the years ended December 31, 2024 and 2023 (in thousands): Exit Costs Louisiana Pennsylvania Pipeline Balance at December 31, 2022 $ 390,620 $ 5,060 Accretion of discount 41,860 345 Changes in estimate 57,735 — Payments ( 92,766 ) ( 2,865 ) Balance at December 31, 2023 397,449 2,540 Accretion of discount 39,185 126 Changes in estimate ( 2,097 ) — Payments ( 90,229 ) ( 2,666 ) Balance at December 31, 2024 $ 344,308 $ —
Schedule of Estimated Settlement of Divestiture Contract Obligation Based On Discounted Value	As of December 31, 2024, our estimated settlement of the remaining divestiture contract obligation based on a discounted value is as follows (in thousands): Divestiture 2025 $ 86,991 2026 68,458 2027 58,781 2028 53,756 2029 48,814 Thereafter 27,508 $ 344,308

Suspended Exploratory Well Co_2

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2024
Oil and Gas, Capitalized Exploratory Well Cost [Abstract]
Schedule Of Changes In Capitalized Exploratory Well Costs	The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2024 (in thousands): Year Ended Balance at beginning of period $ — Additions to capitalized exploratory well costs pending the determination of proved reserves 12,569 Reclassifications to wells, facilities and equipment based on determination of proved reserves — Capitalized exploratory well costs, charged to expense — Balance at end of period $ 12,569 Less exploratory well costs that have been capitalized for a period of one year or less $ 12,569 Capitalized exploratory well costs that have been capitalized for a period greater than one year $ —

Supplemental Information on N_2

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization	Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2024 2023 2022 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 11,058,771 $ 10,435,611 $ 9,855,287 Unproved properties 819,656 789,871 800,592 Total 11,878,427 11,225,482 10,655,879 Accumulated depreciation, depletion and amortization ( 5,456,727 ) ( 5,107,801 ) ( 4,765,475 ) Net capitalized costs $ 6,421,700 $ 6,117,681 $ 5,890,404 (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, 2024 2023 2022 (in thousands) Acquisitions: Acreage purchases $ 57,869 $ 40,067 $ 28,735 Development 577,093 568,484 460,668 Exploration: Drilling 12,569 — — Expense 25,489 25,280 25,194 Stock-based compensation expense 1,354 1,250 1,578 Gas gathering facilities: Development 4,336 3,123 1,466 Subtotal 678,710 638,204 517,641 Asset retirement obligations 13,845 4,616 18,096 Total costs incurred $ 692,555 $ 642,820 $ 535,737 (a) Includes cost incurred whether capitalized or expensed.
Proved Developed and Undeveloped Reserves	Natural Gas NGLs Oil Natural (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: 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 Revisions 326,783 44,515 2,485 608,784 Extensions, discoveries and additions 24,078 30,234 296 207,260 Production ( 538,085 ) ( 37,940 ) ( 2,475 ) ( 780,575 ) Balance, December 31, 2023 11,610,748 1,040,767 42,962 18,113,125 Revisions 17,299 16,530 ( 6,785 ) 75,765 Extensions, discoveries and additions 578,660 25,659 2,792 749,362 Property sales ( 10,542 ) — — ( 10,542 ) Production ( 545,416 ) ( 39,623 ) ( 2,181 ) ( 796,235 ) Balance, December 31, 2024 11,650,749 1,043,333 36,788 18,131,475 Proved developed reserves: December 31, 2021 6,809,849  577,507  23,833  10,417,887 December 31, 2022 7,230,313 594,931 22,213 10,933,180 December 31, 2023 7,631,202 629,379 21,396 11,535,852 December 31, 2024 7,929,452 647,430 19,460 11,930,793 Proved undeveloped reserves: December 31, 2021 4,642,232  423,798  28,763  7,357,597 December 31, 2022 4,567,659 409,027 20,443 7,144,476 December 31, 2023 3,979,546 411,388 21,566 6,577,273 December 31, 2024 3,721,297 395,903 17,328 6,200,682 (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 2024 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2023 6,577,273 Undeveloped reserves transferred to developed ( 998,927 ) Revisions (a) ( 116,052 ) Extension and discoveries 738,388 Ending proved undeveloped reserves at December 31, 2024 6,200,682 (a) Includes 457.2 Bcfe positive revision for previously proved undeveloped properties due to their addition back into our five year development plan along with 183.2 Bcfe of positive revisions due to improved recovery associated with extended lateral lengths and 15.0 Bcfe of revisions due to increased ethane recoveries. These are offset by 771.5 Bcfe of proved undeveloped reserves removed and deferred due to the five-year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan.
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, and oil 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, 2024 2023 (in thousands) Future cash inflows $ 48,101,796 $ 54,389,915 Future costs: Production ( 30,097,778 ) ( 29,663,691 ) Development (a) ( 2,742,638 ) ( 2,978,183 ) Future net cash flows before income taxes 15,261,380 21,748,041 Future income tax expense ( 2,876,562 ) ( 4,176,604 ) Total future net cash flows before 10% discount 12,384,818 17,571,437 10% annual discount ( 7,693,744 ) ( 10,732,951 ) Standardized measure of discounted future net cash flows $ 4,691,074 $ 6,838,486 (a) 2024 includes $ 413.3 million of undiscounted future asset retirement costs as of December 31, 2024, using current estimates of future abandonment costs.
Changes in Discounted Future Net Cash Flows	The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2024 2023 2022 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ ( 2,601,024 ) $ ( 23,584,574 ) $ 14,326,997 Revisions in quantities ( 78,775 ) ( 131,078 ) 109,129 Changes in future development and abandonment costs ( 167,061 ) ( 123,529 ) ( 524,847 ) Net change in income taxes 324,863 3,920,556 ( 2,625,699 ) Accretion of discount 792,623 2,955,359 1,486,783 Additions to proved reserves from extensions, 265,917 103,116 2,842,173 Natural gas, NGLs and oil sales, net of production costs ( 918,980 ) ( 1,100,908 ) ( 3,550,632 ) Actual development costs incurred during the period 598,635 574,646 471,877 Sales of reserves in place ( 5,265 ) — — Changes in timing and other ( 358,345 ) ( 320,385 ) ( 475,724 ) Net change for the year ( 2,147,412 ) ( 17,706,797 ) 12,060,057 Beginning of year 6,838,486 24,545,283 12,485,226 End of year $ 4,691,074 $ 6,838,486 $ 24,545,283

