EQT CORP, 10-K filed on 2/19/2025
Annual Report
v3.25.0.1
Cover - USD ($)
$ in Billions
 12 Months Ended
Dec. 31, 2024
Feb. 14, 2025
Jun. 28, 2024
Cover [Abstract]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2024    
Current Fiscal Year End Date --12-31    
Document Transition Report false    
Entity File Number 001-03551    
Entity Registrant Name EQT CORPORATION    
Entity Incorporation, State or Country Code PA    
Entity Tax Identification Number 25-0464690    
Entity Address, Address Line One 625 Liberty Avenue    
Entity Address, Address Line Two Suite 1700    
Entity Address, City or Town Pittsburgh    
Entity Address, State or Province PA    
Entity Address, Postal Zip Code 15222    
City Area Code 412    
Local Phone Number 553-5700    
Title of 12(b) Security Common Stock, no par value    
Trading Symbol EQT    
Security Exchange Name NYSE    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Document Financial Statement Error Correction [Flag] false    
Entity Shell Company false    
Entity Public Float     $ 16.2
Entity Common Stock, Shares Outstanding   597,441,000  
Documents Incorporated by Reference
EQT Corporation's definitive proxy statement relating to its 2025 annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the end of EQT Corporation's fiscal year ended December 31, 2024 and is incorporated by reference into Part III of this Annual Report on Form 10-K to the extent described therein.
    
Entity Central Index Key 0000033213    
Document Fiscal Year Focus 2024    
Document Fiscal Period Focus FY    
Amendment Flag false    
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Audit Information
 12 Months Ended
Dec. 31, 2024
Auditor [Abstract]  
Auditor Firm ID 42
Auditor Name Ernst & Young LLP
Auditor Location Pittsburgh, Pennsylvania
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STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Operating revenues:      
Gain (loss) on derivatives $ 51,117 $ 1,838,941 $ (4,642,932)
Total operating revenues 5,273,309 6,908,923 7,497,689
Operating expenses:      
Transportation and processing 1,915,616 2,157,260 2,116,976
Production 377,007 239,001 298,388
Operating and maintenance 110,393 15,699 2,597
Exploration 2,735 3,330 3,438
Selling, general and administrative 336,724 236,171 252,645
Depreciation, depletion and amortization 2,162,350 1,732,142 1,665,962
(Gain) loss on sale/exchange of long-lived assets (764,044) 17,445 (8,446)
Impairment and expiration of leases 97,368 109,421 176,606
Impairment of contract asset 0 0 214,195
Other operating expenses 349,864 84,043 57,331
Total operating expenses 4,588,013 4,594,512 4,779,692
Operating income 685,296 2,314,411 2,717,997
(Income) loss from investments (76,039) (7,596) 4,931
Other income (25,983) (1,231) (11,280)
Loss on debt extinguishment 68,299 80 140,029
Interest expense, net 454,825 219,660 249,655
Income before income taxes 264,194 2,103,498 2,334,662
Income tax expense 22,079 368,954 553,720
Net income 242,115 1,734,544 1,780,942
Less: Net income (loss) attributable to noncontrolling interests 11,538 (688) 9,977
Net income attributable to EQT Corporation $ 230,577 $ 1,735,232 $ 1,770,965
Income per share of common stock attributable to EQT Corporation:      
Weighted average common stock outstanding - Basic (in shares) 509,597 380,902 370,048
Net income attributable to EQT Corporation - Basic (in dollars per share) $ 0.45 $ 4.56 $ 4.79
Weighted average common stock outstanding - Diluted (in shares) 514,593 413,224 406,495
Net income attributable to EQT Corporation - Diluted (in dollars per share) $ 0.45 $ 4.22 $ 4.38
Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil $ 4,934,366 $ 5,044,768 $ 12,114,168
Pipeline, net marketing services and other      
Operating revenues:      
Pipeline, net marketing services and other $ 287,826 $ 25,214 $ 26,453
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STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Statement of Comprehensive Income [Abstract]      
Net income $ 242,115 $ 1,734,544 $ 1,780,942
Other comprehensive income, net of tax:      
Other postretirement benefits liability adjustment, net of tax: $252, $59 and $488 363 310 1,617
Comprehensive income 242,478 1,734,854 1,782,559
Less: Comprehensive income (loss) attributable to noncontrolling interests 11,538 (688) 9,977
Comprehensive income attributable to EQT Corporation $ 230,940 $ 1,735,542 $ 1,772,582
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STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Statement of Comprehensive Income [Abstract]      
Other post-retirement benefits liability adjustment, tax expense $ 252 $ 59 $ 488
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CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Current assets:    
Cash and cash equivalents $ 202,093 $ 80,977
Accounts receivable (less allowance for credit losses: $12,529 and $663) 1,132,608 823,695
Derivative instruments, at fair value 143,581 978,634
Income tax receivable 97,378 91,414
Prepaid expenses and other 139,019 38,255
Total current assets 1,714,679 2,012,975
Property, plant and equipment 44,505,504 33,817,169
Less: Accumulated depreciation and depletion 12,757,686 10,866,999
Net property, plant and equipment 31,747,818 22,950,170
Investments in unconsolidated entities 3,617,397 92,666
Net intangible assets 215,257 22,595
Goodwill 2,079,481 0
Other assets 455,623 206,692
Total assets 39,830,255 25,285,098
Current liabilities:    
Current portion of debt 320,800 292,432
Accounts payable 1,177,656 1,272,522
Derivative instruments, at fair value 446,519 186,363
Accrued interest 167,157 80,520
Other current liabilities 349,417 205,003
Total current liabilities 2,461,549 2,036,840
Revolving credit facility borrowings 150,000 0
Term Loan Facility borrowings 0 1,244,265
Senior notes 8,853,377 4,176,180
Note payable to EQM Midstream Partners, LP 0 82,236
Deferred income taxes 2,851,103 1,904,821
Other liabilities and credits 1,236,090 1,059,939
Total liabilities 15,552,119 10,504,281
Equity:    
Common stock, no par value, shares authorized: 1,280,000 and 640,000, shares issued: 596,870 and 419,896 18,014,711 12,093,986
Retained earnings 2,585,238 2,681,898
Accumulated other comprehensive loss (2,321) (2,684)
Total common shareholders' equity 20,597,628 14,773,200
Noncontrolling interest in consolidated subsidiaries 3,680,508 7,617
Total equity 24,278,136 14,780,817
Total liabilities and equity $ 39,830,255 $ 25,285,098
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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Statement of Financial Position [Abstract]    
Allowance for credit loss $ 12,529 $ 663
Common stock, par value (in dollars per share) $ 0 $ 0
Common stock, authorized (in shares) 1,280,000,000 640,000,000
Common stock, issued (in shares) 596,870,000 419,896,000
v3.25.0.1
STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Cash flows from operating activities:      
Net income $ 242,115 $ 1,734,544 $ 1,780,942
Adjustments to reconcile net income to net cash provided by operating activities:      
Deferred income tax expense 14,732 384,666 534,612
Depreciation, depletion and amortization 2,162,350 1,732,142 1,665,962
(Gain) loss on sale/exchange of long-lived assets (764,044) 17,445 (8,446)
Impairments 97,368 109,421 390,801
(Income) loss from investments (76,039) (7,596) 4,931
Loss on debt extinguishment 68,299 80 140,029
Share-based compensation expense 158,344 49,834 45,201
Distributions from equity method investments 66,200 18,693 50,220
Other 15,069 16,943 32,645
(Gain) loss on derivatives (51,117) (1,838,941) 4,642,932
Net cash settlements received (paid) on derivatives 1,217,895 900,650 (5,927,698)
Net premiums (paid) received on derivatives (42,394) (322,663) 14,200
Changes in other assets and liabilities:      
Accounts receivable (220,446) 867,679 (168,978)
Accounts payable 16,512 (406,113) 181,459
Other current assets (85,256) 93,787 48,576
Other items, net 7,385 (171,721) 38,172
Net cash provided by operating activities 2,826,973 3,178,850 3,465,560
Cash flows from investing activities:      
Capital expenditures (2,253,709) (2,019,037) (1,400,443)
Cash paid for acquisitions, net of cash acquired (874,265) (2,271,881) (205,347)
Proceeds from sale/exchange of assets 1,696,121 4,200 8,572
Proceeds from sale of investment shares 0 0 189,249
Capital contributions to equity method investments (148,049) (12,092) (1,394)
Other investing activities (80) (14,845) (12,390)
Net cash used in investing activities (1,579,982) (4,313,655) (1,421,753)
Cash flows from financing activities:      
Proceeds from revolving credit facility borrowings 6,887,000 1,007,000 10,242,000
Repayment of revolving credit facility borrowings (7,451,200) (1,007,000) (10,242,000)
Proceeds from issuance of debt 750,000 1,250,000 1,000,000
Proceeds from net settlement of Capped Call Transactions (Note 10) 93,290 0 0
Debt issuance costs (18,854) (5,336) (26,506)
Repayment and retirement of debt (4,313,867) (1,015,836) (917,039)
(Premiums paid) discounts received on debt extinguishment (52,432) 5,178 (135,308)
Dividends paid (326,581) (228,339) (203,629)
Repurchase and retirement of common stock 0 (201,029) (409,485)
Net proceeds from the sale of units of the Midstream Joint Venture (Note 8) 3,410,392 0 0
Net (distribution to) contribution from noncontrolling interest (1,640) (7,322) 3,408
Cash paid for taxes to net settle share-based incentive awards (102,872) (41,780) (24,773)
Other financing activities 889 1,602 14,206
Net cash used in financing activities (1,125,875) (242,862) (699,126)
Net change in cash and cash equivalents 121,116 (1,377,667) 1,344,681
Cash and cash equivalents at beginning of year 80,977 1,458,644 113,963
Cash and cash equivalents at end of year $ 202,093 $ 80,977 $ 1,458,644
v3.25.0.1
STATEMENTS OF CONSOLIDATED EQUITY - USD ($)
shares in Thousands, $ in Thousands
Total
Common Stock
Treasury Stock
(Accumulated Deficit) Retained Earnings
Accumulated Other Comprehensive Loss
 [1]
Noncontrolling Interest in Consolidated Subsidiaries
Beginning Balance (in shares) at Dec. 31, 2021   376,399        
Beginning Balance at Dec. 31, 2021 $ 9,970,999 $ 10,071,820 $ (18,046) $ (94,400) $ (4,611) $ 16,236
Comprehensive income, net of tax:            
Net income (loss) 1,780,942     1,770,965   9,977
Other postretirement benefits liability adjustment, net of tax 1,617       1,617  
Dividends (203,629)     (203,629)    
Share-based compensation plans (in shares)   2,100        
Share-based compensation plans 41,717 $ 23,671 18,046      
Convertible Notes settlements (in shares)   4        
Convertible Notes settlements 63 $ 63        
Repurchase and retirement of common stock (in shares)   (13,140)        
Repurchase and retirement of common stock (393,022) $ (203,664)   (189,358)    
Distribution to noncontrolling interest (11,592)         (11,592)
Contribution from noncontrolling interest (15,000)         (15,000)
Other (11,233)         (11,233)
Ending Balance (in shares) at Dec. 31, 2022   365,363        
Ending Balance at Dec. 31, 2022 11,213,328 $ 9,891,890 0 1,283,578 (2,994) 40,854
Comprehensive income, net of tax:            
Net income (loss) 1,734,544     1,735,232   (688)
Other postretirement benefits liability adjustment, net of tax 310       310  
Dividends (228,339)     (228,339)    
Share-based compensation plans (in shares)   2,274        
Share-based compensation plans 18,180 $ 18,180        
Convertible Notes settlements (in shares)   8,565        
Convertible Notes settlements 122,830 $ 122,830        
Repurchase and retirement of common stock (in shares)   (5,906)        
Repurchase and retirement of common stock (201,029) $ (91,545)   (109,484)    
Acquisitions and Merger (in shares)   49,600        
Acquisition and Merger 2,152,631 $ 2,152,631        
Distribution to noncontrolling interest (11,072)         (11,072)
Contribution from noncontrolling interest (3,750)         (3,750)
Dissolution of consolidated variable interest entity (25,227)         (25,227)
Other 911     (911)    
Ending Balance (in shares) at Dec. 31, 2023   419,896        
Ending Balance at Dec. 31, 2023 14,780,817 $ 12,093,986 0 2,681,898 (2,684) 7,617
Comprehensive income, net of tax:            
Net income (loss) 242,115     230,577   11,538
Other postretirement benefits liability adjustment, net of tax 363       363  
Dividends (327,237)     (327,237)    
Share-based compensation plans (in shares)   4,554        
Share-based compensation plans 70,688 $ 70,688        
Convertible Notes settlements (in shares)   19,992        
Convertible Notes settlements 285,608 $ 285,608        
Net settlement of Capped Call Transactions 93,290 $ 93,290        
Acquisitions and Merger (in shares)   152,428        
Acquisition and Merger 5,711,601 $ 5,548,608       162,993
Change in ownership of consolidated subsidiary, net (Note 8) 3,422,531 $ (77,469)       3,500,000
Distribution to noncontrolling interest (1,640)         (1,640)
Ending Balance (in shares) at Dec. 31, 2024   596,870        
Ending Balance at Dec. 31, 2024 $ 24,278,136 $ 18,014,711 $ 0 $ 2,585,238 $ (2,321) $ 3,680,508
[1] Amounts included in accumulated other comprehensive loss are related to other postretirement benefits liability adjustments, net of tax, which are attributable to net actuarial losses and net prior service costs.
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STATEMENTS OF CONSOLIDATED EQUITY (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Statement of Stockholders' Equity [Abstract]      
Other postretirement benefits liability adjustment, tax $ 252 $ 59 $ 488
Dividends (in dollars per share) $ 0.63 $ 0.61 $ 0.55
Common stock, authorized shares (in shares) 1,280,000,000 640,000,000 640,000,000
Preferred stock, authorized shares (in shares) 3,000,000 3,000,000 3,000,000
Preferred shares, shares outstanding (in shares) 0 0 0
Preferred stock, shares issued (in shares) 0 0 0
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Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies Summary of Significant Accounting Policies
 
Nature of Operations. EQT Corporation is an integrated natural gas company with production, gathering and transmission operations focused in the Appalachian Basin.

In this Annual Report on Form 10-K, references to "EQT" refer to EQT Corporation and references to the "Company" refer collectively to EQT Corporation and its consolidated subsidiaries, collectively, in each case unless otherwise noted or indicated.

Principles of Consolidation and Noncontrolling Interests. The Consolidated Financial Statements include the accounts of EQT and all subsidiaries, ventures and partnerships in which EQT directly or indirectly holds a controlling interest and variable interest entities for which EQT is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation. The Company records noncontrolling interest in its Consolidated Financial Statements for any non-wholly-owned consolidated subsidiary.

Upon the completion of the Midstream Joint Venture Transaction (defined in Note 8) and as of December 31, 2024, the Company consolidates its controlling interest in the Midstream Joint Venture (defined in Note 8) under the voting interest entity model. See Note 8 for discussion of the formation of the Midstream Joint Venture, the completion of the Midstream Joint Venture Transaction and the method of allocation used in accounting for the portion of Midstream Joint Venture that is not owned by the Company.

In addition, upon the completion of the Equitrans Midstream Merger (defined in Note 6) and as of December 31, 2024, the Company consolidates its 60% interest in Eureka Midstream Holdings, LLC (Eureka Midstream Holdings), a joint venture that owns a gathering header pipeline system that is operated by a subsidiary of EQT, under the voting interest entity model. See Note 10 for discussion of the revolving credit facility of Eureka Midstream, LLC (Eureka), a wholly-owned subsidiary of Eureka Midstream Holdings.

In 2020, the Company entered into a partnership with a third-party investor (the Investor) to form a joint venture, The Mineral Company LLC, for the purpose of purchasing certain mineral rights in the Appalachian Basin. During 2023, The Mineral Company LLC's assets were distributed pro rata to the Company and the Investor, and The Mineral Company LLC was dissolved. Prior to The Mineral Company LLC's dissolution, the Company consolidated The Mineral Company LLC as management had determined that The Mineral Company LLC was a variable interest entity, and the Company was the primary beneficiary of The Mineral Company LLC.

Prior to the NEPA Gathering System Acquisition (defined in Note 6) and the First NEPA Non-Operated Asset Divestiture (defined in Note 7), the Company recorded in the Consolidated Financial Statements its pro rata share of revenues, expenses, assets and liabilities of the NEPA Gathering System (defined in Note 6). Following the completion of the First NEPA Non-Operated Asset Divestiture, the Company owns 100% of the NEPA Gathering System.

Segments. The Company has three reportable segments reflective of its three lines of business consisting of Production, Gathering and Transmission. See Note 2.

Reclassification. Certain previously reported amounts have been reclassified to conform to the current year presentation. In addition, as discussed further in Note 2, certain prior period amounts have been recast to reflect the Company's change in reportable segments from one reportable segment to three reportable segments consisting of Production, Gathering and Transmission.

Use of Estimates. The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported herein. Actual results could differ from those estimates.

Cash and Cash Equivalents. The Company considers all highly-liquid investments with an original maturity of three months or less when purchased to be cash equivalents and accounts for such investments at cost. Interest earned on cash equivalents is included as a reduction of interest expense, net.
Accounts Receivable, Net of Allowance for Credit Losses. The Company's accounts receivable relates primarily to the sales of natural gas, natural gas liquids (NGLs) and oil and amounts due from joint interest partners. See Note 3 for a discussion of amounts due from contracts with customers. Reserves for uncollectible accounts are recorded in selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required to assess the ultimate realization of the Company's accounts receivable. Reserves are based on historical experience, current and expected economic trends and specific information about customer accounts, such as the customer's creditworthiness.