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2024 USD ($) Counterparties Counterparty Customer	Dec. 31, 2023 USD ($) Customer	Dec. 31, 2022 USD ($) Customer
Summary Of Significant Accounting Policies [Line Items]
Net brokered margin gain (loss)		$ 7,500,000	$ 3,700,000	$ 7,300,000
Allowance for doubtful accounts on accounts receivable		255,000	308,000
Bad debt (income) expense		50,000	0	(250,000)
Net book value of unproved properties	[1]	819,656,000	789,871,000	800,592,000
Abandonment and impairment of unproved properties		8,417,000	46,359,000	28,608,000
Depreciation expense		$ 1,400,000	1,500,000	$ 2,200,000
Lessee, operating lease, contract term		12 months
Marketable securities held in deferred compensation plans		$ 61,000,000	72,000,000
Deferred financing cost related to bank credit facility		5,000,000	7,300,000
Investments and other		2,000,000	1,900,000
Surface acreage investments		7,600,000	$ 7,700,000
Deferred tax assets		$ 4,000,000
Number of customers accounted more than 10% of total oil and gas revenues | Customer		2	1	0
Number of counterparties | Counterparty		5
Number of financial institutions included in counter parties | Counterparty		15
Number of counterparties amount payable | Counterparties		5
Impairment of oil and gas properties		$ 0
Revenue Contract with Customer | Customer A | Customer Concentration Risk
Summary Of Significant Accounting Policies [Line Items]
Percentage of cash		15%	13%
Revenue Contract with Customer | Customer B | Customer Concentration Risk
Summary Of Significant Accounting Policies [Line Items]
Percentage of cash		10%
Counterparties in a Liability position
Summary Of Significant Accounting Policies [Line Items]
Net derivative liability		$ 11,500,000
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] (a) Includes capitalized asset retirement costs and the associated accumulated amortization.

Revenues from Contracts with _3

Revenues from Contracts with Customers - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) Stream	Dec. 31, 2023 USD ($)
Disaggregation of Revenue [Line Items]
Number of revenue streams | Stream	3
Maximum
Disaggregation of Revenue [Line Items]
Settlement statements, number of days	90 days
Minimum
Disaggregation of Revenue [Line Items]
Settlement statements, number of days	30 days
Revenue Contract with Customer
Disaggregation of Revenue [Line Items]
Accounts receivable | $	$ 291.5	$ 263.9

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Total Revenue	$ 2,346,898	$ 2,541,213	$ 5,330,868
Natural Gas, NGLs and Oil Sales
Disaggregation of Revenue [Line Items]
Total Revenue	2,213,850	2,334,661	4,911,092
Natural Gas, NGLs and Oil Sales | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	1,052,442	1,234,308	3,364,111
Natural Gas, NGLs and Oil Sales | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	1,020,903	933,791	1,308,574
Natural Gas, NGLs and Oil Sales | Oil sales
Disaggregation of Revenue [Line Items]
Total Revenue	140,505	166,562	238,407
Brokered Natural Gas, Marketing and Other | Natural gas sales
Disaggregation of Revenue [Line Items]
Total Revenue	119,767	195,656	408,584
Brokered Natural Gas, Marketing and Other | NGLs sales
Disaggregation of Revenue [Line Items]
Total Revenue	5,370	1,834	2,783
Brokered Natural Gas, Marketing and Other | Other marketing revenue
Disaggregation of Revenue [Line Items]
Total Revenue	$ 7,911	$ 9,062	$ 8,409

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)		12 Months Ended
	Jul. 12, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Taxes [Line Items]
Income tax expense (benefit)		$ (15,735,000)	$ 229,201,000	$ 230,460,000
Deferred tax liabilities		537,378,000	561,288,000
Accrued interest or penalties related to tax amounts		0	0
Change in Valuation Allowances		70,400,000	$ 2,700,000	$ 78,300,000
PENNSYLVANIA
Income Taxes [Line Items]
Valuation allowances		0
Net operating loss carryforwards		$ 773,200,000
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, prior	9.99%		8.99%
LOUISIANA
Income Taxes [Line Items]
Net operating loss carryforward not subject to expiration		$ 1,700,000,000
Federal
Income Taxes [Line Items]
Valuation allowances		0	$ 23,396,000
Net operating loss carryforwards		1,400,000,000
State
Income Taxes [Line Items]
Valuation allowances		$ 124,979,000	$ 172,001,000

Income Taxes - Reconciliation B

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory tax rate	21%	21%	21%
State, net of federal benefit	13.90%	(0.10%)	1%
Equity compensation and executive compensation disallowance	(0.50%)	(0.30%)	0.20%
Valuation allowances	(28.10%)	0.20%	(5.50%)
Tax credits	(12.70%)	0%	(0.40%)
Permanent differences and other	0.10%	0%	0%
Effective tax rate	(6.30%)	20.80%	16.30%

Income Taxes - Income Tax (Bene

Income Taxes - Income Tax (Benefit) Expense Attributable to Income Before Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current, Federal	$ 3,329	$ 0	$ 0
Current, State	4,836	1,547	14,688
Current	8,165	1,547	14,688
Deferred, Federal	(7,310)	230,563	245,839
Deferred, State	(16,590)	(2,909)	(30,067)
Deferred	(23,900)	227,654	215,772
Income tax (benefit) expense	$ (15,735)	$ 229,201	$ 230,460

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Deferred tax assets:
Net operating loss carryforward	$ 424,487	$ 538,340
Divestiture contract obligation	87,311	107,067
Deferred compensation	14,480	17,342
Equity compensation	8,155	6,767
Asset retirement obligations	29,096	25,614
Interest expense carryforward	10,830	19,861
Lease right-of-use liabilities	26,726	6,023
Tax credits	31,941	10,104
Other	5,878	6,292
Total deferred tax assets	513,925	542,013
Deferred tax liabilities:
Depreciation and depletion	(1,010,139)	(998,886)
Unrealized mark-to-market gain	(14,568)	(96,545)
Lease right-of-use assets	(26,065)	(5,184)
Other	(531)	(2,686)
Total deferred tax liabilities	(1,051,303)	(1,103,301)
Net deferred tax liability	(537,378)	(561,288)
Federal
Valuation allowances:
Valuation allowances	0	(23,396)
State, net of federal benefit
Valuation allowances:
Valuation allowances	$ (124,979)	$ (172,001)

Net Income Per Common Share - C

Net Income 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, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share Reconciliation [Abstract]
Net Income (Loss)		$ 266,340	$ 871,142	$ 1,183,370
Participating basic earnings	[1]	(1,298)	(14,971)	(28,578)
Basic net income attributed to common stockholders		265,042	856,171	1,154,792
Reallocation of participating earnings	[1]	8	159	614
Diluted net income attributed to common stockholders		$ 265,050	$ 856,330	$ 1,155,406
Net income per common share:
Basic		$ 1.1	$ 3.61	$ 4.79
Diluted		$ 1.09	$ 3.57	$ 4.69
[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 Per Common Share - B

Net Income 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, 2024	Dec. 31, 2023	Dec. 31, 2022
Denominator:
Weighted average common shares outstanding - basic	240,689	236,986	240,858
Effect of dilutive securities	2,056	2,851	5,521
Weighted average common shares outstanding - diluted	242,745	239,837	246,379

Net Income Per Common Share - A

Net Income Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	1,200,000	4,100,000	6,100,000
Equity Grants
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation		3,000	5,000

Indebtedness - Additional Infor

Indebtedness - Additional Information (Detail)	36 Months Ended
	Dec. 31, 2024 USD ($)
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0

Indebtedness - Debt Outstanding

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands		Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Total senior notes		$ 1,708,702	$ 1,788,388
Unamortized debt issuance costs		(10,819)	(14,159)
Total debt, net of deferred financing costs		1,697,883	1,774,229
Less current maturities of long-term debt	[1]	(608,269)	0
Total long-term debt		1,089,614	1,774,229
Notes Payable to Banks
Debt Instrument [Line Items]
Bank debt		0	0
4.875% Senior Notes Due 2025 | Notes Payable to Banks
Debt Instrument [Line Items]
Total senior notes		608,702	688,388
8.25% Senior Notes Due 2029 | Notes Payable to Banks
Debt Instrument [Line Items]
Total senior notes		600,000	600,000
4.75% Senior Notes Due 2030 | Notes Payable to Banks
Debt Instrument [Line Items]
Total senior notes		$ 500,000	$ 500,000
[1] (a) As of December 31, 2024, current maturities include $ 608.7 million principal amount of our 4.875 % senior notes due 2025 ( $ 608.3 million net of deferred financing costs).

Indebtedness - Debt Outstandi_2

Indebtedness - Debt Outstanding (Parenthetical) (Detail) - USD ($) $ in Thousands		Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Current maturities of long-term debt	[1]	$ 608,269	$ 0
Total senior notes		$ 1,708,702	$ 1,788,388
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate on notes		4.875%	4.875%
4.875% Senior Notes Due 2025 | Notes Payable to Banks
Debt Instrument [Line Items]
Total senior notes		$ 608,702	$ 688,388
8.25% Senior Notes Due 2029
Debt Instrument [Line Items]
Interest rate on notes		8.25%	8.25%
8.25% Senior Notes Due 2029 | Notes Payable to Banks
Debt Instrument [Line Items]
Total senior notes		$ 600,000	$ 600,000
4.75% Senior Notes Due 2030
Debt Instrument [Line Items]
Interest rate on notes		4.75%	4.75%
4.75% Senior Notes Due 2030 | Notes Payable to Banks
Debt Instrument [Line Items]
Total senior notes		$ 500,000	$ 500,000
[1] (a) As of December 31, 2024, current maturities include $ 608.7 million principal amount of our 4.875 % senior notes due 2025 ( $ 608.3 million net of deferred financing costs).

Indebtedness - Bank Debt - Addi

Indebtedness - Bank Debt - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2024 USD ($) Commercialbank	Dec. 31, 2023	Dec. 31, 2022	Oct. 31, 2024 USD ($)
Debt Instrument [Line Items]
Bank credit facility, maximum amount	$ 4,000,000,000
Bank credit facility, borrowing base	3,000,000,000			$ 3,000,000,000
Bank commitments	$ 1,500,000,000			$ 1,500,000,000
Number of commercial banks included in current bank group | Commercialbank	17
Maturity date of loan	Apr. 14, 2027
Line of credit facility amount outstanding during period	$ 0
Outstanding amount	0
Undrawn letters of credit	165,300,000
Borrowing capacity available under the commitment amount	$ 1,300,000,000
Weighted average interest rate on the bank credit facility		8.40%	4.10%
Annual rate of commitment fee paid on the undrawn balance	0.375%
Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin	0.75%
SOFR
Debt Instrument [Line Items]
Interest rate margin	1.75%
Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.375%
Minimum | Alternate Base Rate
Debt Instrument [Line Items]
Interest rate on notes	0.75%
Minimum | SOFR
Debt Instrument [Line Items]
Interest rate on notes	1.75%
Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.50%
Maximum | Alternate Base Rate
Debt Instrument [Line Items]
Interest rate on notes	1.75%
Maximum | SOFR
Debt Instrument [Line Items]
Interest rate on notes	2.75%