Derivative Instruments. See Note 4 for a discussion of the Company's derivative instruments and Note 5 for a description of the fair value hierarchy and a discussion of the Company's fair value measurements.

Prepaid Expenses and Other. The following table summarizes the Company's prepaid expenses and other current assets.
 December 31,
 20242023
 (Thousands)
Margin requirements with counterparties (see Note 4)
$86,975 $13,017 
Prepaid expenses and other current assets52,044 25,238 
Total prepaid expenses and other$139,019 $38,255 

Property, Plant and Equipment. The following table summarizes the Company's property, plant and equipment.
 December 31,
 20242023
 (Thousands)
Oil and gas producing properties$33,549,913 $32,510,595 
Less: Accumulated depletion12,489,317 10,734,099 
Net oil and gas producing properties21,060,596 21,776,496 
Other production assets, at cost less accumulated depreciation20,434 21,679 
Net production assets21,081,030 21,798,175 
Gathering assets8,067,556 1,153,049 
Less: Accumulated depreciation131,546 41,793 
Net gathering assets7,936,010 1,111,256 
Transmission and storage assets2,667,352 — 
Less: Accumulated depreciation30,027 — 
Net transmission and storage assets2,637,325 — 
Other property, plant and equipment, at cost less accumulated depreciation93,453 40,739 
Net property, plant and equipment$31,747,818 $22,950,170 

The Company uses the successful efforts method of accounting for gas, NGLs and oil producing activities. Under this method, the cost of productive wells and related equipment, development dry holes and productive acreage, including productive mineral interests, are capitalized and depleted using the unit-of-production method. These costs include salaries, benefits and other internal costs directly attributable to production activities. In 2024, 2023 and 2022, the Company capitalized internal costs of approximately $69 million, $57 million and $48 million, respectively, to its oil and gas producing properties. In addition, in 2024, 2023 and 2022, the Company capitalized interest expense related to well development of approximately $54 million, $41 million and $28 million, respectively. Depletion expense is calculated based on actual produced sales volume multiplied by the applicable depletion rate per unit. Depletion rates for leases and wells are each calculated by dividing net capitalized costs by the number of units expected to be produced over the life of the reserves separately. Costs for exploratory dry holes, exploratory geological and geophysical activities and delay rentals as well as other property carrying costs are charged to exploration expense. The Company's producing oil and gas properties had an overall average depletion rate of $0.90, $0.84 and $0.85 per Mcfe for the years ended December 31, 2024, 2023 and 2022, respectively.
There were no exploratory wells drilled during 2024, 2023 and 2022, and there were no capitalized exploratory well costs for the years ended December 31, 2024, 2023 and 2022.

The Company's gathering, transmission and storage property, plant and equipment is carried at cost. Maintenance projects that do not increase the overall life of the related assets are expensed as incurred. Expenditures that extend the useful life of the asset are capitalized. In 2024, the Company capitalized internal costs of approximately $25 million and $4 million to its gathering assets and transmission and storage assets, respectively. The Company's gathering, transmission and storage property, plant and equipment are depreciated using composite rates on a straight-line basis over the estimated useful life of the asset. The average depreciation rate for the year ended December 31, 2024 was 3.1%. Depreciation rates for the Company's regulated property, plant and equipment are reviewed when the Company files a change in transmission and storage rates with the FERC.

Impairment of Property, Plant and Equipment

Impairment of Proved Oil and Gas Properties. The carrying values of the Company's proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the Company's oil and gas properties has occurred, the Company compares the estimated expected undiscounted future cash flows to the carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by the Company for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted for basis differentials, future operating costs and inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates. There were no indicators of impairment to the Company's material asset groups identified during 2024, 2023 and 2022.

Impairment and Expiration of Leases. Capitalized costs of unproved oil and gas properties are evaluated for recoverability on a prospective basis at least annually. Indicators of potential impairment include changes due to economic factors, potential shifts in business strategy and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. The Company recognizes impairment if the Company does not have the intent to drill on the leased property prior to expiration of the lease or does not have the intent and ability to extend, renew, trade or sell the lease prior to expiration. For the years ended December 31, 2024, 2023 and 2022, the Company recorded $97.4 million, $109.4 million and $176.6 million, respectively, for impairment and expiration of leases. The Company's unproved properties had a net book value of approximately $1,563 million and $2,039 million as of December 31, 2024 and 2023, respectively.

Impairment of Other Property, Plant and Equipment. The Company evaluates its other property, plant and equipment for impairment when events or changes in circumstance indicate that the carrying value of such assets may not be recoverable. There were no indicators of impairment to the Company's asset groups identified during 2024, 2023 and 2022.

Impairment of Contract Asset. In 2020, the Company recorded a contract asset representing rate relief that the Company was entitled to pursuant to a consolidated gas gathering and compression agreement (the Consolidated GGA) entered into between the Company and an affiliate of EQM Midstream Partners, LP (EQM), which became an indirect wholly-owned subsidiary of EQT upon the closing of the Equitrans Midstream Merger. During 2022, the Company identified indicators that the carrying amount of its contract asset might not be fully recoverable, including increased uncertainty of the estimated timing of completion of the Mountain Valley Pipeline (the MVP) due to court rulings and public statements from Equitrans Midstream Corporation (Equitrans Midstream), the former parent of EQM, with respect to the completion of the MVP. As a result of the Company's impairment evaluation, the Company recognized impairment of the contract asset of $214 million in the Statement of Consolidated Operations for the year ended December 31, 2022, decreasing the contract asset's value to zero.

Investments in Unconsolidated Entities. See Note 11 for a discussion of the Company's investments in unconsolidated entities, which include EQT's equity method investments and investments in equity securities. The Company evaluates its investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the investment's fair value is less than its carrying amount. The recognition of an impairment loss is required if the impairment is considered other than temporary. There were no indicators of impairment to the Company's investments in unconsolidated entities identified during 2024, 2023 and 2022.
Net Intangible Assets. As part of the Equitrans Midstream Merger preliminary purchase price allocation, the Company identified intangible assets related to certain of Equitrans Midstream's transmission services contracts. See Note 6. The Company evaluates its intangible assets for impairment when indicators of impairment are present. There were no indicators of impairment to the Company's net intangible assets identified during 2024.

Goodwill. Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. Goodwill is allocated among, and evaluated for impairment at, the reporting unit level, which is defined as an operating segment or one level below an operating segment.

The Company evaluates its goodwill for impairment at least annually or more frequently if indicators of impairment exist. Goodwill is tested for impairment by assessing qualitative factors to determine whether it is more likely than not (greater than 50%) that the fair value of the reporting unit is less than the carrying amount or by performing a quantitative assessment. If the qualitative assessment indicates a possible impairment, then a quantitative impairment test is performed to determine the fair value of the reporting unit using a combination of an income and market approach. Otherwise, no further analysis is required.

Under the quantitative assessment, the evaluation of impairment involves comparing the current fair value of each reporting unit to its carrying value, including goodwill. In the event that the estimated fair value of a reporting unit is less than the carrying value, the Company would recognize an impairment loss equal to the excess of the reporting unit's carrying value over its fair value not to exceed the total amount of goodwill applicable to that reporting unit.

The Company evaluated its goodwill for impairment as of October 1, 2024 and determined there were no indicators of impairment.

Other Current Liabilities. The following table summarizes the Company's other current liabilities.
 December 31,
 20242023
 (Thousands)
Accrued taxes other than income$114,700 62,391 
Accrued incentive compensation53,138 24,542 
Current portion of long-term capacity contracts43,697 43,233 
Current portion of lease liabilities41,878 46,380 
Deferred revenue24,187 2,890 
Accrued payroll12,115 8,870 
Other accrued liabilities59,702 16,697 
Total other current liabilities$349,417 $205,003 
 
Unamortized Debt Discount and Issuance Costs. Discounts and costs incurred with the issuance of debt are amortized over the life of the debt. These amounts are presented as a reduction of debt in the Consolidated Balance Sheets. See Note 10.

Leases. See Note 14 for a discussion of the Company's leases.

Income Taxes. The Company files a consolidated U.S. federal income tax return and uses the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded for the current year and the change in deferred taxes exclusive of amounts recorded in other comprehensive loss. Any refinements to prior year taxes made in the current year due to new information are reflected as adjustments in the current period. Separate income taxes are calculated for items charged or credited directly to shareholders' equity.

EQM, Eureka Midstream Holdings and the Midstream Joint Venture are treated as partnerships for U.S. federal and applicable state income tax purposes and are not separately subject to U.S. federal or state income taxes. EQM's, Eureka Midstream Holdings' and the Midstream Joint Venture's income is included in the Company's pre-tax income; however, the Company does not record income tax expense on income attributable to noncontrolling interests in Eureka Midstream Holdings and the Midstream Joint Venture, which reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the effective tax rate in periods when the Company has consolidated pre-tax losses.
Deferred tax assets and liabilities arise from temporary differences between the financial reporting and tax bases of the Company's assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that a portion or all of the deferred tax asset will not be realized. When evaluating whether or not a valuation allowance should be established, the Company exercises judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of the deferred tax assets will not be realized. To determine whether a valuation allowance is needed, the Company considers all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income.
 
In accounting for uncertainty of a tax position taken or expected to be taken in a tax return, the Company uses a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If it is more likely than not that a tax position will be sustained, the Company measures and recognizes the tax position at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. To determine the amount of financial statement benefit recorded for uncertain tax positions, the Company considers the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense. See Note 9.

Insurance. The Company maintains insurance to cover traditional insurable risks such as general liability, workers compensation, auto liability, environmental liability, property damage, business interruption, fiduciary liability, director and officers' liability and other risks. These policies may be subject to deductible or retention amounts, coverage limitations and exclusions. The Company was previously self-insured for certain material losses related to general liability, workers compensation and environmental liability; however, the Company now maintains insurance for such losses arising on or after November 12, 2020. In addition, in conjunction with the Equitrans Midstream Merger, the Company assumed a self-insured retention reserve for certain material losses related to excess liability and environmental liability for losses arising before December 20, 2024. The Company also assumed with the Equitrans Midstream Merger a 10% co-insurance related to material losses on property insurance coverage. Prospectively, coverage is included in the Company's insurance programs that do not have high self-insured and co-insurance amounts. Reserves are recorded on an undiscounted basis using analyses of historical data and, where applicable, actuarial estimates, which represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The reserves are reviewed by the Company quarterly and, where applicable, by independent actuaries annually.

Asset Retirement Obligations. The Company accrues a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of the Company's plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to depreciation and depletion expense. The initial capitalized costs are depleted over the useful lives of the related assets.

The Company's asset retirement obligations related to the abandonment of oil and gas producing facilities include reclaiming well pads, reclaiming water impoundments, plugging wells and dismantling related structures. In addition, the Company records asset retirement obligations on its storage wells with known plugging timelines. Estimates are based on historical experience of plugging and abandoning wells and reclaiming or disposing other assets and estimated remaining lives of the wells and assets.

The Company is under no legal or contractual obligation to restore or dismantle its gathering and transmission pipeline assets upon abandonment. In addition, the Company is responsible for the operation and maintenance of its gathering and transmission assets and intends to continue such operation and maintenance so long as supply and demand for natural gas exists. As the Company expects supply and demand for natural gas to exist into the foreseeable future, the Company has not recorded asset retirement obligations for its gathering and transmission pipeline assets.
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company's asset retirement obligations included in other liabilities and credits in the Consolidated Balance Sheets.
 December 31,
 20242023
 (Thousands)
Balance at January 1$911,057 $732,803 
Accretion expense68,501 47,700 
Liabilities incurred21,587 10,515 
Liabilities settled(66,729)(33,938)
Liabilities assumed in acquisitions45,847 64,424 
Liabilities removed in divestitures(28,701)(6,480)
Change in estimates (a)52,008 96,033 
Balance at December 31$1,003,570 $911,057 

(a)During 2024, the Company recorded changes in estimates attributable primarily to increased plugging costs. During 2023, the Company recorded changes in estimates attributable primarily to inflation on estimated plugging costs.

The Company does not have assets that are legally restricted for purposes of settling its asset retirement obligations. The Company operates in several states that have implemented expanded requirements for settling asset retirement obligations. This has resulted in the Company's use of additional materials during the plugging process, which has increased the estimated cost for plugging horizontal and conventional wells.

Regulatory Accounting. As of December 31, 2024, the Company consolidates the Midstream Joint Venture, which holds Equitrans, L.P., which owns and operates the Midstream Joint Venture's wholly-owned FERC-regulated transmission and storage assets.

Through the rate-setting process, rate regulation allows recovery of costs to provide regulated services plus an allowed return on invested capital. Regulatory accounting allows deferral of costs and income as regulated assets and liabilities when it is probable that such costs and income is subject to recovery in future periods. Such deferred amounts are then recognized in Equitrans, L.P.'s Statement of Operations in the period in which the underlying costs and income are reflected in the rates charged by Equitrans, L.P. to shippers and operators. Equitrans, L.P. expects to continue to be subject to rate regulation.

The following table presents Equitrans, L.P.'s regulated operating revenues and expenses included in the Company's Consolidated Statement of Operations for the period from July 22, 2024 to December 31, 2024.
 July 22, 2024 to December 31, 2024
 (Thousands)
Operating revenues$218,569 
Operating expenses$78,908 

The following table presents Equitrans, L.P.'s regulated property, plant and equipment included in the Company's Consolidated Balance Sheet as of December 31, 2024.
 December 31, 2024
 (Thousands)
Property, plant and equipment$2,667,352 
Less: Accumulated depreciation30,027 
Net property, plant and equipment$2,637,325 
The Company includes Equitrans, L.P.'s regulated assets and liabilities in its Consolidated Balance Sheet. Equitrans, L.P.'s regulated assets are reported in other assets, and Equitrans, L.P.'s regulated liabilities are reported in other liabilities and credits. The following table summarizes Equitrans, L.P.'s regulated assets and liabilities as of December 31, 2024.
 December 31, 2024
 (Thousands)
Regulated assets:
Deferred taxes (a)$142,757 
Other recoverable costs (b)23,182 
Total regulated assets$165,939 
Regulated liabilities:
Deferred taxes (a)$8,534 
Ongoing postretirement benefits other than pension and other reimbursable costs (c)20,158 
Total regulated liabilities$28,692 

(a)The regulated asset from deferred taxes is related primarily to a historical deferred income tax position as well as taxes on the equity component of allowance for funds used during construction (AFUDC). The regulated liability from deferred taxes is related to the revaluation of a historical difference between the regulatory and tax bases of regulated property, plant and equipment. Equitrans, L.P. expects to recover the amortization of the deferred income tax positions ratably over the depreciable lives of the underlying assets. In addition, Equitrans, L.P. expects to recover the taxes on the equity component of AFUDC through future rates over the depreciable lives of the underlying long-lived assets.
(b)The regulated asset from other recoverable costs is related primarily to costs associated with Equitrans, L.P.'s asset retirement obligations, which Equitrans, L.P. expects to continue to recover over the next 9.5 years, and costs associated with a legacy postretirement benefits plan, which Equitrans, L.P. expects to continue to recover over the next 7.5 years.
(c)Equitrans, L.P. defers costs for other postretirement benefits plans, which are subject to recovery in approved rates. The related regulated liability reflects lower cumulative actuarial expenses than the amounts recovered through rates. Equitrans, L.P. expects to continue to recover costs as long as the existing recourse rates provide for recovery.

Revenue Recognition. For information on revenue recognition from contracts with customers, see Note 3. For information on gains and losses on derivative commodity instruments, see Note 4.
 
Transportation and Processing. Costs incurred to gather, process and transport gas produced by the Company to market sales points are recorded as transportation and processing costs in the Statements of Consolidated Operations. The Company markets some transportation for resale. These costs, which are not incurred to transport gas produced by the Company, are reflected as a deduction from net marketing services and other revenues.

Share-based Compensation. See Note 13 for a discussion of the Company's share-based compensation plans.

Other Operating Expenses. The following table summarizes the Company's other operating expenses.
Years Ended December 31,
202420232022
(Thousands)
Transaction costs$309,419 $56,263 $14,185 
Changes in legal and environmental reserves, including settlements16,271 9,342 $30,394 
Other24,174 18,438 12,752 
Total other operating expenses$349,864 $84,043 $57,331 

Defined Contribution Plan and Other Postretirement Benefits Plan. The Company recognized expense related to its defined contribution plan of $14.5 million, $9.0 million and $7.8 million for the years ended December 31, 2024, 2023 and 2022, respectively. In addition, the Company sponsors an other postretirement benefits plan.

Income Per Share. See Note 12 for a discussion of the Company's common stock and income per share computation.
Supplemental Cash Flow Information. The following table summarizes net cash paid for interest and income taxes and non-cash activity included in the Statements of Consolidated Cash Flows.
Years Ended December 31,
202420232022
(Thousands)
Cash paid during the year for:
Interest, net of amount capitalized$401,768 $213,141 $236,797 
Income taxes, net7,960 13,350 20,773 
Non-cash activity during the period for:
Equity issued as consideration for acquisitions (Note 6)$5,548,608 $2,152,631 $— 
Issuance of EQT common stock for Convertible Notes settlement (Note 10)285,608 122,830 63 
First NEPA Non-Operated Asset Divestiture (Note 7)
155,318 — — 
Increase in asset retirement costs and obligations73,576 106,548 54,608 
Increase in right-of-use assets and lease liabilities, net29,568 45,774 23,356 
Capitalization of non-cash equity share-based compensation10,095 6,287 5,406 
Investments in nonconsolidated entities3,428 — — 
Accrued transaction costs related to the sale of units of the Midstream Joint Venture (Note 8)1,135 — — 
Dissolution of consolidated variable interest entity— 25,227 — 

Recently Issued Accounting Standards

In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, to improve reportable segment disclosure requirements, primarily through the requirement of enhanced disclosure of significant segment expenses. In addition, this ASU enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and provides new segment disclosure requirements for entities with a single reportable segment. This ASU is effective for annual reporting periods beginning after December 15, 2023 and interim periods within annual reporting periods beginning after December 15, 2024. The Company adopted ASU 2023-07 in the fourth quarter of 2024. See Note 2 for segments disclosures.

In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures, to improve 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 annual reporting periods 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, Disaggregation of Income Statement Expenses, to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization and depletion) in commonly presented expense captions (such as cost of sales; selling, general and administrative expense; and research and development). This ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The requirements should be applied prospectively with the option for retrospective application. The Company is evaluating the impact ASU 2024-03 will have on its financial statements and related disclosures.
Subsequent Events. The Company has evaluated subsequent events through the date of the financial statement issuance.
v3.25.0.1
Financial Information by Business Segment
 12 Months Ended
Dec. 31, 2024
Segment Reporting [Abstract]  
Financial Information by Business Segment Financial Information by Business Segment
Prior to the completion of the Equitrans Midstream Merger, the Company's operations consisted of one reportable segment. Historically, the Company administered all properties as a whole rather than by discrete operating segments and measured financial performance as a single enterprise and not on an area-by-area basis.

As a result of the completion of the Equitrans Midstream Merger, the Company adjusted its internal reporting structure and the Company's chief operating decision maker, Toby Rice, President and Chief Executive Officer, changed the manner in which he measures financial performance and allocates resources to incorporate the gathering and transmission assets acquired by the Company in the Equitrans Midstream Merger. Hence, the Company's operations expanded to comprise three discrete operating segments reflective of its three lines of business consisting of Production, Gathering and Transmission.

The Company's Production segment comprises the Company's natural gas, NGLs and oil extraction, development and production business and supporting ventures, such as water operations. The Company's Gathering segment owns and operates the Company's gathering system, which has extensive overlap with the Company's Production segment operations, and processing facility. The Company's Transmission segment operates the Company's FERC-regulated, interstate transmission and storage system, which has multiple interconnect points to other interstate pipelines and local distribution companies. In addition, the Transmission segment holds the Company's investment in the MVP Joint Venture (defined in Note 11). Certain amounts, including cash and cash equivalents, debt, income taxes and other amounts related to the Company's headquarters function as well as amounts related to the Company's energy transition initiatives are managed on a consolidated basis and, as such, have not been allocated to the Company's segments and have been presented as "Other."

As a result of the Company's change in reportable segments from one reportable segment to three reportable segments, certain prior period amounts have been recast.

The accounting policies of the Company's segments are the same as those described in Note 1.

For all of the Company's segments, the chief operating decision maker uses operating income as the profitability metric to measure financial performance and allocate resources. The chief operating decision maker considers actual-to-forecast variances for operating income when allocating capital and personnel to the Company's segments and compares operating income and return on assets of each segment to assess segment performance. In addition to operating income, the chief operating decision maker reviews equity earnings recognized from, and the carrying value of the Company's investment in, the MVP Joint Venture when measuring the financial performance of, and allocating resources to, the Company's Transmission segment.

Substantially all of the Company's operating revenues and assets are generated and located in the United States.
Total segment operating income. The follow tables present the Company's profit and loss metric of operating income by segment.
Year Ended December 31, 2024
ProductionGatheringTransmissionTotal SegmentIntersegment eliminations and otherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$4,934,366 $— $— $4,934,366 $— $4,934,366 
Gain (loss) on derivatives67,880 (16,763)— 51,117 — 51,117 
Pipeline, net marketing services and other7,587 766,463 218,293 992,343 (704,517)287,826 
Total operating revenues5,009,833 749,700 218,293 5,977,826 (704,517)5,273,309 
Operating expenses (a):
Transportation and processing2,619,710 — — 2,619,710 (704,094)1,915,616 
Production377,007 — — 377,007 — 377,007 
Operating and maintenance— 89,897 20,496 110,393 — 110,393 
Exploration2,735 — — 2,735 — 2,735 
Selling, general and administrative (b)244,450 38,837 17,183 300,470 36,254 336,724 
Depreciation, depletion and amortization2,016,670 89,513 39,406 2,145,589 16,761 2,162,350 
(Gain) loss on sale/exchange of long-lived assets(764,431)(22)409 (764,044)— (764,044)
Impairment and expiration of leases97,368 — — 97,368 — 97,368 
Other operating expenses (c)12,696 — — 12,696 337,168 349,864 
Total operating expenses4,606,205 218,225 77,494 4,901,924 (313,911)4,588,013 
Operating income (loss)$403,628 $531,475 $140,799 $1,075,902 $(390,606)$685,296 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(c)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger. See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2023
ProductionGatheringTotal SegmentIntersegment eliminations and otherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$5,044,768 $— $5,044,768 $— $5,044,768 
Gain on derivatives1,838,941 — 1,838,941 — 1,838,941 
Pipeline, net marketing services and other12,649 161,395 174,044 (148,830)25,214 
Total operating revenues6,896,358 161,395 7,057,753 (148,830)6,908,923 
Operating expenses (a):
Transportation and processing2,306,090 — 2,306,090 (148,830)2,157,260 
Production239,001 — 239,001 — 239,001 
Operating and maintenance— 15,699 15,699 — 15,699 
Exploration3,330 — 3,330 — 3,330 
Selling, general and administrative (b)236,171 — 236,171 — 236,171 
Depreciation, depletion and amortization1,705,311 17,066 1,722,377 9,765 1,732,142 
Loss on sale/exchange of long-lived assets17,445 — 17,445 — 17,445 
Impairment and expiration of leases109,421 — 109,421 — 109,421 
Other operating expenses (c)9,177 — 9,177 74,866 84,043 
Total operating expenses4,625,946 32,765 4,658,711 (64,199)4,594,512 
Operating income (loss)$2,270,412 $128,630 $2,399,042 $(84,631)$2,314,411 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(c)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition (defined in Note 6). See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2022
ProductionGatheringTotal SegmentIntersegment eliminations and otherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$12,114,168 $— $12,114,168 $— $12,114,168 
Loss on derivatives(4,642,932)— (4,642,932)— (4,642,932)
Pipeline, net marketing services and other12,827 96,947 109,774 (83,321)26,453 
Total operating revenues7,484,063 96,947 7,581,010 (83,321)7,497,689 
Operating expenses (a):
Transportation and processing2,200,297 — 2,200,297 (83,321)2,116,976 
Production298,388 — 298,388 — 298,388 
Operating and maintenance— 2,597 2,597 — 2,597 
Exploration3,438 — 3,438 — 3,438 
Selling, general and administrative (b)252,645 — 252,645 — 252,645 
Depreciation, depletion and amortization1,648,808 8,035 1,656,843 9,119 1,665,962 
Gain on sale/exchange of long-lived assets(8,446)— (8,446)— (8,446)
Impairment and expiration of leases176,606 — 176,606 — 176,606 
Impairment of contract asset214,195 — 214,195 — 214,195 
Other operating expenses (c)32,605 — 32,605 24,726 57,331 
Total operating expenses4,818,536 10,632 4,829,168 (49,476)4,779,692 
Operating income (loss)$2,665,527 $86,315 $2,751,842 $(33,845)$2,717,997 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(c)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition. See Note 1 for a summary of the Company's consolidated other operating expenses.
Reconciliation of total segment operating income to income before income taxes
Years Ended December 31,
202420232022
(Thousands)
Total segment operating income$1,075,902 $2,399,042 $2,751,842 
Intersegment eliminations457 — — 
Unallocated amounts:
Other revenue(34)— — 
Corporate selling, general and administrative36,254 — — 
Corporate other depreciation and amortization16,761 9,765 9,119 
Corporate other operating expenses (a)337,168 74,866 24,726 
(Income) loss from investments (b)(76,039)(7,596)4,931 
Other income(25,983)(1,231)(11,280)
Loss on debt extinguishment68,299 80 140,029 
Interest expense, net454,825 219,660 249,655 
Income before income taxes$264,194 $2,103,498 $2,334,662 

(a)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger for the year ended December 31, 2024. Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition for both years ended December 31, 2023 and 2022. See Note 1 for a summary of the Company's consolidated other operating expenses.
(b)Income from investments for the year ended December 31, 2024 included $78.8 million of equity earnings from the Company's investment in the MVP Joint Venture, which is reported in the Company's Transmission segment.

Total segment assets. The following table presents the Company's total assets by segment. The Company's investment in the MVP Joint Venture is presented in investments in unconsolidated entities in the Consolidated Balance Sheet. The Company did not have an investment in the MVP Joint Venture or goodwill prior to completion of the Equitrans Midstream Merger.
ProductionGatheringTransmissionTotal Segment
December 31, 2024(Thousands)
Investment in the MVP Joint Venture$— $— $3,534,730 $3,534,730 
Goodwill— — 1,217,742 1,217,742 
Other segment assets22,546,098 8,295,625 2,919,532 33,761,255 
Total assets$22,546,098 $8,295,625 $7,672,004 $38,513,727 
December 31, 2023
Total assets$23,803,913 $1,215,627 $— $25,019,540 
December 31, 2022
Total assets$20,469,506 $417,117 $— $20,886,623 
Reconciliation of total segment assets to total assets
December 31,
202420232022
(Thousands)
Total segment assets$38,513,727 $25,019,540 $20,886,623 
Intersegment eliminations(318,835)(47,471)(19,288)
Unallocated amounts:
Cash and cash equivalents202,093 80,977 1,458,644 
Income tax receivable97,378 91,414 — 
Other property, plant and equipment, at cost less accumulated depreciation93,453 40,739 32,594 
Goodwill (a)861,739 — — 
Regulated asset from deferred taxes
142,757 — — 
Other237,943 99,899 311,353 
Total assets$39,830,255 $25,285,098 $22,669,926 

(a)Represents goodwill attributable to additional deferred tax liabilities that arose from the differences between the fair value and tax bases of the Equitrans Midstream Merger preliminary purchase price allocation that carried over from Equitrans Midstream to the Company. See Note 6.

Total segment capital expenditures. The following table presents the Company's capital expenditures by segment.
Years Ended December 31,
202420232022
(Thousands)
Production$2,003,635 $1,878,417 $1,427,995 
Gathering202,264 31,701 6,155 
Transmission31,446 — — 
Total segment capital expenditures2,237,345 1,910,118 1,434,150 
Other corporate items28,603 15,125 5,962 
Total capital expenditures$2,265,948 $1,925,243 $1,440,112 

Consolidated GGA

Pursuant to the terms of the Consolidated GGA, EQM's affiliate, which is party thereto (which is included, post-Equitrans Midstream Merger, in the Company's Gathering segment) (the EQM Affiliate) agreed to provide gas gathering services to a subsidiary of EQT (which is included in the Company's Production segment) (the EQT Party) and the EQT Party committed to an initial annual minimum volume commitment (MVC) of 3.0 Bcf per day and an acreage dedication in Pennsylvania and West Virginia. The Consolidated GGA is effective through December 31, 2035 and will renew annually thereafter unless terminated by the parties thereto.

The Consolidated GGA provided for cash bonus payments (the Henry Hub Cash Bonus) conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds to be payable by the EQT Party to the EQM Affiliate during each quarter beginning with the first day of the quarter in which the MVP In-Service Date (as defined in the Consolidated GGA) occurs and ending on the earlier of 36 months thereafter or December 31, 2024. Upon commencement of long-term firm capacity obligations, the MVP In-Service Date occurred on July 1, 2024.

The Company's Production and Gathering segments recorded their respective derivative liability and asset and any gain or loss related to the Henry Hub Cash Bonus. During the fourth quarter of 2024, the EQT Party paid $4.2 million to the EQM Affiliate, and, as of December 31, 2024, the derivative related to the Henry Hub Cash Bonus was settled. As of December 31, 2023, the derivative related to the Henry Hub Cash Bonus had a fair value of approximately $48 million. The fair value of the derivative asset and liability related to the Henry Hub Cash Bonus was based on significant inputs that are interpolated from observable market data and, as such, was a Level 2 fair value measurement. See Note 5 for a description of the fair value hierarchy.
v3.25.0.1
Revenue from Contracts with Customers
 12 Months Ended
Dec. 31, 2024
Revenue from Contract with Customer [Abstract]  
Revenue from Contracts with Customers Revenue from Contracts with Customers
Sales of natural gas, NGLs and oil. Under the Company's natural gas, NGLs and oil sales contracts, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. These contracts typically require payment within 25 days of the end of the calendar month in which the commodity is delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company's efforts to satisfy the performance obligations. Other contracts, such as fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices, contain fixed consideration. The Company allocates the fixed consideration to each performance obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price.

Based on management's judgment, the performance obligations for the sale of natural gas, NGLs and oil are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas, NGLs or oil is delivered to the designated sales point.

The sales of natural gas, NGLs and oil presented in the Statements of Consolidated Operations represent the Company's share of revenues net of royalties and exclude revenue interests owned by others. When selling natural gas, NGLs and oil on behalf of royalty or working interest owners, the Company acts as an agent and, thus, reports the revenue on a net basis.

Pipeline revenue. The Company provides gathering, transmission and storage services under firm and interruptible service contracts.

Firm service contracts generally require the customer to pay a firm reservation fee, which is a fixed, monthly charge to reserve an agreed upon amount of pipeline or storage capacity regardless of whether the customer uses the capacity. Under its firm service contracts, the Company has a stand-ready obligation to provide the firm service over the life of the contract. The performance obligation for revenue from firm reservation fees is satisfied over time as the pipeline capacity is made available to the customer. As such, the Company recognizes firm reservation fee revenue evenly over the contract period using a time-elapsed output method to measure progress.

Volumetric-based fees, which are charges based on the volume of gas gathered, transported or stored, can also be charged under firm service contracts for each firm contracted volume gathered, transported or stored as well as for volumes gathered, transported or stored in excess of the firm contracted volume so long as capacity exists.

Interruptible service contracts require the customer to pay volumetric-based fees and generally do not guarantee access to the pipeline or storage facility.

The performance obligation for revenue from volumetric-based fees is generally satisfied upon the Company's monthly invoicing to the customer for volumes gathered, transported or stored during the month. The amount invoiced generally corresponds directly to the value of the Company's performance to date as the customer obtains value as each volume is gathered, transported or stored. Gathering service contracts are invoiced on a one-month lag, with payment typically due within 21 days of the invoice date. Revenue for gathering services provided but not yet invoiced is estimated based on contract data, preliminary throughput and allocation measurements on a monthly basis. Transmission and storage service contracts are invoiced at the end of each calendar month, with payment typically due within 10 days of the invoice date.

For both firm reservation and volumetric-based fee revenues, the Company allocates the transaction price to each performance obligation based on the estimated relative standalone selling price. Any excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units-of-production or straight-line methodology as these methods align with the consumption of services provided to the customer. The units-of-production methodology requires the use of judgment to estimate future production volumes.

Certain of the Company's gathering service agreements are structured with MVCs, which specify minimum quantities that the customer will be charged regardless of whether such quantities are gathered. Revenue is recognized for MVCs when the performance obligation has been met, which is the earlier of when the gas is gathered or when the likelihood that the customer will be able to meet its MVC is remote. If a customer fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering services within the specified period), the customer is obligated to pay a contractually-determined fee based on the shortfall between actual volume gathered and the MVC.
Disaggregated revenue information. The table below provides disaggregated information on the Company's revenues. Certain other revenue contracts are outside the scope of ASU 2014-09, Revenue from Contracts with Customers. These contracts are reported in pipeline, net marketing services and other revenues in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
Years Ended December 31,
202420232022
(Thousands)
Revenues from contracts with customers:
Production:
Sales of natural gas, NGLs and oil
Natural gas sales$4,224,882 $4,520,817 $11,448,293 
NGLs sales615,933 427,760 586,715 
Oil sales93,551 96,191 79,160 
Sales of natural gas, NGLs and oil4,934,366 5,044,768 12,114,168 
Gathering:
Pipeline revenue
Firm reservation fee revenue (a)313,987 — — 
Volumetric-based fee revenue (b)452,476 161,395 96,947 
Total766,463 161,395 96,947 
Transmission:
Pipeline revenues
Firm reservation fee revenue183,088 — — 
Volumetric-based fee revenue34,968 — — 
Total218,056 — — 
Intersegment eliminations and other(704,517)(148,830)(83,321)
Total revenues from contracts with customers (c)5,214,368 5,057,333 12,127,794 
Other sources of revenue:
Gain (loss) on derivatives51,117 1,838,941 (4,642,932)
Net marketing services and other revenues7,824 12,649 12,827 
Total other sources of revenue58,941 1,851,590 (4,630,105)
Total operating revenues$5,273,309 $6,908,923 $7,497,689 

(a)Firm reservation fee revenue for the year ended December 31, 2024 included unbilled revenues supported by MVCs of $4.2 million.
(b)Volumetric-based fee revenue for the year ended December 31, 2024 included unbilled revenues supported by MVCs of $4.5 million.
(c)For contracts with customers where the Company's performance obligations had been satisfied and an unconditional right to consideration existed as of the balance sheet date, the Company recorded amounts due from contracts with customers of $939.9 million and $584.8 million in accounts receivable in the Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively.
Summary of remaining performance obligations. The following table summarizes the transaction price allocated to the Company's remaining obligations on all contracts with fixed consideration as of December 31, 2024. The table excludes contracts that qualified for the exception to the relative standalone selling price method as of December 31, 2024.
20252026202720282029ThereafterTotal
(Thousands)
Gathering firm reservation fees:
Third-party contracts$101,671 $92,311 $85,651 $85,651 $85,651 $371,792 $822,727 
Affiliate contracts91,918 101,728 101,393 97,701 97,701 1,482,452 1,972,893 
Total Gathering firm reservation fees193,589 194,039 187,044 183,352 183,352 1,854,244 2,795,620 
Gathering revenues supported by MVCs:
Third-party contracts82,396 89,217 80,904 77,153 65,788 185,423 580,881 
Affiliate contracts372,446 397,966 410,621 411,740 410,621 2,042,451 4,045,845 
Total Gathering revenues supported by MVCs454,842 487,183 491,525 488,893 476,409 2,227,874 4,626,726 
Transmission firm reservation fees:
Third-party contracts176,189 174,435 171,768 169,410 166,324 814,742 1,672,868 
Affiliate contracts241,507 261,045 261,045 260,715 260,383 1,964,638 3,249,333 
Total Transmission firm reservation fees417,696 435,480 432,813 430,125 426,707 2,779,380 4,922,201 
Total$1,066,127 $1,116,702 $1,111,382 $1,102,370 $1,086,468 $6,861,498 $12,344,547 

As of December 31, 2024, the Company had no remaining performance obligations on its natural gas sales contracts with fixed consideration.