Indebtedness - Senior Note Rede

Indebtedness - Senior Note Redemptions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Gain on early extinguishment of debt	$ 257,000	$ 438,000	$ (69,493,000)
Senior Notes
Debt Instrument [Line Items]
Redemption price of notes as percentage of principal amount	101%
Four Point Eight Seven Five Percent Senior Notes Due Two Thousand Twenty Five [Member]
Debt Instrument [Line Items]
Repurchases of senior notes on the open market	$ 79,700,000
Interest rate on notes	4.875%	4.875%
Gain on early extinguishment of debt	$ 257,000

Indebtedness - Debt Covenants a

Indebtedness - Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2024
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 debt-to-EBITDAX (as defined in the credit agreement) of less than 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, 2024.
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) $ in Thousands	Dec. 31, 2024 USD ($)
Debt Disclosure [Abstract]
2025	$ 608,702
2026	0
2027	0
2028	0
2029	600,000
Thereafter	500,000
Total debt	$ 1,708,702

Asset Retirement Obligations -

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation [Abstract]
Beginning of period	$ 117,429	$ 109,851
Liabilities incurred	3,871	2,047
Liabilities settled	(4,655)	(3,039)
Accretion expense	7,148	6,000
Change in estimate	9,974	2,570
End of period	133,767	117,429
Less current portion	(1,189)	(2,395)
Long-term asset retirement obligations	$ 132,578	$ 115,034

Derivative Activities - Additio

Derivative Activities - Additional Information (Detail) - Commodity - Natural Gas Basis Swaps $ in Millions	Dec. 31, 2024 USD ($) MMBTU
Derivative [Line Items]
Volume hedged | MMBTU	266,640,000
Fair Value, Inputs, Level 2
Derivative [Line Items]
Net derivative liability | $	$ 29.2

Derivative Activities - Derivat

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail) - Natural Gas $ in Thousands	Dec. 31, 2024 USD ($) MmbtuPerDay $ / MMBTU
2025 Commodity Contract | Swaps
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	400,000
Weighted Average Hedge Price, Swap	4.12
Fair Market Value | $	$ 84,763
2025 Commodity Contract | Three Way Collars
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	158,822
Weighted Average Hedge Price, Sold Put	2.53
Weighted Average Hedge Price, Floor	3.3
Weighted Average Hedge Price, Ceiling	4.82
Fair Market Value | $	$ 11,894
2026 Commodity Contract | Swaps
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	200,000
Weighted Average Hedge Price, Swap	4.05
Fair Market Value | $	$ 10,154
2027 Commodity Contract | Swaps
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	30,000
Weighted Average Hedge Price, Swap	4.1
Fair Market Value | $	$ 2,557

Derivative Activities - Deriv_2

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - Swaptions $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) MmbtuPerDay $ / MMBTU
Fair Value, Inputs, Level 3
Derivative [Line Items]
Net derivative liability	$ 13.2
2026 Commodity Contract
Derivative [Line Items]
Volume Hedged | MmbtuPerDay	150,000
Weighted average price of hedge | $ / MMBTU	4
2026 Commodity Contract | Fair Value, Inputs, Level 3
Derivative [Line Items]
Net derivative liability	$ 13.2
2026 Commodity Contract | Maximum
Derivative [Line Items]
Expiration of derivative non monetary notional amount	Aug. 31, 2025
2026 Commodity Contract | Minimum
Derivative [Line Items]
Expiration of derivative non monetary notional amount	Jun. 30, 2025

Derivative Activities - Combine

Derivative Activities - Combined Fair Value of Derivatives, by Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross amounts of recognized assets	$ 112,359	$ 452,378
Gross amounts offset in the consolidated balance sheets	(25,261)	(9,407)
Net amounts of assets presented in the consolidated balance sheets	87,098	442,971
Gross amounts of recognized (liabilities)	(45,383)	(9,736)
Gross amounts offset in the consolidated balance sheets	25,261	9,407
Net amounts of (liabilities) presented in the consolidated balance sheets	$ (20,122)	$ (329)

Derivative Activities - Effects

Derivative Activities - Effects of Derivatives on Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ 56,726	$ 821,154	$ (1,188,506)
Natural Gas Derivatives
Derivative [Line Items]
Derivative Fair Value Income (Loss)	54,732	814,113	(1,122,332)
NGLs Derivatives
Derivative [Line Items]
Derivative Fair Value Income (Loss)	3,744	0	(9,318)
Oil Derivatives
Derivative [Line Items]
Derivative Fair Value Income (Loss)	(1,750)	12,121	(67,763)
Freight
Derivative [Line Items]
Derivative Fair Value Income (Loss)	0	0	(33)
Contingent Consideration
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ 0	$ (5,080)	$ 10,940

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2024
Measurement Input, Price Volatility | Weighted Average | Natural Gas | Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Implied volatilities	24%

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, 2024 USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at December 31, 2023	$ (1,161)
Total gains included in earnings	0
Additions	(13,240)
Settlements	1,161
Balance at December 31, 2024	$ (13,240)

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($) $ in Thousands		Dec. 31, 2024	Dec. 31, 2023
Assets:
Marketable securities		$ 61,000	$ 72,000
Reported Value Measurement
Assets:
Commodity derivatives	[1]	87,098	442,971
Marketable securities	[2]	60,989	71,989
(Liabilities):
Commodity derivatives	[1]	(20,122)	(329)
Bank credit facility	[3]	0	0
Deferred compensation plan	[4]	(86,882)	(117,125)
Estimate of Fair Value Measurement
Assets:
Commodity derivatives	[1]	87,098	442,971
Marketable securities	[2]	60,989	71,989
(Liabilities):
Commodity derivatives	[1]	(20,122)	(329)
Bank credit facility	[3]	0	0
Deferred compensation plan	[4]	(86,882)	(117,125)
4.875% Senior Notes Due 2025 | Reported Value Measurement
(Liabilities):
Senior notes	[3]	(608,702)	(688,388)
4.875% Senior Notes Due 2025 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[3]	(607,363)	(679,363)
8.25% Senior Notes Due 2029 | Reported Value Measurement
(Liabilities):
Senior notes	[3]	(600,000)	(600,000)
8.25% Senior Notes Due 2029 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[3]	(618,114)	(624,816)
4.75% Senior Notes Due 2030 | Reported Value Measurement
(Liabilities):
Senior notes	[3]	(500,000)	(500,000)
4.75% Senior Notes Due 2030 | Estimate of Fair Value Measurement
(Liabilities):
Senior notes	[3]	$ (469,285)	$ (463,085)
[1] Fair values for commodity derivatives utilize Level 2 inputs with the exception of swaptions, which utilize Level 3 inputs. Fair value of swaption contracts as of December 31, 2024 was a net derivative liability of $ 13.2 million. Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges, 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. Debt is presented on the balance sheet at carrying value. The fair value of our deferred compensation plan is updated to 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, 2024	Dec. 31, 2023
4.875% Senior Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	4.875%	4.875%
8.25% Senior Notes Due 2029
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	8.25%	8.25%
4.75% Senior Notes Due 2030
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	4.75%	4.75%

Stock-Based Compensation Plan_2

Stock-Based Compensation Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2024 Plans
Share-Based Payment Arrangement [Abstract]
Active equity-based stock plans	2

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 43,745	$ 40,918	$ 47,499
Direct Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,922	1,723	1,459
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	2,465	2,095	2,439
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,354	1,250	1,578
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 38,004	$ 35,850	$ 42,023

Stock-Based Compensation Plan_4

Stock-Based Compensation Plans - Additional Information 1 (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units vested	$ 35.7	$ 31.9	$ 20.3
Stock-based compensation expense	$ 34.9	$ 31.6	$ 21
Weighted average period	1 year 8 months 12 days
Time Based Stock Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Time Based Stock Awards | Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Time Based Stock Awards | Non Employee Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	1 year

Stock-Based Compensation Plan_5

Stock-Based Compensation Plans - Additional Information 2 (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 1,400,000	$ 4,000,000	$ 13,600,000
Restricted stock units vested	2,100,000	4,300,000	13,200,000
Unrecognized compensation related to Awards	$ 228,000
Restricted Stock Liability Awards | Non-Employee Directors | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average period	1 year
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 34,900,000	31,600,000	21,000,000
Restricted stock units vested	35,700,000	31,900,000	20,300,000
Unrecognized compensation related to Awards	$ 34,400,000
Weighted average period	1 year 8 months 12 days
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation related to Awards	$ 780,000
Weighted average period	1 year 2 months 12 days
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 3,900,000	$ 1,700,000	$ 3,200,000
Unrecognized compensation related to Awards	$ 5,400,000
Weighted average period	1 year 10 months 24 days

Stock-Based Compensation Plan_6

Stock-Based Compensation Plans - Additional Information 3 (Detail) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2024 USD ($) Award $ / shares shares	Dec. 31, 2023 USD ($) Award $ / shares	Dec. 31, 2022 USD ($) Award $ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax expense (benefit)	$ (15,735)	$ 229,201	$ 230,460
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of awards available for grant | Award	2
Granted, weighted average grant date fair value | $ / shares	$ 31.84	$ 30.37	$ 27.9
Performance Share | Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of share value each unit represents at grant date | shares	1
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of awards available for grant | Award	1
Vesting period	3 years
Number of shares granted | Award	254,000	64,000	112,000
Stock-based compensation expense	$ 3,900	$ 1,700	$ 3,200
Performance Based TSR - PSUs | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200%
Performance Based TSR - PSUs | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0%
Performance-based PS-PSUs and RS-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Stock-based compensation expense	$ 3,300	2,200	6,200
Equity Compensation
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax expense (benefit)	$ (5,200)	$ (10,600)	$ (7,200)

Stock-Based Compensation Plan_7

Stock-Based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Share - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	4.10%	3.80%	1.40%
Expected annual volatility	56%	61%	68%
Grant date fair value per unit	$ 31.84	$ 30.37	$ 27.9

Stock-Based Compensation Plan_8

Stock-Based Compensation Plans - Time Based and Performance Based Restricted Stock Awards Outstanding (Detail) - $ / shares		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023
Time-Based Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance		1,473,805	1,736,688
Granted		1,275,533	1,629,816
Vested		(1,455,086)	(1,863,153)
Forfeited		(18,290)	(29,546)
Outstanding, Ending Balance		1,275,962	1,473,805
Outstanding, Beginning Balance, weighted average grant date fair value		$ 22.82	$ 14.44
Granted, weighted average grant date fair value		30.41	25.11
Vested and issued, weighted average grant date fair value		24.53	17.1
Forfeited, weighted average grant date fair value		29.07	17.73
Outstanding, Ending Balance, weighted average grant date fair value		$ 28.37	$ 22.82
Time-Based Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance		93,116	379,633
Granted		24,186	21,170
Vested		(98,810)	(307,687)
Forfeited		0	0
Outstanding, Ending Balance		18,492	93,116
Outstanding, Beginning Balance, weighted average grant date fair value		$ 19.44	$ 14.71
Granted, weighted average grant date fair value		34.14	25.41
Vested and issued, weighted average grant date fair value		21.25	14.01
Forfeited, weighted average grant date fair value		0	0
Outstanding, Ending Balance, weighted average grant date fair value		$ 28.98	$ 19.44
Performance-Based Stock Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	[1]	937,582	1,950,632
Granted	[1]	254,195	145,747
Vested	[1]	(526,918)	(1,158,797)
Forfeited	[1]	0	0
Outstanding, Ending Balance	[1]	664,859	937,582
Outstanding, Beginning Balance, weighted average grant date fair value		$ 17.01	$ 9.02
Granted, weighted average grant date fair value		31.84	26.86
Vested and issued, weighted average grant date fair value		10.99	4.8
Forfeited, weighted average grant date fair value		0	0
Outstanding, Ending Balance, weighted average grant date fair value		$ 27.45	$ 17.01
[1] (a) Amounts granted reflect performance units initially granted. The actual payout will be between zero and 200 % depending on achievement of either total stockholder return ranking compared to our peers at the vesting date (TSR awards) or on the achievement of internal performance targets (internal performance metric awards).