In addition, based on total projected contractual revenues, the Company's firm gathering third-party contracts and firm transmission and storage third-party contracts had a weighted average remaining term of approximately 10 years and 11 years, respectively, as of December 31, 2024. Based on total projected contractual revenues, the Company's firm gathering affiliate contracts and firm transmission and storage affiliate contracts had a weighted average remaining term of approximately 14 years and 13 years, respectively, as of December 31, 2024.
v3.25.0.1
Derivative Instruments
 12 Months Ended
Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments Derivative Instruments
 
The Company's primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the Company's operating results. The Company uses derivative commodity instruments to hedge its cash flows from sales of produced natural gas and NGLs. The overall objective of the Company's hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.

The derivative commodity instruments used by the Company are primarily swap, collar and option agreements. These agreements may result in payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. The Company uses these agreements to hedge its NYMEX and basis exposure. The Company may also use other contractual agreements when executing its commodity hedging strategy. The Company typically enters into over the counter (OTC) derivative commodity instruments with financial institutions, and the creditworthiness of all counterparties is regularly monitored.

The Company does not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of the Company's derivative instruments are recognized in operating revenues in gain (loss) on derivatives in the Statements of Consolidated Operations. The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
Contracts that result in physical delivery of a commodity expected to be sold by the Company in the normal course of business are generally designated as normal sales and are exempt from derivative accounting. Contracts that result in the physical receipt or delivery of a commodity but are not designated or do not meet all of the criteria to qualify for the normal purchase and normal sale scope exception are subject to derivative accounting.

The Company's OTC derivative instruments generally require settlement in cash. The Company also enters into exchange traded derivative commodity instruments that are generally settled with offsetting positions. Settlements of derivative commodity instruments are reported as a component of cash flows from operating activities in the Statements of Consolidated Cash Flows.

With respect to the derivative commodity instruments held by the Company, the Company hedged portions of its expected sales of production and portions of its basis exposure covering approximately 2,189 billion cubic feet (Bcf) of natural gas and 2,562 thousand barrels (Mbbl) of NGLs as of December 31, 2024 and 2,045 Bcf of natural gas and 1,049 Mbbl of NGLs as of December 31, 2023. The open positions at both December 31, 2024 and 2023 had maturities extending through December 2027.

Certain of the Company's OTC derivative instrument contracts provide that, if EQT's credit rating assigned by Moody's Investors Service, Inc. (Moody's), S&P Global Ratings (S&P) or Fitch Ratings Service (Fitch) is below the agreed-upon credit rating threshold (typically, below investment grade) and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the counterparty to such contract can require the Company to deposit collateral. Similarly, if such counterparty's credit rating assigned by Moody's, S&P or Fitch is below the agreed-upon credit rating threshold and if the associated derivative liability exceeds the agreed-upon dollar threshold for such credit rating, the Company can require the counterparty to deposit collateral with the Company. Such collateral can be up to 100% of the derivative liability. Investment grade refers to the quality of a company's credit as assessed by one or more credit rating agencies. To be considered investment grade, a company must be rated "Baa3" or higher by Moody's, "BBB–" or higher by S&P and "BBB–" or higher by Fitch. Anything below these ratings is considered non-investment grade. As of December 31, 2024, EQT's senior notes were rated "Baa3" by Moody's, "BBB–" by S&P and "BBB–" by Fitch.

When the net fair value of any of the Company's OTC derivative instrument contracts represents a liability to the Company that is in excess of the agreed-upon dollar threshold for the Company's then-applicable credit rating, the counterparty has the right to require the Company to remit funds as a margin deposit in an amount equal to the portion of the derivative liability that is in excess of the dollar threshold amount. The Company records these deposits as a current asset in the Consolidated Balance Sheets. As of December 31, 2024 and 2023, the aggregate fair value of the Company's OTC derivative instruments with credit rating risk-related contingent features in a net liability position was $61.9 million and $6.4 million, respectively, for which no deposits were required or recorded in the Consolidated Balance Sheets.

When the net fair value of any of the Company's OTC derivative instrument contracts represents an asset to the Company that is in excess of the agreed-upon dollar threshold for the counterparty's then-applicable credit rating, the Company has the right to require the counterparty to remit funds as a margin deposit in an amount equal to the portion of the derivative asset that is in excess of the dollar threshold amount. The Company records these deposits as a current liability in the Consolidated Balance Sheets. As of both December 31, 2024 and 2023, there were no such deposits recorded in the Consolidated Balance Sheets.

When the Company enters into exchange traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good faith deposits to guard against the risks associated with changing market conditions. The Company is required to make such deposits based on an established initial margin requirement and the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Consolidated Balance Sheets. When the fair value of such contracts is in a net asset position, the broker may remit funds to the Company. The Company records these deposits as a current liability in the Consolidated Balance Sheets. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the contract. The margin requirements are subject to change at the exchanges' discretion. As of December 31, 2024 and 2023, there were $87.0 million and $13.0 million, respectively, of such deposits recorded as a current asset in the Consolidated Balance Sheets.
The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The table below summarizes the impact of netting agreements and margin deposits on gross derivative assets and liabilities.
Gross derivative instruments recorded in the
Consolidated Balance Sheet		Derivative instruments
subject to master
netting agreements		Margin requirements with
counterparties		Net derivative
instruments
December 31, 2024(Thousands)
Asset derivative instruments, at fair value$143,581 $(117,350)$— $26,231 
Liability derivative instruments, at fair value446,519 (117,350)(86,975)242,194 
December 31, 2023
Asset derivative instruments, at fair value$978,634 $(112,203)$— $866,431 
Liability derivative instruments, at fair value186,363 (112,203)(13,017)61,143 
v3.25.0.1
Fair Value Measurements
 12 Months Ended
Dec. 31, 2024
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
 
The Company records its financial instruments, which are principally derivative instruments, at fair value in the Consolidated Balance Sheets. The Company estimates the fair value of its financial instruments using quoted market prices when available. If quoted market prices are not available, the fair value is based on models that use market-based parameters, including forward curves, discount rates, volatilities and nonperformance risk, as inputs. Nonperformance risk considers the effect of the Company's credit standing on the fair value of liabilities and the effect of the counterparty's credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to EQT's or the counterparty's credit rating and the yield on a risk-free instrument.

The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value hierarchy based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities that use Level 2 inputs primarily include the Company's swap, collar and option agreements.

Exchange traded commodity swaps have Level 1 inputs. The fair value of the commodity swaps with Level 2 inputs is based on standard industry income approach models that use significant observable inputs, including, but not limited to, NYMEX natural gas forward curves, SOFR-based discount rates, basis forward curves and NGLs forward curves. The Company's collars and options are valued using standard industry income approach option models. The significant observable inputs used by the option pricing models include NYMEX forward curves, natural gas volatilities and SOFR-based discount rates.

The table below summarizes assets and liabilities measured at fair value on a recurring basis.
  Fair value measurements at reporting date using:
Gross derivative instruments recorded in the Consolidated Balance SheetsQuoted prices in active markets 
for identical assets
(Level 1)		Significant other
observable inputs
(Level 2)		Significant unobservable inputs
(Level 3)
December 31, 2024(Thousands)
Asset derivative instruments, at fair value$143,581 $50,300 $93,281 $— 
Liability derivative instruments, at fair value446,519 81,074 365,445 — 
December 31, 2023
Asset derivative instruments, at fair value$978,634 $66,302 $912,332 $— 
Liability derivative instruments, at fair value186,363 42,218 144,145 — 
The carrying value of cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. The carrying value of borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and (prior to its redemption) the Term Loan Facility (defined in Note 10) approximates fair value as each facility's interest rate is based on prevailing market rates. The Company considers all of these fair values to be Level 1 fair value measurements.

The Company estimates the fair value of its senior notes using established fair value methodology. Because not all of the Company's senior notes are actively traded, their fair value is a Level 2 fair value measurement. As of December 31, 2024 and 2023, the Company's senior notes had a fair value of approximately $8.8 billion and $4.9 billion, respectively, and a carrying value of approximately $8.9 billion and $4.5 billion, respectively, inclusive of any current portion. See Note 10 for further discussion of the Company's debt.

Upon the closing of the Equitrans Midstream Merger, EQT's note payable to EQM became an intercompany transaction on a consolidated basis and, as such, was effectively settled on July 22, 2024. See Note 6. As of December 31, 2023, the fair value of EQT's note payable to EQM was estimated using an income approach model with a market-based discount rate and was considered a Level 3 fair value measurement. As of December 31, 2023, EQT's note payable to EQM had a fair value and carrying value of approximately $91 million and $88 million, respectively, inclusive of any current portion.

The Company recognizes transfers between Levels as of the actual date of the event or change in circumstances that caused the transfer. There were no transfers between Levels 1, 2 and 3 during the periods presented.

See Note 1 for a discussion of the fair value measurement and impairment of the Company's property, plant equipment. In addition, see Note 1 for a discussion of impairment of the Company's contract asset, investments in unconsolidated entities, net intangible assets and goodwill. See Note 1 for a discussion of the fair value measurement of the Company's asset retirement obligations. See Note 2 for a discussion of the fair value measurement of the Henry Hub Cash Bonus. See Note 6 for a discussion of the fair value measurement of assets acquired and liabilities assumed in the Equitrans Midstream Merger. See Note 7 for a discussion of the fair value measurement of the assets received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 11 for a discussion of the fair value measurement of the Company's investment in the Investment Fund (defined in Note 11).
v3.25.0.1
Acquisitions
 12 Months Ended
Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]  
Acquisitions Acquisitions
Equitrans Midstream Merger

On July 22, 2024, the Company completed its acquisition of Equitrans Midstream (Equitrans Midstream Merger) pursuant to the agreement and plan of merger dated March 10, 2024 (the Merger Agreement), by and among EQT, Humpty Merger Sub Inc., an indirect wholly-owned subsidiary of EQT (Merger Sub), Humpty Merger Sub LLC, an indirect wholly-owned subsidiary of EQT (LLC Sub), and Equitrans Midstream.

Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub merged with and into Equitrans Midstream (the First Merger), with Equitrans Midstream surviving as an indirect wholly-owned subsidiary of EQT (the First Step Surviving Corporation), and, as the second step in a single integrated transaction with the First Merger, the First Step Surviving Corporation merged with and into LLC Sub (the Second Merger and, together with the First Merger, the Equitrans Midstream Merger), with LLC Sub surviving the Second Merger as an indirect wholly-owned subsidiary of EQT.

Upon the closing of the Equitrans Midstream Merger, each share of common stock, no par value, of Equitrans Midstream (Equitrans Midstream common stock) that was issued and outstanding immediately prior to the effective time of the First Merger (other than shares of Equitrans Midstream common stock owned by Equitrans Midstream or its subsidiaries or by the Company) was converted into the right to receive, without interest, 0.3504 shares of EQT common stock, which totaled 152,427,848 shares of EQT common stock with an aggregate value of $5.5 billion, based on an EQT common stock share price of $35.88. In addition, in connection with the closing of the Equitrans Midstream Merger, the Company paid an aggregate of $79.5 million of equity consideration to employees of Equitrans Midstream who did not continue with the Company upon the Equitrans Midstream Merger closing date.
Immediately prior to the completion of the Equitrans Midstream Merger, on July 22, 2024, using borrowings under EQT's revolving credit facility, the Company paid $685.3 million to effect the purchase and redemption of all of the issued and outstanding Series A Perpetual Convertible Preferred Shares, no par value, of Equitrans Midstream (the Equitrans Midstream preferred stock).

Immediately following the closing of the Equitrans Midstream Merger, on July 22, 2024, EQM repaid all of its outstanding obligations under EQM's revolving credit facility using cash on hand and cash contributions from EQT, and, thereafter, EQM terminated its revolving credit facility. See Note 10.

Upon completion of the Equitrans Midstream Merger, the pre-existing contractual relationships between the Company, as producer, and Equitrans Midstream, as gathering and transmission services provider, are treated as intercompany transactions on a consolidated basis and, as such, were effectively settled on July 22, 2024. Likewise, upon completion of the Equitrans Midstream Merger, EQT's note payable to EQM became an intercompany transaction on a consolidated basis and, as such, was effectively settled on July 22, 2024.

For the year ended December 31, 2024, the Company recognized $304.8 million of transaction costs related to the Equitrans Midstream Merger in other operating expenses in the Statement of Consolidated Operations. Included in such transaction costs was severance and other termination benefits and stock-based compensation costs of $165.4 million, of which $60.8 million was cash and $104.6 million was non-cash.
Allocation of Purchase Price. The Equitrans Midstream Merger was accounted for as a business combination using the acquisition method. The table below summarizes the preliminary purchase price and estimated fair values of assets acquired and liabilities assumed as of July 22, 2024 with the excess of purchase price over estimated fair value of the identified net assets recognized as goodwill. Certain information necessary to complete the purchase price allocation is not yet available, including, but not limited to, final appraisals of assets acquired and liabilities assumed and final income tax computations. The Company expects to complete the purchase price allocation once it has received all necessary information, at which time the value of the assets acquired and liabilities assumed will be revised if necessary.
Preliminary Purchase Price Allocation
(Thousands)
Consideration:
Equity$5,548,608 
Cash (paid in lieu of fractional shares)29 
Redemption of Equitrans Midstream preferred stock685,337 
Settlement of pre-existing relationships(239,741)
Total consideration$5,994,233 
Fair value of assets acquired:
Cash and cash equivalents$58,767 
Accounts receivable, net82,072 
Income tax receivable2,142 
Prepaid expenses and other22,048 
Property, plant and equipment9,379,642 
Investments in unconsolidated entities3,363,336 
Net intangible assets200,000 
Other assets249,846 
Noncontrolling interest in consolidated subsidiaries(162,993)
Amount attributable to assets acquired$13,194,860 
Fair value of liabilities assumed:
Current portion of debt$699,837 
Accounts payable65,006 
Accrued interest47,996 
Other current liabilities70,951 
Revolving credit facility borrowings1,035,000 
Senior notes6,273,941 
Deferred income taxes935,106 
Other liabilities and credits152,271 
Amount attributable to liabilities assumed$9,280,108 
Goodwill$2,079,481 
The fair value of Equitrans Midstream's property, plant and equipment, which primarily includes gathering, transmission and storage systems and water infrastructure assets, and Equitrans Midstream's equity method investment in the MVP Joint Venture was measured using a combination of a cost and income approach based on inputs that are not observable in the market and, as such, are Level 3 fair value measurements. Significant inputs to the valuation of Equitrans Midstream's property, plant and equipment and investment in the MVP Joint Venture include replacement costs for similar assets, relative age of the assets, any potential economic or functional obsolescence associated with the assets, future revenue estimates and future operating cost assumptions and estimated weighted average costs of capital.

The fair value of the noncontrolling interest in Eureka Midstream Holdings was calculated using the noncontrolling interest ownership percentage and the enterprise value of Eureka Midstream Holdings, which was measured using a combination of a cost and income approach based on inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. Significant inputs to the valuation of the noncontrolling interest in Eureka Midstream Holdings include replacement costs for similar assets, relative age of the assets, any potential economic or functional obsolescence associated with the assets, future revenue estimates, future operating cost assumptions and estimated weighted average cost of capital.

As part of the preliminary purchase price allocation, the Company identified intangible assets related to certain of Equitrans Midstream's transmission services contracts. The fair value of the identified intangible assets was determined using the income approach based on inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. Significant inputs to the valuation of the identified intangible assets include future revenue estimates, future cost assumptions, estimated contract renewals, a discount rate assumption and an estimated required rate of return on the assets. The identified intangible assets are amortized over their useful life of 15 years on a straight-line basis, which reflects the pattern in which the Company expects to consume the economic benefits of the assets. The estimated annual amortization expense for the intangible assets is $13.3 million for each of the next 5 years.

The fair value of EQM's senior notes was measured using established fair value methodology. Because not all of EQM's senior notes are actively traded, their fair value is a Level 2 fair value measurement. The difference between the fair value and principal amount of the assumed senior notes is amortized over the remaining life of the debt. The unamortized amount is presented as a reduction of debt in the Consolidated Balance Sheet. Because the carrying value of borrowings under EQM's revolving credit facility and Eureka's revolving credit facility approximated their respective fair value (as each facility's interest rate is based on prevailing market rates), the Company considers their fair values to be Level 1 fair value measurements.