Stock-Based Compensation Plan_9

Stock-Based Compensation Plans - Restricted Stock and Restricted Stock Units and Performance Awards Outstanding (Parenthetical) (Detail) - Stock Based Performance Awards	12 Months Ended
	Dec. 31, 2024
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%

Stock-Based Compensation Pla_10

Stock-Based Compensation Plans - Additional Information 4 (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Retirement Benefits [Abstract]
Maximum percentage of employees contribution	75%
Maximum percentage of employers contribution in cash	6%
Employer contribution	$ 5,500	$ 5,200	$ 4,800
Deferred compensation plan vesting period	3 years
Interest and dividends	$ 1,300	1,600	1,100
Mark-to-market gain (loss)	4,500	7,800	(14,200)
Deferred compensation plan	$ (9,600)	$ (26,600)	$ (61,900)
Shares held in rabbi trust total	742,000	1,600,000	5,600,000
Vested shares held in rabbi trust	724,000	1,500,000	5,300,000
Proceeds from the sales of common stock held by the deferred compensation plan	$ 20,131	$ 75,201	$ 22,229

Capital Stock - Additional Info

Capital Stock - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Class Of Stock [Line Items]
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
Share repurchase, aggregate cost	$ 65.3
Shares repurchased	2,050,000	715,000
Stock repurchase program, authorized amount	$ 1,000

Capital Stock - Schedule of Cha

Capital Stock - Schedule of Changes in Number of Common Shares Outstanding (Detail) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Class Of Stock [Line Items]
Beginning balance	241,040,304	238,885,730
Treasury shares	(2,050,000)	(714,530)
Ending balance	240,669,354	241,040,304
Restricted Stock
Class Of Stock [Line Items]
Restricted stock grants	24,186	50,238
Restricted stock units vested	1,192,633	1,755,345
Performance Share
Class Of Stock [Line Items]
Performance stock units vested	455,317	1,057,245
Performance stock dividends	6,914	6,276

Capital Stock - Schedule of C_2

Capital Stock - Schedule of Change in Treasury Shares (Detail) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Stockholders' Equity Note [Abstract]
Beginning balance	24,716,065	24,001,535
Rabbi trust shares distributed/sold	0	(470)
Shares repurchased	2,050,000	715,000
Ending balance	26,766,065	24,716,065

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Net cash provided from operating activities included:
Income taxes paid to taxing authorities		$ (1,034)	$ (2,200)	$ (20,335)
Interest paid		(113,679)	(120,631)	(193,732)
Non-cash investing activities included:
Increase in asset retirement costs capitalized	[1]	13,845	4,616	18,096
Increase in accrued capital expenditures		$ 24,525	$ 4,403	$ 1,966
[1] (a) Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Components of Lease Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023
Commitments And Contingencies Disclosure [Line Items]
Operating lease cost		$ 90,170	$ 70,781
Variable lease expense	[1]	8,942	25,529
Sublease income		(103)	0
Total lease expense		99,658	97,018
Natural Gas and Oil Properties
Commitments And Contingencies Disclosure [Line Items]
Short-term lease expense / costs	[2]	10,478	14,032
Leases with Contract Term of One Year or Less
Commitments And Contingencies Disclosure [Line Items]
Short-term lease expense / costs	[3]	$ 649	$ 708
[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_2

Commitments and Contingencies - Supplemental Cash Flow Information Related to Operating Leases (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 93,137	$ 71,669
ROU assets added in exchange for lease obligations	$ 180,342	$ 7,421

Commitments and Contingencies_3

Commitments and Contingencies - Schedule of Weighted Average Remaining Lease Term and Weighted Average Discount Rate for Operating Leases (Detail)	Dec. 31, 2024	Dec. 31, 2023
Lessee Disclosure [Abstract]
Weighted average remaining lease term	3 years 8 months 12 days	2 years 10 months 24 days
Weighted average discount rate	6%	7%

Commitments and Contingencies_4

Commitments and Contingencies - Schedule of Lease Liabilities with Enforceable Contract Terms are Greater Than One year Mature (Detail) $ in Thousands	Dec. 31, 2024 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2025	$ 91,776
2026	7,540
2027	6,141
2028	3,241
2029	3,291
Thereafter	25,122
Total lease payments	137,111
Less effects of discounting	(14,236)
Total lease liability	$ 122,875

Commitments and Contingencies_5

Commitments and Contingencies - Schedule of Future Minimum Transportation Fees Due (Detail) $ in Thousands	Dec. 31, 2024 USD ($)	[1]
Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]
2025	$ 835,018
2026	815,463
2027	794,968
2028	777,578
2029	668,391
Thereafter	2,691,096
Transportation and Gathering Contracts	$ 6,582,514
[1] (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.

Commitments and Contingencies_6

Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2024 BblD MmbtuDay McfD
Commitments And Contingencies Disclosure [Line Items]
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
Contingent Commitment
Commitments And Contingencies Disclosure [Line Items]
Gathering and processing capacity | McfD	300,000
Additional volume of revised agreement | MmbtuDay	250,000
Increase in contingent minimum commitment	5,000
Contingent minimum commitment	40,000
Contingent Commitment | Propane Export Terminal | Minimum
Commitments And Contingencies Disclosure [Line Items]
Contingent minimum commitment	10,000
Contingent Commitment | Propane Export Terminal | Maximum
Commitments And Contingencies Disclosure [Line Items]
Contingent minimum commitment	20,000

Commitments and Contingencies_7

Commitments and Contingencies - Future Delivery Commitments (Detail)	12 Months Ended
	Dec. 31, 2024 MmbtuPerDay bbl / d
2025 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	338,123
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	243,739
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	108,630
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 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	0
2032 | Ethane and Propane
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	10,000
2033-2037 | Natural Gas
Contractual Sales Agreement [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MmbtuPerDay	0
2033-2037 | 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 ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2020
Restructuring Cost And Reserve [Line Items]
Accrued obligations		$ 344,308,000
North Louisiana
Restructuring Cost And Reserve [Line Items]
Exit and termination costs		2,100,000	$ 57,700,000
Exit cost					$ 479,800,000
Accrued obligations		344,300,000
Accretion expense		39,200,000	41,900,000	$ 43,600,000
Divestiture contract obligation, short term		87,000,000
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost		126,000	$ 345,000	$ 579,000
Pennsylvania | Capacity Releases on Transportation Pipelines
Restructuring Cost And Reserve [Line Items]
Exit cost	$ 10,400,000
Accrued obligations		$ 0