Goodwill is attributable to the Company's qualitative assumptions of long-term value that the Equitrans Midstream Merger creates for EQT shareholders. Of the total goodwill, the Company attributed $1.2 billion to the vertical integration of the business, including from the elimination of contracted transportation costs with Equitrans Midstream as the Company is unable to recognize intangible assets related to its significant long-term customer contracts with Equitrans Midstream as such contracts became intercompany transactions upon the closing of the Equitrans Midstream Merger. The Company allocated this amount of total goodwill to its Transmission segment. In addition, the Company attributed $0.9 billion of total goodwill to additional deferred tax liabilities that arose from the differences between the fair value and tax bases of preliminary purchase price allocation that carried over from Equitrans Midstream to the Company. Given the income tax characteristics of EQM (the entity that holds the gathering and transmission operations acquired in the Equitrans Midstream Merger) the Company presents this amount of total goodwill as "Other" for segments reporting. See Note 2. Differences between the preliminary purchase price allocation and the final purchase price allocation may change the amount of goodwill recognized.

In conjunction with the Equitrans Midstream Merger, as of the Equitrans Midstream Merger closing date, the Company had unamortized carryover tax basis of $647.2 million of tax deductible goodwill.

See Note 5 for a description of the fair value hierarchy.
Post-Acquisition Operating Results. The table below summarizes amounts contributed by the assets acquired in the Equitrans Midstream Merger, inclusive of intercompany eliminations, to the Company's consolidated results for the period beginning on July 22, 2024 and ending on December 31, 2024.
July 22, 2024 through December 31, 2024
(Thousands)
Loss on derivatives$(16,763)
Pipeline, net marketing services and other274,646 
Total operating revenues$257,883 
Net loss (a)$(136,946)
Less: Net income attributable to noncontrolling interests12,879 
Net loss attributable to EQT Corporation$(149,825)

(a)Net loss includes $280.6 million of transaction costs related to the Equitrans Midstream Merger.

Unaudited Pro Forma Information. The table below summarizes the Company's results as though the Equitrans Midstream Merger had been completed on January 1, 2023. Certain historical amounts were reclassified to conform to the Company's current financial presentation of operations. Such unaudited pro forma information is provided for informational purposes only and does not represent what consolidated results of operations would have been had the Equitrans Midstream Merger occurred on January 1, 2023 nor are they indicative of future consolidated results of operations.
Years Ended December 31,
 20242023
(Thousands, except per share amounts)
Pro forma operating revenues:
Pro forma sales of natural gas, NGLs and oil$4,934,366 $5,044,768 
Pro forma gain on derivatives17,685 1,887,016 
Pro forma pipeline, net marketing services and other621,214 616,245 
Pro forma total operating revenues$5,573,265 $7,548,029 
Pro forma net income (a)$489,503 $2,439,515 
Less: Pro forma net income attributable to noncontrolling interests28,303 30,037 
Pro forma net income attributable to EQT Corporation$461,200 $2,409,478 
Pro forma income per share of common stock attributable to EQT Corporation:
Pro forma net income attributable to EQT Corporation – Basic$0.78 $4.52 
Pro forma net income attributable to EQT Corporation – Diluted$0.77 $4.27 

(a)Pro forma net income for the year ended December 31, 2024 includes $304.8 million of transaction costs related to the Equitrans Midstream Merger.

NEPA Gathering System Acquisition

In 2021, the Company acquired a 50% interest in and became the operator of certain gathering assets located in Northeast Pennsylvania (collectively, the NEPA Gathering System).

On April 11, 2024, the Company completed its acquisition of a minority equity partner's 33.75% interest in the NEPA Gathering System for a purchase price of approximately $205 million (the NEPA Gathering System Acquisition), subject to customary post-closing adjustments. The NEPA Gathering System Acquisition was accounted for as an asset acquisition, and, as such, its purchase price was allocated to property, plant and equipment.
Tug Hill and XcL Midstream Acquisition

On August 22, 2023, the Company completed its acquisition (the Tug Hill and XcL Midstream Acquisition) of the upstream assets from THQ Appalachia I, LLC and the gathering and processing assets from THQ-XcL Holdings I, LLC through the acquisition of all of the issued and outstanding membership interests of each of THQ Appalachia I Midco, LLC and THQ-XcL Holdings I Midco, LLC. The purchase price for the Tug Hill and XcL Midstream Acquisition consisted of 49,599,796 shares of EQT common stock and approximately $2.4 billion in cash, subject to customary post-closing adjustments.

The Company accounted for the Tug Hill and XcL Midstream Acquisition as a business combination using the acquisition method. The Company completed the purchase price allocation for the Tug Hill and XcL Midstream Acquisition during the first quarter of 2024. The purchase accounting adjustments recorded in 2024 were not material.

For the years ended December 31, 2024 and 2023, the Company recognized $4.4 million and $56.3 million, respectively, of transaction costs related to the Tug Hill and XcL Midstream Acquisition in other operating expenses in the Statements of Consolidated Operations.

2022 Asset Acquisition

In the fourth quarter of 2022, the Company completed its acquisition (the 2022 Asset Acquisition) of approximately 4,600 net Marcellus acres in Northeast Pennsylvania for a total purchase price of approximately $56 million. The 2022 Asset Acquisition was accounted for as an asset acquisition, and, as such, the purchase price was allocated to property, plant and equipment.
v3.25.0.1
NEPA Non-Operated Asset Divestitures
 12 Months Ended
Dec. 31, 2024
Discontinued Operations and Disposal Groups [Abstract]  
NEPA Non-Operated Asset Divestitures NEPA Non-Operated Asset Divestitures
First NEPA Non-Operated Asset Divestiture. On May 31, 2024, the Company completed the divestiture (the First NEPA Non-Operated Asset Divestiture) of an undivided 40% interest in the Company's non-operated natural gas assets in Northeast Pennsylvania with a carrying amount of approximately $523 million to Equinor USA Onshore Properties Inc. and its affiliates (collectively, the Equinor Parties). The carrying value was composed of approximately $549 million of property, plant and equipment, approximately $6 million of other current liabilities and approximately $20 million of other liabilities and credits. In exchange, as consideration, the Company received from the Equinor Parties cash of $500 million, subject to customary post-closing purchase price adjustments, certain upstream assets and the remaining 16.25% equity interest in the NEPA Gathering System. The total fair value of consideration received, net of liabilities assumed, was approximately $832 million, subject to customary post-closing purchase price adjustments, and included $413 million of property, plant and equipment.

As a result of the First NEPA Non-Operated Asset Divestiture, the Company recognized a gain of approximately $299 million in (gain) loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations. The gain was calculated as the carrying value of the divested assets less the fair value of consideration received, net of liabilities assumed, and approximately $10 million of divestiture costs incurred. The long-lived assets divested and received and resulting gain are reported in the Company's Production segment. The Company used cash proceeds from the First NEPA Non-Operated Asset Divestiture to partly fund EQT's redemption of its 6.125% senior notes.

The fair values of the developed and undeveloped natural gas properties received as consideration for the First NEPA Non-Operated Asset Divestiture were measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. Significant inputs include future commodity prices, projections of estimated quantities of reserves, estimated future rates of production, projected reserve recovery factors, timing and amount of future development operating costs and a weighted average cost of capital as well as future development plans from a market participant perspective with respect to undeveloped properties.

The fair value of the interest in the NEPA Gathering System received as consideration for the First NEPA Non-Operated Asset Divestiture was measured using the cost approach based on inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. Significant inputs include replacement cost for similar assets, relative age of the assets and potential economic or functional obsolescence.

See Note 5 for a description of the fair value hierarchy.
In addition, subsequent to the completion of the First NEPA Non-Operated Asset Divestiture, the Company and the Equinor Parties entered into a gas buy-back agreement with respect to the assets received by the Company as consideration for the First NEPA Non-Operated Asset Divestiture, whereby the Equinor Parties agreed to purchase a specified amount of natural gas from the Company through the first quarter of 2028.

Second NEPA Non-Operated Asset Divestiture. On December 31, 2024, the Company completed the divestiture (the Second NEPA Non-Operated Asset Divestiture, and, together with the First NEPA Non-Operated Asset Divestiture, the NEPA Non-Operated Asset Divestitures) of the remaining undivided 60% interest in the Company's non-operated natural gas assets in Northeast Pennsylvania with a carrying amount of approximately $772 million to the Equinor Parties. The carrying value was composed of approximately $812 million of property, plant and equipment, approximately $9 million of other current liabilities and approximately $31 million of other liabilities and credits. In exchange, as consideration, the Company received from the Equinor Parties cash of $1.25 billion, subject to customary post-closing purchase price adjustments and transaction costs.

As a result of the Second NEPA Non-Operated Asset Divestiture, the Company recognized a gain of approximately $463 million in (gain) loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations. The gain was calculated as the carrying value of the divested assets less the consideration received and approximately $7 million of divestiture costs incurred. The long-lived assets divested and resulting gain are reported in the Company's Production segment. The Company used cash proceeds from the Second NEPA Non-Operated Asset Divestiture to repay a portion of outstanding borrowings under EQT's revolving credit facility.
v3.25.0.1
The Midstream Joint Venture Transaction
 12 Months Ended
Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]  
The Midstream Joint Venture Transaction The Midstream Joint Venture Transaction
On September 24, 2024, the Company formed PipeBox LLC (the Midstream Joint Venture) as a wholly-owned subsidiary of EQM. On November 22, 2024, EQM entered into a contribution agreement (the Contribution Agreement) with an affiliate of Blackstone Credit & Insurance (the BXCI Affiliate).

On December 30, 2024, pursuant to the Contribution Agreement, EQM and certain of its affiliates contributed to the Midstream Joint Venture the following assets in exchange for 364,285,715 Class A Units in the Midstream Joint Venture: (i) EQM's ownership interest in the MVP (via EQM's Series A ownership interest in the MVP Joint Venture), (ii) EQM's regulated transmission and storage assets (including those owned by Equitrans, L.P.), and (iii) EQM's Hammerhead Pipeline System (a 1.6 Bcf per day gathering header pipeline designed to connect natural gas produced in Pennsylvania and West Virginia to the MVP, Texas Eastern Transmission and Eastern Gas Transmission). In addition, pursuant to the Contribution Agreement, on December 30, 2024, the BXCI Affiliate contributed to the Midstream Joint Venture $3.5 billion of cash, net of certain transaction fees and expenses, in exchange for a noncontrolling equity interest of 350,000,000 Class B Units in the Midstream Joint Venture (such contributions by EQM and the BXCI Affiliate, collectively, the Midstream Joint Venture Transaction).

The Midstream Joint Venture Transaction was accounted for as a sale of interest in a subsidiary without a loss of control. The Company recorded a $3.5 billion increase in noncontrolling interest in consolidated subsidiaries and a $77.5 million decrease to common shareholders' equity, inclusive of transaction-related expenses incurred by the Company and a $13.3 million deferred tax asset.

In addition, on December 30, 2024, EQT (solely for the limited purposes set forth therein), EQM, the BXCI Affiliate and the Midstream Joint Venture entered into an amended and restated limited liability company agreement of the Midstream Joint Venture (the JV Agreement). The JV Agreement provides for, among other things, quarterly distributions of available cash flow to the Midstream Joint Venture's unitholders, of which EQM, as Class A Unitholder, will receive 40% and the BXCI Affiliate, as Class B Unitholder, will receive 60% until the Base Return (as defined in the JV Agreement) has been achieved. After the Base Return has been achieved and until the 8th anniversary of the closing of the Midstream Joint Venture Transaction of December 30, 2024, 100% of the Midstream Joint Venture's distributions, including in a liquidation or sale of the Midstream Joint Venture, will be distributed to EQM as Class A Unitholder and zero percent will be distributed to the BXCI Affiliate as Class B Unitholder; after the Base Return has been achieved and from the 8th anniversary of December 30, 2024 and thereafter, no less than 95% of the Midstream Joint Venture's distributions, including in a liquidation or sale of the Midstream Joint Venture, will be distributed to EQM as Class A Unitholder, and up to 5% of the Midstream Joint Venture's distributions will be distributed to the BXCI Affiliate as Class B Unitholder (with specific distribution percentages determined based on the BXCI Affiliate's ownership of Class B Units as of the time of such distribution).
Based on the governing provisions of the JV Agreement, EQT's management determined that the allocation of income between the Company and the BXCI Affiliate should be based on the change in the investors claim on the Midstream Joint Venture's book value. Under this method, the Company recognizes net income/loss attributable to the noncontrolling interest based on changes to the amount that each member would hypothetically receive at each balance sheet date under the JV Agreement's liquidation provisions, assuming that the net assets of the Midstream Joint Venture were liquidated at the recorded amounts, after taking into account any capital transactions between the Company and the BXCI Affiliate.

The Company used the proceeds from the Midstream Joint Venture Transaction to repay outstanding borrowings, and interest thereon, under the Bridge Credit Facility (defined in Note 10) and the Term Loan Facility and a portion of outstanding borrowings under EQT's revolving credit facility as well as to pay certain transaction fees and expenses related to the Midstream Joint Venture Transaction and other related transactions. See Note 10.
Investments in Unconsolidated Entities
Equity Method Investments

The Company applies the equity method of accounting to its investments in entities that the Company does not have the power to direct the activities that most significantly affect those entities' economic performance but does have the ability to exercise significant influence over. The Company's pro-rata share of income/loss from the Company's equity method investments is recorded in (income) loss from investments in the Statements of Consolidated Operations.

The table below summarizes the Company's equity method investments.
December 31, 2024December 31, 2023
Ownership InterestCarrying ValueOwnership InterestCarrying Value
(Thousands)(Thousands)
MVP Joint Venture (a):
The MVP (b)49.3 %$3,469,438 — %$— 
MVP Southgate47.2 %65,292 — %— 
Total MVP Joint Venture3,534,730 — 
Laurel Mountain Midstream, LLC (c)31 %28,757 31 %39,923 
WATT Fuel Cell Corporation (d)15.63 %14,533 15.43 %16,700 
Yellowbird Energy LLC (e)50 %6,135 — %— 
Total$3,584,155 $56,623 

(a)Mountain Valley Pipeline, LLC (the MVP Joint Venture) is a Delaware series limited liability company joint venture formed among (i) with respect to Series A, an affiliate of EQT and affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating the MVP and (ii) with respect to Series B, a wholly-owned subsidiary of EQT and affiliates of NextEra Energy, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating MVP Southgate.
(b)As discussed in Note 8, upon the completion of the Midstream Joint Venture Transaction, the Company contributed its interest in the MVP (via its Series A ownership interest in the MVP Joint Venture) to the Midstream Joint Venture.
(c)Laurel Mountain Midstream, LLC is a natural gas gathering and processing joint venture formed among the Company, Williams Companies Inc. and certain other energy companies.
(d)Watt Fuel Cell Corporation is a developer and manufacturer of solid oxide fuel cell systems that operate on common, readily available fuels such as natural gas and propane.
(e)Yellowbird Energy LLC is a joint venture formed in 2024 between a subsidiary of EQT and a third-party investor.
The MVP. The MVP is a 303-mile long, 42-inch diameter natural gas interstate pipeline with a total capacity of 2.0 Bcf per day that spans from the Company's transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia. Following receipt of authorization from the Federal Energy Regulatory Commission (the FERC), the MVP entered into service on June 14, 2024 and became available for interruptible or short-term firm transportation service. On July 1, 2024, the MVP commenced long-term firm capacity obligations. A wholly-owned subsidiary of EQM is the operator of the MVP.

Estimated total project cost of the MVP is approximately $8.1 billion, including contingency and excluding AFUDC during construction. Of this amount, $142.8 million was contributed by the Company following the completion of the Equitrans Midstream Merger.

The Company has a negative basis difference between the carrying value of its equity method investment in the MVP and its proportionate share of the MVP's net assets (composed of fixed assets). The basis difference is accreted over the useful life of the fixed assets, with accretion expense presented in (income) loss from investments in the Company's Statement of Consolidated Operations. As of December 31, 2024, the basis difference, net of accretion, was $1.3 billion.
For the year ended December 31, 2024, the Company's Series A ownership interest (with respect to the MVP) in the MVP Joint Venture was significant as defined by the SEC's Regulation S-X Rule 1-02(w). Accordingly, pursuant to Regulation S-X Rule 4-08(g), the following table presents summarized financial information of the MVP Joint Venture in relation to the MVP for the period beginning on July 22, 2024 and ending December 31, 2024 and as of December 31, 2024.
 July 22, 2024 to
December 31, 2024
(Thousands)
Operating revenues$247,360 
Operating income$126,202 
Net income$129,773 
December 31, 2024
(Thousands)
Current assets$204,028 
Noncurrent assets9,535,975 
Total assets$9,740,003 
Current liabilities$69,303 
Noncurrent liabilities1,514 
Total liabilities70,817 
Members' equity9,669,186 
Total liabilities and members' equity$9,740,003 
MVP Southgate. MVP Southgate is a contemplated interstate pipeline that was approved by the FERC. The pipeline was initially designed to extend approximately 75 miles from the MVP in Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina using 24-inch and 16-inch diameter pipe.

In December 2023, the MVP Joint Venture entered into precedent agreements with Public Service Company of North Carolina, Inc. and Duke Energy Carolinas, LLC. The precedent agreements contemplate a modified project and, among other things, describe certain conditions precedent to the parties' respective obligations regarding MVP Southgate. As modified, the natural gas interstate pipeline would extend approximately 31 miles from the terminus of the MVP in Pittsylvania County, Virginia to planned new delivery points in Rockingham County, North Carolina using 30-inch diameter pipe and have a targeted capacity of 550,000 dekatherms per day. The proposed 31-mile route passes through a portion of the Southern Virginia Mega Site at Berry Hill, which is one of the largest business parks on the East Coast.
On February 3, 2025, the MVP Joint Venture filed an application with the FERC seeking to amend its existing Certificate of Public Convenience and Necessity to reflect the amended project. The Company expects a wholly-owned subsidiary of EQM to operate MVP Southgate upon its completion, which is targeted for June 2028. MVP Southgate is estimated to have a total cost of approximately $370 million to $430 million, excluding AFUDC and certain costs incurred for purposes of the originally certificated project, of which the Company will fund its proportionate share through capital contributions to the MVP Joint Venture.

Pursuant to the MVP Joint Venture's limited liability company agreement and upon the closing of the Equitrans Midstream Merger, the Company is obligated to provide performance assurances with respect to MVP Southgate that may take the form of a guarantee from EQM (provided that, in accordance with the requirements of the MVP Joint Venture's limited liability company agreement, EQM's debt is assigned an investment grade credit rating), a letter of credit or cash collateral. Upon receipt of the FERC's initial release to begin construction of MVP Southgate, the Company will be obligated to provide performance assurance in an amount equal to 33% of its share of MVP Southgate's remaining capital commitments under the applicable construction budget.

Investments in Equity Securities

The Company accounts for its investments in entities that the Company does not have the ability to exercise significant influence over as an investment in equity security. Changes in the fair value of the Company's investments in equity securities are recorded in (income) loss from investments and dividends received on the Company's investments in equity securities are recorded in other income in the Statements of Consolidated Operations.

The Investment Fund. As of December 31, 2024, the Company held an investment in a fund (the Investment Fund) that invests in companies that develop technology and operating solutions for exploration and production companies. As of December 31, 2024 and 2023, the fair value of the Company's investment in the Investment Fund was $33.2 million and $36.1 million, respectively, and was presented in investments in unconsolidated entities in the Consolidated Balance Sheets. The Company computes the fair value of the Company's investment in the Investment Fund using, as a practical expedient, the net asset value provided in the financial statements received from fund managers.

Equitrans Midstream. Prior to the Company's sale of all of its then-owned shares of Equitrans Midstream common stock in 2022, the Company accounted for its investment in Equitrans Midstream as an investment in equity security.
v3.25.0.1
Income Taxes
 12 Months Ended
Dec. 31, 2024
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
 
The following table summarizes the Company's income tax expense.
 Years Ended December 31,
 202420232022
 (Thousands)
Current:   
Federal$1,222 $(10,894)$651 
State6,125 (4,818)18,457 
Subtotal7,347 (15,712)19,108 
Deferred:
Federal(21,463)450,091 527,539 
State36,195 (65,425)7,073 
Subtotal14,732 384,666 534,612 
Total income tax expense$22,079 $368,954 $553,720 
 
For the year ended December 31, 2024, current income tax expense is composed of state and federal income tax liabilities. For the year ended December 31, 2023, current income tax benefit related primarily to 2014 through 2017 audit settlement interest and reduction in prior year state income tax liabilities. For the year ended December 31, 2022, current income tax expense related primarily to state income tax liabilities.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (IRA). The IRA establishes a 15% corporate alternative minimum tax for certain corporations and a 1% excise tax on stock repurchases made by publicly traded U.S. corporations. The IRA also includes new and renewed options for energy credits. These changes are effective for tax years beginning after December 31, 2022. The impact of these changes did not have a material impact on the Company's financial statements and disclosures.
The table below summarizes the reasons for income tax expense differences from amounts computed at the federal statutory rate of 21% on pre-tax income.
 Years Ended December 31,
 202420232022
Amount RateAmountRateAmountRate
 (Thousands)(Thousands)(Thousands)
Income before income taxes$264,194 $2,103,498 $2,334,662 
Tax at statutory rate$55,481 21.0%$441,735 21.0%$490,279 21.0%
State income taxes5,440 2.1%50,263 2.4%48,970 2.1%
Valuation allowance(9,601)(3.6)%(81,483)(3.9)%12,685 0.5%
Convertible Notes repurchase premium— —%— —%35,957 1.5%
Uncertain tax positions(16,977)(6.4)%(7,015)(0.3)%11,135 0.5%
State law change(11,315)(4.3)%(21,670)(1.0)%(49,511)(2.1)%
Federal and state tax credits(6,537)(2.5)%(4,715)(0.2)%(4,319)(0.2)%
Transaction costs6,041 2.3%— —%— —%
Other(453)(0.2)%(8,161)(0.4)%8,524 0.4%
Income tax expense$22,079 8.4%$368,954 17.5%$553,720 23.7%
 
The Company's effective tax rate for the year ended December 31, 2024 was lower compared to the U.S. federal statutory rate due primarily to the release of valuation allowances related to capital loss carryforward utilization, expiration of a statute of limitations related to uncertain tax positions, inclusive of interest, and net state deferred tax benefit related to a rate reduction from a Pennsylvania tax law change enacted on July 8, 2022 (the Pennsylvania Tax Legislation). The Pennsylvania Tax Legislation lowered the corporate net income tax rate from 8.99% to 8.49% in 2024 and continues to lower the corporate net income tax rate by 0.5% annually thereafter until the corporate net income tax rate reaches 4.99% in 2031. The rate reductions were partly offset by valuation allowances limiting certain state income tax benefits and non-deductible transaction costs incurred with the Equitrans Midstream Merger.

The Company's effective tax rate for the year ended December 31, 2023 was lower compared to the U.S. federal statutory rate due primarily to the release of valuation allowances limiting certain state deferred tax assets and net state deferred tax benefit related to a rate reduction from the Pennsylvania Tax Legislation and the Tug Hill and XcL Midstream Acquisition. The Pennsylvania Tax Legislation lowered the corporate net income tax rate from 9.99% to 8.99% in 2023.

The Company's effective tax rate for the year ended December 31, 2022 was higher compared to the U.S. federal statutory rate due primarily to state income taxes, including valuation allowances limiting certain state income tax benefits and nondeductible repurchase premiums on the Convertible Notes (defined in Note 10), partly offset by state income tax benefits related to the Pennsylvania Tax Legislation. Included in the state law change was a decrease in state net operating loss (NOL) carryforwards of $214.1 million and a decrease in state valuation allowance on NOL carryforwards of $198.5 million.
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
 December 31,
 20242023
 (Thousands)
Deferred tax assets:
NOL carryforwards$708,518 $740,802 
Interest disallowance limitation106,622 59,668 
Federal tax credits89,644 92,730 
Net unrealized losses80,723 — 
State capital loss carryforward44,496 99,632 
Incentive compensation and deferred compensation plans18,032 16,854 
Other2,433 1,156 
Deferred tax assets1,050,468 1,010,842 
Valuation allowance(257,218)(290,812)
Net deferred tax asset793,250 720,030 
Deferred tax liabilities:
Property, plant and equipment(2,516,074)(2,457,946)
Investment in partnerships(1,128,279)— 
Net unrealized gains— (166,905)
Deferred tax liability(3,644,353)(2,624,851)
Net deferred tax liability$(2,851,103)$(1,904,821)
 
During 2024, the net deferred tax liability increased by $946.3 million compared to 2023 due primarily to the additional deferred tax liability related to the Company's investment in EQM (treated as a partnership for tax purposes) and the additional deferred tax liabilities that arose from the fair value accounting of net assets acquired in the Equitrans Midstream Merger, partly offset by an increase in net unrealized losses.

The following table presents the expiration periods of the NOL carryforward deferred tax assets and associated valuation allowance by jurisdiction.
 December 31,
 20242023
 (Thousands)
NOL carryforwards:
Federal (expires between 2032 and 2037)$14,644 $67,958 
Federal (indefinite expiration)322,258 323,598 
State (expires between 2025 and 2037)347,279 332,153 
State (indefinite expiration)24,337 17,093 
Total NOL carryforwards$708,518 $740,802 
Valuation allowance on NOL carryforwards:
Federal$(14,263)$(24,927)
State(187,321)(156,700)
Total valuation allowance on NOL carryforwards$(201,584)$(181,627)

The Company recognizes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, is considered when determining the need for a valuation allowance. To determine whether a valuation allowance is required, the Company uses judgement to estimate future taxable income and considers the tax consequences in the jurisdiction where such taxable income is generated as well as evidence including the Company's current financial position, actual and forecasted results of operations, the reversal of deferred tax liabilities and tax planning strategies in addition to the current and forecasted business economics of the oil and gas industry.
For 2024 and 2023, positive evidence considered included the reversals of financial-to-tax temporary differences, the implementation of and/or ability to employ various tax planning strategies and the Company's estimation of future taxable income. Negative evidence considered included historical pre-tax book losses of the Company and the uncertainty of future commodity prices and inability to generate capital gains. A review of positive and negative evidence regarding these tax benefits resulted in the conclusion that valuation allowances for certain NOLs and state capital loss carryforwards were warranted as it was more likely than not that the Company would not use them prior to expiration.

The remaining valuation allowance (which is not included in the NOL table above) is related primarily to the state capital loss carryforward realized with the sales of the Company's equity investment in Equitrans Midstream occurring between February 2020 and April 2022, which was a capital asset for tax purposes. Any capital losses from the sale of the investment can only be utilized to offset capital gains and are limited to being carried back 3 years and forward 5 years for potential utilization. In April 2022, the Company sold the remaining portion of its equity investment in Equitrans Midstream, which generated a capital loss that can only be carried forward for potential future utilization. During 2024, the Company recognized capital gains from the NEPA Non-operated Asset Divestitures that allowed the Company to recognize in the Statement of Consolidated Operations a federal and state income tax benefit of $52.8 million and $2.3 million, respectively, related to its valuation allowances for its capital loss carryforwards.

As of December 31, 2024, the Company had a valuation allowance related to the capital loss carryforward of $44.5 million for state income tax purposes due to the limitations on future potential utilization. As of December 31, 2023, the Company had a valuation allowance related to the capital loss carryforward of $52.8 million for federal income tax purposes and $46.8 million for state income tax purposes due to the limitations on future potential utilization.

The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, excluding interest and penalties.
 202420232022
 (Thousands)
Balance at January 1$89,197 $204,035 $182,032 
Additions for tax positions taken in current year11,720 11,986 9,612 
Additions (reductions) for tax positions taken in prior years15,177 (883)12,391 
Reductions for tax positions settled with tax authorities(29,645)(125,941)— 
Reductions for lapse in statute of limitations(13,706)— — 
Balance at December 31$72,743 $89,197 $204,035 

The following table presents specific line items that were included in the reserve for uncertain tax positions.
December 31,
202420232022
(Thousands)
If recognized, effect to the effective tax rate$67,105 $83,669 $117,341 
Reduction of related deferred tax asset for general business credit carryforwards and NOLs$60,415 $77,013 $110,744 

The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Company recorded interest and penalties expense (income) of approximately $0.6 million, $(19.8) million and $6.7 million for the years ended December 31, 2024, 2023 and 2022, respectively. Interest and penalties of $2.9 million, $2.3 million, and $22.2 million were included in the Consolidated Balance Sheets as of December 31, 2024, 2023 and 2022, respectively.

As of December 31, 2024, the Company believed that, as a result of potential settlements with relevant taxing authorities, it is reasonably possible that a decrease of $14.6 million in unrecognized tax benefits related to state income tax positions may be necessary within twelve months.
In September 2024, the Company settled its consolidated U.S. federal income tax liability with the IRS through 2019 for amounts included in the reserve for uncertain tax positions with minimal impact to the effective tax rate. The settlement resulted in forgone research and development tax credits of $29.6 million, which are reflected in the table above. The refundable alternative minimum tax credits realized with the settlement of the previous IRS audit are included in the income tax receivable in the Consolidated Balance Sheet as of December 31, 2024. As of December 31, 2024, the Company is no longer subject to state examinations by income tax authorities for years prior to 2016 and has considered ongoing state income tax matters in its reserve for uncertain tax positions.

There were no material changes to the Company's methodology for accounting for unrecognized tax benefits during 2024.
v3.25.0.1
Debt
 12 Months Ended
Dec. 31, 2024
Debt Disclosure [Abstract]  
Debt Debt
The table below summarizes the Company's outstanding debt.
December 31, 2024December 31, 2023
 Principal ValueCarrying Value (a)Fair Value (b)Principal ValueCarrying Value (a)Fair Value (b)
 (Thousands)
EQT's revolving credit facility maturing July 23, 2029$150,000 $150,000 $150,000 $— $— $— 
Eureka's revolving credit facility maturing November 13, 2025320,800 320,800 320,800 — — — 
Term Loan Facility due June 30, 2026— — — 1,250,000 1,244,265 1,244,265 
Debentures and senior notes:
EQT's 6.125% notes due February 1, 2025 (c)
— — — 601,521 600,389 605,082 
EQT's 1.75% convertible notes due May 1, 2026
— — — 290,177 286,185 768,554 
EQT's 3.125% notes due May 15, 2026
392,915 391,193 382,994 392,915 389,978 373,261 
EQT's 7.75% debentures due July 15, 2026
115,000 114,213 119,590 115,000 113,716 121,590 
EQM's 7.500% notes due June 1, 2027
500,000 511,377 510,140 — — — 
EQM's 6.500% notes due July 1, 2027
900,000 915,538 912,159 — — — 
EQT's 3.90% notes due October 1, 2027
1,169,503 1,166,523 1,137,248 1,169,503 1,165,439 1,121,027 
EQT's 5.700% notes due April 1, 2028
500,000 492,640 508,695 500,000 490,376 509,280 
EQM's 5.500% notes due July 15, 2028
118,683 118,204 117,382 — — — 
EQT's 5.00% notes due January 15, 2029
318,494 315,785 314,357 318,494 315,121 316,784 
EQM's 4.50% notes due January 15, 2029
742,923 711,754 711,297 — — — 
EQM's 6.375% notes due April 1, 2029
600,000 608,667 606,774 — — — 
EQT's 7.000% notes due February 1, 2030 (c)
674,800 671,641 718,358 674,800 671,020 726,645 
EQM's 7.500% notes due June 1, 2030
500,000 535,671 534,950 — — — 
EQM's 4.75% notes due January 15, 2031
1,100,000 1,045,219 1,039,995 — — — 
EQT's 3.625% notes due May 15, 2031
435,165 430,818 388,111 435,165 430,141 389,925 
EQT's 5.750% notes due February 1, 2034
750,000 742,796 744,743 — — — 
EQM's 6.500% notes due July 15, 2048
80,233 81,338 81,932 — — — 
EQT's note payable to EQM— — — 88,483 88,483 91,063 
Total debt9,368,516 9,324,177 9,299,525 5,836,058 5,795,113 6,267,476 
Less: Current portion of debt (d)320,800 320,800 320,800 296,424 292,432 774,983 
Long-term debt$9,047,716 $9,003,377 $8,978,725 $5,539,634 $5,502,681 $5,492,493 
 
(a)For EQT's revolving credit facility, Eureka's revolving credit facility and, as of December 31, 2023, EQT's note payable to EQM, the principal value represents carrying value. For all other debt, the principal value less the unamortized debt issuance costs and debt discounts and, for EQM's senior notes, the unamortized fair value adjustments recorded with Equitrans Midstream Merger purchase price accounting represents carrying value.
(b)The carrying value of borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and, as of December 31, 2023, the Term Loan Facility approximates fair value as their interest rates are based on prevailing market rates; therefore, the Company considers the fair value of EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility to be Level 1 fair value measurements. As of December 31, 2023, the Company measured the fair value of EQT's note payable to EQM using Level 3 inputs. For all other debt, fair value is measured using Level 2 inputs. See Note 5 for the fair value hierarchy.
(c)Interest rates for EQT's 7.000% senior notes fluctuate based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Prior to their redemption, interest rates for EQT's 6.125% senior notes fluctuated based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Interest rates for the Company's other senior notes do not fluctuate.
(d)As of December 31, 2024, the current portion of debt included borrowings outstanding under Eureka's revolving credit facility. As of December 31, 2023, the current portion of debt included EQT's 1.75% convertible notes and a portion of EQT's note payable to EQM. Upon the closing of the Equitrans Midstream Merger, EQT's note payable to EQM became an intercompany transaction on a consolidated basis and, as such, was effectively settled on July 22, 2024.

Debt Repayments. The Company repaid, redeemed or repurchased the following debt during the year ended December 31, 2024.
Debt TranchePrincipalPremiums/(Discounts)Accrued but Unpaid InterestTotal Cost
(Thousands)
EQM's 6.000% notes due July 1, 2025 (a)
$400,000 $1,284 $11,933 $413,217 
EQM's 4.125% notes due December 1, 2026 (a)
500,000 — 1,662 501,662 
EQM's 5.500% notes due July 15, 2028 (a)
731,317 15,541 18,435 765,293 
EQM's 4.50% notes due January 15, 2029 (a)
57,077 (713)1,177 57,541 
EQM's 6.500% notes due July 15, 2048 (a)
469,767 27,012 13,995 510,774 
EQM's 4.00% notes due August 1, 2024
300,000 — 6,000 306,000 
EQT's 6.125% notes due February 1, 2025
601,521 1,178 13,612 616,311 
Term Loan Facility due June 30, 20261,250,000 15 6,136 1,256,151 
EQT's 1.75% convertible notes due May 1, 2026
583 — — 583 
Total$4,310,265 $44,317 $72,950 $4,427,532 

(a)In addition to call premiums (discounts) disclosed, EQM paid $7.8 million in third-party advisory costs and fees to dealer managers and brokers for the redemption of its 6.000% senior notes, redemption of its 4.125% senior notes and repayment of certain of its senior notes in the EQM Tender Offer (defined below).