Exit Costs - Summary of Exit Co

Exit Costs - Summary of Exit Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Restructuring Cost And Reserve [Line Items]
Total exit costs	$ 37,214	$ 99,940	$ 70,337
Pennsylvania
Restructuring Cost And Reserve [Line Items]
Exit cost	126	345	579
North Louisiana Contract Release
Restructuring Cost And Reserve [Line Items]
Exit cost	$ 37,088	$ 99,595	$ 69,758

Exit Costs - Exit Costs Include

Exit Costs - Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet - (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Exit costs included in accrued liabilities in consolidated balance sheet
Ending balance	$ 344,308
Exit Costs | LOUISIANA
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	397,449	$ 390,620
Accretion of discount	39,185	41,860
Changes in estimate	(2,097)	57,735
Payments	(90,229)	(92,766)
Ending balance	344,308	397,449
Exit Costs | Pennsylvania Pipeline
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	2,540	5,060
Accretion of discount	126	345
Changes in estimate	0	0
Payments	(2,666)	(2,865)
Ending balance	$ 0	$ 2,540

Exit Costs - Schedule of Estima

Exit Costs - Schedule of Estimated Settlement of Divestiture Contract Obligation Based on Discounted Value (Detail) $ in Thousands	Dec. 31, 2024 USD ($)
Disclosure Commitments And Contingencies Schedule Of Estimated Settlement Of Divestiture Contract Obligation [Abstract]
2025	$ 86,991
2026	68,458
2027	58,781
2028	53,756
2029	48,814
Thereafter	27,508
Divestiture Contract Obligation	$ 344,308

Suspended Exploratory Well Co_3

Suspended Exploratory Well Costs - Additional Information (Detail) - USD ($)	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Capitalized Exploratory Well Cost [Abstract]
Capitalized exploratory well costs	$ 12,569,000	$ 0	$ 0

Suspended Exploratory Well Co_4

Suspended Exploratory Well Costs - Schedule Of Changes In Capitalized Exploratory Well Costs (Detail)	12 Months Ended
	Dec. 31, 2024 USD ($)
Oil and Gas, Capitalized Exploratory Well Cost [Abstract]
Balance at beginning of period	$ 0
Additions to capitalized exploratory well costs pending the determination of proved reserves	12,569,000
Reclassifications to wells, facilities and equipment based on determination of proved reserves	0
Capitalized exploratory well costs, charged to expense	0
Balance at end of period	12,569,000
Less exploratory well costs that have been capitalized for a period of one year or less	12,569,000
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 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, 2024	Dec. 31, 2023	Dec. 31, 2022
Natural gas and oil properties:
Properties subject to depletion	[1]	$ 11,058,771	$ 10,435,611	$ 9,855,287
Unproved properties	[1]	819,656	789,871	800,592
Total	[1]	11,878,427	11,225,482	10,655,879
Accumulated depreciation, depletion and amortization	[1]	(5,456,727)	(5,107,801)	(4,765,475)
Natural gas and oil properties, successful efforts method, net	[1]	$ 6,421,700	$ 6,117,681	$ 5,890,404
[1] (a) 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, 2024	Dec. 31, 2023	Dec. 31, 2022
Acquisitions:
Acreage purchases	[1]	$ 57,869	$ 40,067	$ 28,735
Development	[1]	577,093	568,484	460,668
Gas gathering facilities:
Development	[1]	4,336	3,123	1,466
Subtotal	[1]	678,710	638,204	517,641
Asset retirement obligations	[1]	13,845	4,616	18,096
Total costs incurred	[1]	692,555	642,820	535,737
Exploration Expense
Exploration:
Drilling	[1]	12,569	0	0
Expense	[1]	25,489	25,280	25,194
Stock-based compensation expense	[1]	$ 1,354	$ 1,250	$ 1,578
[1] (a) 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, 2024 USD ($) MMcfe Bcfe $ / bbl $ / MMBTU $ / Mcf	Dec. 31, 2023 MMcfe $ / MMBTU $ / Mcf $ / bbl	Dec. 31, 2022 MMcfe $ / Mcf $ / bbl $ / MMBTU
Reserve Quantities [Line Items]
Percentage of proved resources reviewed by consultants		96%	96%	96%
Percentage of reserve audits performed by consultants		99%	99%	96%
Proved reserve and pretax present value of reserve discounted		10%	10%	10%
Variance in reserve estimates		approximately 5%
Scheduled to be drilling period maximum for undeveloped reserves		scheduled to be drilled within five years
Percentage of natural gas liquids in the total proved reserves		35%
Price of NGLs barrel rate compare to oil		34%
Reserve additions attributable to natural gas				77%
Proved undeveloped reserves dropped		771,500	370,600	1,381,900
Revisions of positive pricing				900
Revision of negative pricing		1,300	2,200
Cost spent on undeveloped reserves transferred to developed reserves | $		$ 512.1
Estimated future development costs over years | $		$ 2,300
Proved undeveloped reserves reported for more than five years | Bcfe		0
Crude Oil and NGL
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / bbl		74.88	78.1	94.13
Crude Oil and Condensate
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		63.39	68.32	87.14
NGLs
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		24.4	24.91	38.35
Natural Gas
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / Mcf		1.74	2.2	6.08
Natural Gas, Per Thousand Cubic Feet
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / MMBTU		2.13	2.62	6.36
Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved reserves from drilling activities and evaluations of proved areas	[1]	749,362	207,260	1,668,244
Revisions of previous estimates	[1]	75,765	608,784	(591,983)
Revision of positive performance		391,400	701,400	72,800
Additional undeveloped properties reclassified		457,200	280,200	716,200
Maximum
Reserve Quantities [Line Items]
Statement that reserve estimates differ from auditors		0.10
[1] (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.

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, 2024 MMcfe MMBbls MMcf	Dec. 31, 2023 MMcfe MMBbls MMcf	Dec. 31, 2022 MMcfe MMBbls MMcf	Dec. 31, 2021 MMBbls MMcf
Natural Gas
Reserve Quantities [Line Items]
Beginning Balance | MMcf		11,610,748	11,797,972	11,452,081
Revisions | MMcf		17,299	326,783	(393,165)
Extensions, discoveries and additions | MMcf		578,660	24,078	1,278,499
Property sales | MMcf		(10,542)
Production | MMcf		(545,416)	(538,085)	(539,443)
Ending Balance | MMcf		11,650,749	11,610,748	11,797,972
Proved developed reserves:
Proved developed reserves | MMcf		7,929,452	7,631,202	7,230,313	6,809,849
Proved undeveloped reserves:
Proved undeveloped reserve | MMcf		3,721,297	3,979,546	4,567,659	4,642,232
NGLs
Reserve Quantities [Line Items]
Beginning Balance		1,040,767	1,003,958	1,001,305
Revisions		16,530	44,515	(20,251)
Extensions, discoveries and additions		25,659	30,234	59,296
Property sales		0
Production		(39,623)	(37,940)	(36,392)
Ending Balance		1,043,333	1,040,767	1,003,958
Proved developed reserves:
Proved developed reserves		647,430	629,379	594,931	577,507
Proved undeveloped reserves:
Proved undeveloped reserve		395,903	411,388	409,027	423,798
Crude Oil and Condensate
Reserve Quantities [Line Items]
Beginning Balance		42,962	42,656	52,596
Revisions		(6,785)	2,485	(12,885)
Extensions, discoveries and additions		2,792	296	5,661
Property sales		0
Production		(2,181)	(2,475)	(2,716)
Ending Balance		36,788	42,962	42,656
Proved developed reserves:
Proved developed reserves		19,460	21,396	22,213	23,833
Proved undeveloped reserves:
Proved undeveloped reserve		17,328	21,566	20,443	28,763
Natural Gas Equivalents
Proved developed reserves:
Proved developed reserves | MMcf	[1]	11,930,793	11,535,852	10,933,180	10,417,887
Proved undeveloped reserves:
Proved undeveloped reserve | MMcf	[1]	6,200,682	6,577,273	7,144,476	7,357,597
Beginning Balance | MMcfe	[1]	18,113,125	18,077,656	17,775,484
Revisions | MMcfe	[1]	75,765	608,784	(591,983)
Extensions, discoveries and additions | MMcfe	[1]	749,362	207,260	1,668,244
Property Sales | MMcfe	[1]	(10,542)
Production | MMcfe	[1]	(796,235)	(780,575)	(774,089)
Ending Balance | MMcfe	[1]	18,131,475	18,113,125	18,077,656
[1] (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.

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, 2024 MMcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves at December 31, 2023	6,577,273
Undeveloped reserves transferred to developed	(998,927)
Revisions	(116,052)	[1]
Extension and discoveries	738,388
Ending proved undeveloped reserves at December 31, 2024	6,200,682
[1] (a) Includes 457.2 Bcfe positive revision for previously proved undeveloped properties due to their addition back into our five year development plan along with 183.2 Bcfe of positive revisions due to improved recovery associated with extended lateral lengths and 15.0 Bcfe of revisions due to increased ethane recoveries. These are offset by 771.5 Bcfe of proved undeveloped reserves removed and deferred due to the five-year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan.

Supplemental Information on N_8

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Parenthetical) (Detail) - MMcfe	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Proved Reserve, Quantity [Line Items]
Positive revisions due to improved recovery associated with extended lateral lengths	183,200
Revisions due to increased ethane recoveries	15,000
Proved undeveloped reserves removed and deferred	771,500
Natural Gas Equivalents
Oil and Gas, Proved Reserve, Quantity [Line Items]
Additional undeveloped properties reclassified	457,200	280,200	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, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Future cash inflows		$ 48,101,796	$ 54,389,915
Future costs:
Production		(30,097,778)	(29,663,691)
Development	[1]	(2,742,638)	(2,978,183)
Future net cash flows before income taxes		15,261,380	21,748,041
Future income tax expense		(2,876,562)	(4,176,604)
Total future net cash flows before 10% discount		12,384,818	17,571,437
10% annual discount		(7,693,744)	(10,732,951)
Standardized measure of discounted future net cash flows		$ 4,691,074	$ 6,838,486	$ 24,545,283	$ 12,485,226
[1] (a) 2024 includes $ 413.3 million of undiscounted future asset retirement costs as of December 31, 2024, 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, 2024 USD ($)
Extractive Industries [Abstract]
Undiscounted future asset retirement costs estimation	$ 413.3

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Revisions of previous estimates:
Changes in prices and production costs	$ (2,601,024)	$ (23,584,574)	$ 14,326,997
Revisions in quantities	(78,775)	(131,078)	109,129
Changes in future development and abandonment costs	(167,061)	(123,529)	(524,847)
Net change in income taxes	324,863	3,920,556	(2,625,699)
Accretion of discount	792,623	2,955,359	1,486,783
Additions to proved reserves from extensions, discoveries and improved recovery	265,917	103,116	2,842,173
Natural gas, NGLs and oil sales, net of production costs	(918,980)	(1,100,908)	(3,550,632)
Actual development costs incurred during the period	598,635	574,646	471,877
Sales of reserves in place	(5,265)	0	0
Changes in timing and other	(358,345)	(320,385)	(475,724)
Net change for the year	(2,147,412)	(17,706,797)	12,060,057
Beginning of year	6,838,486	24,545,283	12,485,226
End of year	$ 4,691,074	$ 6,838,486	$ 24,545,283