EQT's Revolving Credit Facility. EQT has a $3.5 billion revolving credit facility. On July 22, 2024, EQT entered into a Fourth Amended and Restated Credit Agreement (as amended from time to time, the EQT Credit Agreement) with PNC Bank National Association, as administrative agent, swing line lender and L/C issuer, and the other lenders party thereto, amending and restating the Third Amended and Restated Credit Agreement, dated June 28, 2022 (the Third A&R Credit Agreement), under which such lenders agreed to make to EQT unsecured revolving loans in an aggregate principal amount of up to $3.5 billion. The EQT Credit Agreement, among other things, (i) extended the maturity date of the commitments and loans under the Third A&R Credit Agreement to July 23, 2029 and provides, at EQT's option, two one-year extensions thereafter, subject to satisfaction of certain conditions, and (ii) allows for additional commitment increases up to $1 billion, subject to the agreement of EQT and new or existing lenders. EQT can obtain Base Rate Loans (as defined in the EQT Credit Agreement) or Term SOFR Rate Loans (as defined in the EQT Credit Agreement). Base Rate Loans are denominated in dollars and bear interest at a Base Rate (as defined in the EQT Credit Agreement) plus a margin ranging from 12.5 basis points to 100 basis points determined on the basis of EQT's credit ratings. Term SOFR Rate Loans bear interest at a Term SOFR Rate (as defined in the EQT Credit Agreement) plus an additional 10 basis point credit spread adjustment plus a margin ranging from 112.5 basis points to 200 basis points determined on the basis of EQT's credit ratings.

EQT's revolving credit facility may be used for working capital, capital expenditures, share repurchases and any other lawful corporate purposes. EQT's revolving credit facility is underwritten by a syndicate of a large group of financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by EQT. As of December 31, 2024, no one lender of the large group of financial institutions in the syndicate for EQT's revolving credit facility holds more than 10% of the financial commitments under such facility. The large syndicate group and relatively low percentage of participation by each lender are expected to limit the Company's exposure to disruption or consolidation in the banking industry.
EQT is not required to maintain compensating bank balances. EQT's debt issuer credit ratings, as determined by Moody's, S&P or Fitch on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with EQT's revolving credit facility in addition to the interest rate charged by the lenders on any amounts borrowed against EQT's revolving credit facility; the lower EQT's debt credit rating, the higher the level of fees and borrowing rate.

EQT's revolving credit facility contains various provisions that, if not complied with, could result in termination of EQT's revolving credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under EQT's revolving credit facility are the maintenance of a debt-to-total capitalization ratio and limitations on transactions with affiliates. EQT's revolving credit facility contains financial covenants that require a total debt-to-total capitalization ratio of no greater than 65%. As of December 31, 2024, EQT was in compliance with all provisions and covenants of the EQT Credit Agreement.

As of December 31, 2024 and 2023, the Company had approximately $1 million and $15 million, respectively, of letters of credit outstanding under EQT's revolving credit facility.

For the years ended December 31, 2024, 2023 and 2022, under EQT's revolving credit facility, the maximum amount of outstanding borrowings was $2,357 million, $269 million and $1,300 million, respectively, the average daily balance was approximately $936 million, $40 million and $466 million, respectively, and interest was incurred at a weighted average annual interest rate of 6.6%, 6.9% and 2.8%, respectively. For all years ended December 31, 2024, 2023 and 2022, the Company incurred commitment fees of approximately 20 basis points on the undrawn portion of EQT's revolving credit facility to maintain credit availability.

Eureka's Revolving Credit Facility. Upon the closing of the Equitrans Midstream Merger, the Company acquired a controlling interest in Eureka Midstream Holdings. See Notes 1 and 6. Eureka, a wholly-owned subsidiary of Eureka Midstream Holdings, has a $400 million senior secured revolving credit facility pursuant to that certain Credit Agreement, dated May 13, 2021, among Eureka, Sumitomo Mitsui Banking Corporation, as administrative agent, the lenders party thereto from time to time and any other persons party thereto from time to time (as amended from time to time, the Eureka Credit Agreement). Eureka can obtain Base Rate Loans (as defined in the Eureka Credit Agreement) or Term SOFR Rate Loans (as defined in the Eureka Credit Agreement), each plus a margin based on Eureka's consolidated leverage ratio. Base Rate Loans are denominated in dollars and bear interest at a Base Rate (as defined in the Eureka Credit Agreement) plus a margin ranging from 100 basis points to 225 basis points determined on the basis of Eureka's consolidated leverage ratio. Term SOFR Rate Loans bear interest at a Term SOFR Rate (as defined in the Eureka Credit Agreement) plus an additional 10 basis point credit spread adjustment plus a margin ranging from 200 basis points to 325 basis points determined on the basis of Eureka's consolidated leverage ratio.

Eureka's revolving credit facility contains negative covenants that, among other things, limit restricted payments, incurrence of debt, dispositions, mergers and other fundamental changes and transactions with affiliates, in each case and as applicable, subject to certain specified exceptions. In addition, Eureka's revolving credit facility contains certain specified events of default, including insolvency, nonpayment of scheduled principal or interest obligations, loss and failure to replace certain material contracts, change of control and cross-default provisions related to the acceleration or default of certain other financial obligations. As of December 31, 2024, Eureka was in compliance with all provisions and covenants of the Eureka Credit Agreement.

As of December 31, 2024, Eureka had no letters of credit outstanding under its revolving credit facility.

For the period beginning on July 22, 2024 and ending on December 31, 2024, under Eureka's revolving credit facility, the maximum amount of outstanding borrowings was $330 million, the average daily balance was $328 million and interest was incurred at a weighted average annual interest rate of 7.8%. For the period beginning on July 22, 2024 and ending on December 31, 2024, the Company incurred commitment fees of approximately 50 basis points on the undrawn portion of Eureka's revolving credit facility to maintain credit availability.
EQM's Bridge Credit Facility. In connection with its entry into the Contribution Agreement, on November 22, 2024, EQM entered into a debt commitment letter with Royal Bank of Canada (EQM Debt Commitment Letter), pursuant to which Royal Bank of Canada committed, subject to satisfaction of certain conditions, to provide EQM with a senior unsecured bridge term loan facility in an aggregate principal amount of up to $2.3 billion (the Bridge Credit Facility). On December 27, 2024, EQM entered into the Bridge Credit Facility and borrowed $2.23 billion thereunder to fund (with cash on hand) the redemption and repurchase of certain of EQM's senior notes. See "Debt Repayments" table and "EQM's Senior Notes." Upon the closing of the Midstream Joint Venture discussed in Note 8, the Company used a portion of the proceeds from the Midstream Joint Venture Transaction to repay outstanding borrowings, and interest thereon, under the Bridge Credit Facility, and, thereafter, EQM terminated the Bridge Credit Facility.

EQM's Revolving Credit Facility. Immediately following the closing of the Equitrans Midstream Merger, on July 22, 2024, EQM repaid outstanding obligations under that certain Third Amended and Restated Credit Agreement, dated October 31, 2018, by and among EQM, Wells Fargo Bank, National Association, as administrative agent, swing line lender and L/C issuer, and the other financial institutions from time to time party thereto for principal of $705 million and interest and fees of $4.5 million using cash on hand and cash contributions from EQT funded by borrowings under EQT's revolving credit facility, and, thereafter, EQM terminated its revolving credit facility.

Term Loan Facility. On November 9, 2022, EQT entered into a Credit Agreement (as amended from time to time, the Term Loan Agreement) with PNC Bank, National Association, as administrative agent, and the other lenders party thereto, under which such lenders agreed to make to EQT unsecured term loans in a single draw in an aggregate principal amount of up to $1.25 billion (the Term Loan Facility) to partly fund the Tug Hill and XcL Midstream Acquisition. On August 21, 2023, EQT borrowed $1.25 billion under the Term Loan Facility, receiving net proceeds of $1,242.9 million. Prior to its draw on the Term Loan Facility, the Company incurred commitment fees of approximately 20 basis points on the undrawn portion of the Term Loan Facility to maintain credit availability.

On January 16, 2024, EQT entered into a third amendment to the Term Loan Agreement to, among other things, extend the maturity date of the Term Loan Agreement from June 30, 2025 to June 30, 2026. The third amendment to the Term Loan Agreement became effective on January 19, 2024 upon EQT's prepayment of $750 million principal amount of the term loans outstanding under the Term Loan Facility (funded with the net proceeds from the issuance of EQT's 5.750% senior notes and cash on hand) and the satisfaction of other closing conditions. On July 22, 2024, EQT entered into a fourth amendment to the Term Loan Agreement to, among other things, make certain conforming changes to the Term Loan Agreement in alignment with the EQT Credit Agreement.

Upon the closing of the Midstream Joint Venture, the Company used a portion of the proceeds from the Midstream Joint Venture Transaction to repay the remaining $500 million of outstanding borrowings, and interest thereon, under the Term Loan Facility, and, thereafter, EQT terminated the Term Loan Facility. Refer to "Debt Repayments" for details.

Prior to their prepayment, the term loans outstanding under the Term Loan Facility bore interest at either (at EQT's election) a Term SOFR Rate plus the SOFR Adjustment or Base Rate (both terms defined in the Term Loan Agreement), each plus a margin based on EQT's credit ratings. For the period beginning on January 1, 2024 and ending on December 30, 2024, interest under the Term Loan Facility was incurred at a weighted average annual interest rate of 6.8%. For the period beginning on August 21, 2023 and ending on December 31, 2023, interest under the Term Loan Facility was incurred at a weighted average annual interest rate of 6.9%.

EQM's Senior Notes. Upon the closing of the Equitrans Midstream Merger, EQM became an indirect wholly-owned subsidiary of EQT, and EQM's outstanding senior notes were consolidated by the Company.

The indentures governing EQM's senior notes contain certain restrictive financial and operating covenants, including covenants that restrict, among other things, EQM's ability to incur, as applicable, indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. Certain of EQM's senior notes also include an offer to repurchase provision applicable upon the occurrence of certain change of control events specified in the applicable indentures.
On November 25, 2024, the Company announced EQM's commencement of a tender offer (the EQM Tender Offer) to purchase certain of EQM's senior notes, subject to a maximum aggregate purchase price, excluding accrued and unpaid interest, of up to $1.275 billion, in accordance with acceptance priority levels correlating to the order in which the notes are listed as follows: EQM's 6.500% senior notes due 2048, EQM's 5.500% senior notes due 2028, EQM's 4.50% senior notes due 2029 and EQM's 7.500% senior notes due 2030. On December 10, 2024, the Company announced the early results of the EQM Tender Offer, including an increase of the maximum aggregate purchase price to $1.3 billion. On December 27, 2024, EQM used borrowings under the Bridge Credit Facility and cash on hand to fund the EQM Tender Offer. Refer to "Debt Repayments" for details. In accordance with the established acceptance priority levels, none of EQM's 7.500% senior notes due 2030 were purchased.

In conjunction with the EQM Tender Offer, EQM solicited consents from holders of its 6.500% senior notes due 2048 and 5.500% senior notes due 2028 (such notes, together, the Affected Notes) to amend that certain Indenture, dated as of August 1, 2014, solely with respect to the Affected Notes, by modifying the reporting covenant contained therein such that EQT would provide the financial statements and other information required thereby in lieu of EQM (the Proposed Amendment). Each holder who validly tendered Affected Notes pursuant to the EQM Tender Offer was deemed to have validly delivered its related consent to the Proposed Amendment, and, therefore, EQM received the requisite consents to effect the Proposed Amendment. On December 30, 2024, EQM and The Bank of New York Mellon Trust Company, N.A., as trustee for the Affected Notes, entered into that certain Sixth Supplemental Indenture containing the Proposed Amendment, which immediately became effective and operative upon such entry and applies to all holders of Affected Notes that remain outstanding.

On December 30, 2024, EQM used borrowings under the Bridge Credit Facility and cash on hand to redeem its 6.000% senior notes due 2025 and 4.125% senior notes due 2026. Refer to "Debt Repayments" for details.

As of December 31, 2024, aggregate maturities for EQM's senior notes were zero in 2025 and 2026, $1,400 million in 2027, $119 million in 2028, $1,343 million in 2029 and $1,680 million thereafter.

EQT's Senior Notes. The indentures governing EQT's long-term indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict, among other things, EQT's ability to incur, as applicable, indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. Certain of EQT's senior notes also include an offer to repurchase provision applicable upon the occurrence of certain change of control events specified in the applicable indentures.

On January 19, 2024, EQT issued $750 million aggregate principal amount of 5.750% senior notes due 2034. The Company used net proceeds of $742.0 million from the sale and issuance of such notes and cash on hand to prepay $750 million principal amount of the term loans outstanding under the Term Loan Facility.

As of December 31, 2024, aggregate maturities for EQT's senior notes were zero in 2025, $508 million in 2026, $1,170 million in 2027, $500 million in 2028, $318 million in 2029 and $1,860 million thereafter.

EQT's 1.75% Convertible Notes. In April 2020, EQT issued $500 million aggregate principal amount of 1.75% convertible senior notes (the Convertible Notes). The effective interest rate for the Convertible Notes was 2.4%.

On January 2, 2024, in accordance with the indenture governing the Convertible Notes (the Convertible Notes Indenture), EQT issued an irrevocable notice of redemption for all of the outstanding Convertible Notes and announced that EQT would redeem any of the Convertible Notes outstanding on January 17, 2024 in cash for 100% of the principal amount, plus accrued and unpaid interest on such Convertible Notes to, but excluding, such redemption date (the Redemption Price).

Pursuant to the Convertible Notes Indenture, between January 2, 2024 and the conversion deadline of 5:00 p.m., New York City time, on January 12, 2024, certain holders of the Convertible Notes exercised their right to convert their Convertible Notes prior to the redemption and validly surrendered an aggregate principal amount of $289.6 million of Convertible Notes. Based on a conversion rate of 69.0364 shares of EQT common stock per $1,000 principal amount of Convertible Notes, EQT issued to such holders an aggregate 19,992,482 shares of EQT common stock. Settlement of such Convertible Note conversion right exercises net of unamortized deferred issuance costs increased shareholder's equity by $285.6 million. The remaining $0.6 million in outstanding principal amount of Convertible Notes was redeemed on January 17, 2024 in cash for the Redemption Price.
Inclusive of January 2024 settlements of Convertible Notes conversion right exercises that were exercised in December 2023, during January 2024, EQT settled $290.2 million aggregate principal amount of Convertible Notes conversion right exercises by issuing an aggregate 20,036,639 shares of EQT common stock to the converting holders at an average conversion price of $38.03.

Settlement and Termination of Capped Call Transactions. In connection with, but separate from, the issuance of the Convertible Notes, in 2020, EQT entered into capped call transactions (the Capped Call Transactions) with certain financial institutions (the Capped Call Counterparties) to reduce the potential dilution to EQT common stock upon any conversion of Convertible Notes at maturity and/or offset any cash payments that the Company is required to make in excess of the principal amount of such converted notes. The Capped Call Transactions had an initial strike price of $15.00 per share of EQT common stock and an initial cap price of $18.75 per share of EQT common stock, each of which were subject to certain customary adjustments, including adjustments as a result of EQT paying dividends on its common stock, and were set to expire in April 2026. The Company recorded the cost to purchase the Capped Call Transactions of $32.5 million as a reduction to shareholders' equity.

On January 18, 2024, EQT entered into separate termination agreements with each of the Capped Call Counterparties, pursuant to which the Capped Call Counterparties paid EQT an aggregate $93.3 million (the Termination Payments), and the Capped Call Transactions were terminated. EQT received the Termination Payments on January 22, 2024. The Termination Payments were recorded as an increase to shareholders' equity.
v3.25.0.1
Investments in Unconsolidated Entities
 12 Months Ended
Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]  
Investments in Unconsolidated Entities The Midstream Joint Venture Transaction
On September 24, 2024, the Company formed PipeBox LLC (the Midstream Joint Venture) as a wholly-owned subsidiary of EQM. On November 22, 2024, EQM entered into a contribution agreement (the Contribution Agreement) with an affiliate of Blackstone Credit & Insurance (the BXCI Affiliate).

On December 30, 2024, pursuant to the Contribution Agreement, EQM and certain of its affiliates contributed to the Midstream Joint Venture the following assets in exchange for 364,285,715 Class A Units in the Midstream Joint Venture: (i) EQM's ownership interest in the MVP (via EQM's Series A ownership interest in the MVP Joint Venture), (ii) EQM's regulated transmission and storage assets (including those owned by Equitrans, L.P.), and (iii) EQM's Hammerhead Pipeline System (a 1.6 Bcf per day gathering header pipeline designed to connect natural gas produced in Pennsylvania and West Virginia to the MVP, Texas Eastern Transmission and Eastern Gas Transmission). In addition, pursuant to the Contribution Agreement, on December 30, 2024, the BXCI Affiliate contributed to the Midstream Joint Venture $3.5 billion of cash, net of certain transaction fees and expenses, in exchange for a noncontrolling equity interest of 350,000,000 Class B Units in the Midstream Joint Venture (such contributions by EQM and the BXCI Affiliate, collectively, the Midstream Joint Venture Transaction).

The Midstream Joint Venture Transaction was accounted for as a sale of interest in a subsidiary without a loss of control. The Company recorded a $3.5 billion increase in noncontrolling interest in consolidated subsidiaries and a $77.5 million decrease to common shareholders' equity, inclusive of transaction-related expenses incurred by the Company and a $13.3 million deferred tax asset.

In addition, on December 30, 2024, EQT (solely for the limited purposes set forth therein), EQM, the BXCI Affiliate and the Midstream Joint Venture entered into an amended and restated limited liability company agreement of the Midstream Joint Venture (the JV Agreement). The JV Agreement provides for, among other things, quarterly distributions of available cash flow to the Midstream Joint Venture's unitholders, of which EQM, as Class A Unitholder, will receive 40% and the BXCI Affiliate, as Class B Unitholder, will receive 60% until the Base Return (as defined in the JV Agreement) has been achieved. After the Base Return has been achieved and until the 8th anniversary of the closing of the Midstream Joint Venture Transaction of December 30, 2024, 100% of the Midstream Joint Venture's distributions, including in a liquidation or sale of the Midstream Joint Venture, will be distributed to EQM as Class A Unitholder and zero percent will be distributed to the BXCI Affiliate as Class B Unitholder; after the Base Return has been achieved and from the 8th anniversary of December 30, 2024 and thereafter, no less than 95% of the Midstream Joint Venture's distributions, including in a liquidation or sale of the Midstream Joint Venture, will be distributed to EQM as Class A Unitholder, and up to 5% of the Midstream Joint Venture's distributions will be distributed to the BXCI Affiliate as Class B Unitholder (with specific distribution percentages determined based on the BXCI Affiliate's ownership of Class B Units as of the time of such distribution).
Based on the governing provisions of the JV Agreement, EQT's management determined that the allocation of income between the Company and the BXCI Affiliate should be based on the change in the investors claim on the Midstream Joint Venture's book value. Under this method, the Company recognizes net income/loss attributable to the noncontrolling interest based on changes to the amount that each member would hypothetically receive at each balance sheet date under the JV Agreement's liquidation provisions, assuming that the net assets of the Midstream Joint Venture were liquidated at the recorded amounts, after taking into account any capital transactions between the Company and the BXCI Affiliate.

The Company used the proceeds from the Midstream Joint Venture Transaction to repay outstanding borrowings, and interest thereon, under the Bridge Credit Facility (defined in Note 10) and the Term Loan Facility and a portion of outstanding borrowings under EQT's revolving credit facility as well as to pay certain transaction fees and expenses related to the Midstream Joint Venture Transaction and other related transactions. See Note 10.
Investments in Unconsolidated Entities
Equity Method Investments

The Company applies the equity method of accounting to its investments in entities that the Company does not have the power to direct the activities that most significantly affect those entities' economic performance but does have the ability to exercise significant influence over. The Company's pro-rata share of income/loss from the Company's equity method investments is recorded in (income) loss from investments in the Statements of Consolidated Operations.

The table below summarizes the Company's equity method investments.
December 31, 2024December 31, 2023
Ownership InterestCarrying ValueOwnership InterestCarrying Value
(Thousands)(Thousands)
MVP Joint Venture (a):
The MVP (b)49.3 %$3,469,438 — %$— 
MVP Southgate47.2 %65,292 — %— 
Total MVP Joint Venture3,534,730 — 
Laurel Mountain Midstream, LLC (c)31 %28,757 31 %39,923 
WATT Fuel Cell Corporation (d)15.63 %14,533 15.43 %16,700 
Yellowbird Energy LLC (e)50 %6,135 — %— 
Total$3,584,155 $56,623 

(a)Mountain Valley Pipeline, LLC (the MVP Joint Venture) is a Delaware series limited liability company joint venture formed among (i) with respect to Series A, an affiliate of EQT and affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating the MVP and (ii) with respect to Series B, a wholly-owned subsidiary of EQT and affiliates of NextEra Energy, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating MVP Southgate.
(b)As discussed in Note 8, upon the completion of the Midstream Joint Venture Transaction, the Company contributed its interest in the MVP (via its Series A ownership interest in the MVP Joint Venture) to the Midstream Joint Venture.
(c)Laurel Mountain Midstream, LLC is a natural gas gathering and processing joint venture formed among the Company, Williams Companies Inc. and certain other energy companies.
(d)Watt Fuel Cell Corporation is a developer and manufacturer of solid oxide fuel cell systems that operate on common, readily available fuels such as natural gas and propane.
(e)Yellowbird Energy LLC is a joint venture formed in 2024 between a subsidiary of EQT and a third-party investor.
The MVP. The MVP is a 303-mile long, 42-inch diameter natural gas interstate pipeline with a total capacity of 2.0 Bcf per day that spans from the Company's transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia. Following receipt of authorization from the Federal Energy Regulatory Commission (the FERC), the MVP entered into service on June 14, 2024 and became available for interruptible or short-term firm transportation service. On July 1, 2024, the MVP commenced long-term firm capacity obligations. A wholly-owned subsidiary of EQM is the operator of the MVP.

Estimated total project cost of the MVP is approximately $8.1 billion, including contingency and excluding AFUDC during construction. Of this amount, $142.8 million was contributed by the Company following the completion of the Equitrans Midstream Merger.

The Company has a negative basis difference between the carrying value of its equity method investment in the MVP and its proportionate share of the MVP's net assets (composed of fixed assets). The basis difference is accreted over the useful life of the fixed assets, with accretion expense presented in (income) loss from investments in the Company's Statement of Consolidated Operations. As of December 31, 2024, the basis difference, net of accretion, was $1.3 billion.
For the year ended December 31, 2024, the Company's Series A ownership interest (with respect to the MVP) in the MVP Joint Venture was significant as defined by the SEC's Regulation S-X Rule 1-02(w). Accordingly, pursuant to Regulation S-X Rule 4-08(g), the following table presents summarized financial information of the MVP Joint Venture in relation to the MVP for the period beginning on July 22, 2024 and ending December 31, 2024 and as of December 31, 2024.
 July 22, 2024 to
December 31, 2024
(Thousands)
Operating revenues$247,360 
Operating income$126,202 
Net income$129,773 
December 31, 2024
(Thousands)
Current assets$204,028 
Noncurrent assets9,535,975 
Total assets$9,740,003 
Current liabilities$69,303 
Noncurrent liabilities1,514 
Total liabilities70,817 
Members' equity9,669,186 
Total liabilities and members' equity$9,740,003 
MVP Southgate. MVP Southgate is a contemplated interstate pipeline that was approved by the FERC. The pipeline was initially designed to extend approximately 75 miles from the MVP in Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina using 24-inch and 16-inch diameter pipe.

In December 2023, the MVP Joint Venture entered into precedent agreements with Public Service Company of North Carolina, Inc. and Duke Energy Carolinas, LLC. The precedent agreements contemplate a modified project and, among other things, describe certain conditions precedent to the parties' respective obligations regarding MVP Southgate. As modified, the natural gas interstate pipeline would extend approximately 31 miles from the terminus of the MVP in Pittsylvania County, Virginia to planned new delivery points in Rockingham County, North Carolina using 30-inch diameter pipe and have a targeted capacity of 550,000 dekatherms per day. The proposed 31-mile route passes through a portion of the Southern Virginia Mega Site at Berry Hill, which is one of the largest business parks on the East Coast.
On February 3, 2025, the MVP Joint Venture filed an application with the FERC seeking to amend its existing Certificate of Public Convenience and Necessity to reflect the amended project. The Company expects a wholly-owned subsidiary of EQM to operate MVP Southgate upon its completion, which is targeted for June 2028. MVP Southgate is estimated to have a total cost of approximately $370 million to $430 million, excluding AFUDC and certain costs incurred for purposes of the originally certificated project, of which the Company will fund its proportionate share through capital contributions to the MVP Joint Venture.

Pursuant to the MVP Joint Venture's limited liability company agreement and upon the closing of the Equitrans Midstream Merger, the Company is obligated to provide performance assurances with respect to MVP Southgate that may take the form of a guarantee from EQM (provided that, in accordance with the requirements of the MVP Joint Venture's limited liability company agreement, EQM's debt is assigned an investment grade credit rating), a letter of credit or cash collateral. Upon receipt of the FERC's initial release to begin construction of MVP Southgate, the Company will be obligated to provide performance assurance in an amount equal to 33% of its share of MVP Southgate's remaining capital commitments under the applicable construction budget.

Investments in Equity Securities

The Company accounts for its investments in entities that the Company does not have the ability to exercise significant influence over as an investment in equity security. Changes in the fair value of the Company's investments in equity securities are recorded in (income) loss from investments and dividends received on the Company's investments in equity securities are recorded in other income in the Statements of Consolidated Operations.

The Investment Fund. As of December 31, 2024, the Company held an investment in a fund (the Investment Fund) that invests in companies that develop technology and operating solutions for exploration and production companies. As of December 31, 2024 and 2023, the fair value of the Company's investment in the Investment Fund was $33.2 million and $36.1 million, respectively, and was presented in investments in unconsolidated entities in the Consolidated Balance Sheets. The Company computes the fair value of the Company's investment in the Investment Fund using, as a practical expedient, the net asset value provided in the financial statements received from fund managers.

Equitrans Midstream. Prior to the Company's sale of all of its then-owned shares of Equitrans Midstream common stock in 2022, the Company accounted for its investment in Equitrans Midstream as an investment in equity security.
v3.25.0.1
Common Stock and Income Per Share
 12 Months Ended
Dec. 31, 2024
Earnings Per Share [Abstract]  
Common Stock and Income Per Share Common Stock and Income Per Share
 
On July 18, 2024, following approval by its shareholders, EQT amended its Restated Articles of Incorporation to increase the authorized number of shares of EQT common stock from 640,000,000 shares to 1,280,000,000 shares.

As of December 31, 2024, the Company had reserved 19.3 million shares of authorized and unissued EQT common stock for stock compensation plans.

On December 13, 2021, the Company announced that its Board of Directors approved a share repurchase program (the Share Repurchase Program) authorizing the Company to repurchase shares of outstanding EQT common stock for an aggregate purchase price of up to $1 billion, excluding fees, commissions and expenses. On September 6, 2022, the Company announced that its Board of Directors approved a $1 billion increase to the Share Repurchase Program, pursuant to which approval the Company is authorized to repurchase shares of outstanding EQT common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses. The Share Repurchase Program was originally scheduled to expire on December 31, 2023; however, on April 26, 2023, the Company announced that its Board of Directors approved a one-year extension of the Share Repurchase Program, and, on December 18, 2024, the Company announced that its Board of Directors approved an additional two-year extension of the Share Repurchase Program. As a result of such extension, the Share Repurchase Program will expire on December 31, 2026, but it may be suspended, modified or discontinued at any time without prior notice.
From the Share Repurchase Program's inception and through December 31, 2024, the Company has purchased shares under the Share Repurchase Program for an aggregate purchase price of $622.1 million, excluding fees, commissions and expenses. The table below summarizes the Company's share repurchases under the Share Repurchase Program for the years ended December 31, 2023 and 2022. The Company did not repurchase any equity securities during the year ended December 31, 2024.
Total number of shares purchasedAggregate purchase price (a)Average price paid per share (a)
(Millions)
Year Ended December 31, 202213,139,641 $392.7 $29.89 
Year Ended December 31, 20235,906,159 200.0 $33.86 
Total19,045,800 $592.7 

(a)Excludes fees and broker commissions.

See Note 10 for a discussion of the Company's issuance of shares of EQT common stock for its settlement of Convertible Notes conversion right exercises.

In July 2024, the Company issued 152,427,848 shares of EQT common stock as part of the consideration for the Equitrans Midstream Merger described in Note 6.

In August 2023, the Company issued 49,599,796 shares of EQT common stock as part of the consideration for the Tug Hill and XcL Midstream Acquisition described in Note 6.

Income Per Share. Basic income per share is computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares outstanding during the period. Diluted income per share is computed by dividing the sum of net income attributable to EQT Corporation plus the applicable numerator adjustments by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards as well as, prior to their redemption, the Convertible Notes. Purchases of treasury shares are calculated using the average share price of EQT common stock during the period. Prior to their redemption, the Company used the if-converted method to calculate the impact of the Convertible Notes on diluted income per share.

The table below provides the computation for basic and diluted income per share.
Years Ended December 31,
202420232022
(Thousands, except per share amounts)
Net income attributable to EQT Corporation – Basic income available to shareholders$230,577 $1,735,232 $1,770,965 
Add back: Interest expense on Convertible Notes, net of tax86 7,551 8,019 
Diluted income available to shareholders$230,663 $1,742,783 $1,778,984 
Weighted average common stock outstanding – Basic509,597 380,902 370,048 
Options, restricted stock, performance awards and stock appreciation rights
4,625 5,232 5,731 
Convertible Notes371 27,090 30,716 
Weighted average common stock outstanding – Diluted514,593 413,224 406,495 
Income per share of common stock attributable to EQT Corporation:
Basic$0.45 $4.56 $4.79 
Diluted$0.45 $4.22 $4.38 
v3.25.0.1
Share-Based Compensation Plans
 12 Months Ended
Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]  
Share-Based Compensation Plans Share-Based Compensation Plans
The following table summarizes the Company's share-based compensation expense.
 Years Ended December 31,
 202420232022
 (Thousands)
Incentive Performance Share Unit Programs$20,919 $23,915 $23,443 
Restricted stock awards25,473 20,119 23,028 
Stock appreciation rights— 4,056 17,406 
Other programs, including non-employee director awards3,596 3,110 3,534 
Total share-based compensation expense (a)$49,988 $51,200 $67,411 
         
(a)For the years ended December 31, 2024 and 2023, share-based compensation expense of $105.4 million and $3.6 million, respectively, was included in other operating expenses. Share-based compensation expense for 2024 related primarily to the Equitrans Midstream Merger. There were no such costs in 2022.

The Company typically elects to fund awards paid in stock through stock acquired by the Company in the open market or from any other person, issued directly by the Company or any combination of the foregoing. Prior to 2023, the Company typically used treasury stock to fund awards paid in stock.

Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2024 and December 31, 2022 was $5.1 million and $15.9 million, respectively. There was no cash received from exercises under all share-based payment arrangements for employees and directors for the year ended December 31, 2023. During the years ended December 31, 2024, 2023 and 2022, share-based payment arrangements paid in stock generated tax benefits of $7.7 million, $16.5 million and $4.1 million, respectively. Cash paid for taxes related to net settlement of share-based incentive awards for the years ended December 31, 2024, 2023 and 2022 were $102.9 million, $41.8 million and $24.8 million, respectively.

Incentive Performance Share Unit Programs

The Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) has adopted the following programs under each respective Long-Term Incentive Plan (LTIP):
•2020 Incentive Performance Share Unit Program (2020 Incentive PSU Program) under the 2019 LTIP;
•2021 Incentive Performance Share Unit Program (2021 Incentive PSU Program) under the 2020 LTIP;
•2022 Incentive Performance Share Unit Program (2022 Incentive PSU Program) under the 2020 LTIP;
•2023 Incentive Performance Share Unit Program (2023 Incentive PSU Program) under the 2020 LTIP; and
•2024 Incentive Performance Share Unit Program (2024 Incentive PSU Program) under the 2020 LTIP.

The programs noted above are collectively referred to as the Incentive PSU Programs and all granted equity awards.

The Incentive PSU Programs were established to provide long-term incentive opportunities to executives and key employees to further align their interests with those of the Company's shareholders and with the strategic objectives of the Company. The performance period for each of the awards under the Incentive PSU Programs is 36 months, with vesting occurring upon payment following the expiration of the performance period.

Executive performance incentive program awards granted in year 2020 are earned based on:
•adjusted well costs;
•adjusted free cash flow; and
•the level of total shareholder return relative to a predefined peer group.

Executive performance incentive program awards granted in year 2021 are earned based on:
•the level of absolute total shareholder return and total shareholder return relative to a predefined peer group.

Executive performance incentive program awards granted in year 2022 are earned based on:
•the level of absolute total shareholder return and total shareholder return relative to a predefined peer group; and
•the Company's performance in achieving its 2025 net zero Scopes 1 and 2 emissions target.
Executive performance incentive program awards granted in years 2023 and 2024 are earned based on:
•the level of absolute total shareholder return and total shareholder return relative to a predefined peer group.

The payout factor for the 2020 Incentive PSU Program varied between zero to 150% of the number of outstanding units contingent upon the performance metrics listed above. The 2021 Incentive PSU Program, 2023 Incentive PSU Program and 2024 Incentive PSU Program have a payout factor that ranges from zero to 200% and the 2022 Incentive PSU Program has a payout factor that ranges from zero to 220% (which includes the Company's performance in achieving its 2025 net zero Scopes 1 and 2 emissions target). The Company recorded the 2020 Incentive PSU Program, the 2021 Incentive PSU Program, the 2022 Incentive PSU Program, the 2023 Incentive PSU Program and the 2024 Incentive PSU Program as equity awards using a grant date fair value determined through a Monte Carlo simulation, which projected the share price for the Company and its peers at the end point of the performance period. The expected share prices were generated using each company's annual volatility for the expected term and the commensurate three-year risk-free rate shown in the chart below. As the Incentive PSU Programs include a performance condition that affects the number of shares that will ultimately vest, the Monte Carlo simulation computed the grant date fair value for each possible performance condition outcome on the grant date. The Company reevaluates the then-probable outcome at the end of each reporting period to record expense at the probable outcome grant date fair value as applicable. Vesting of the units under each Incentive PSU Program occurs upon payment after the end of the performance period.

The following table summarizes Incentive PSU Programs to be settled in stock and classified as equity awards.
Incentive PSU Programs – Equity SettledNonvested SharesWeighted Average
Fair Value		Aggregate Fair Value
Outstanding at December 31, 2021
2,754,648 $16.08 $44,281,509 
Granted in Period575,120 29.73 (a)17,098,318 
Granted from Multiplier162,183 29.45 4,776,289 
Vested(625,563)29.45 (18,422,830)
Forfeited(4,398)13.28 (58,405)
Outstanding at December 31, 20222,861,990 16.66 47,674,881 
Granted in Period404,790 38.79 15,701,804 
Granted from Multiplier409,383 6.56 2,685,552 
Vested(1,773,994)6.56 (11,637,401)
Forfeited(70,616)37.59 (2,654,455)
Outstanding at December 31, 2023
1,831,553 28.27 51,770,381 
Granted in Period371,500 40.08 14,889,720 
Granted from Multiplier451,805 23.55 10,640,008 
Vested(1,355,415)23.55 (31,920,023)
Forfeited(7,092)45.94 (325,806)
Outstanding at December 31, 2024
1,292,351 $34.86 $45,054,280 

(a)The 2022 Incentive PSU Program was granted as a liability award and converted to an equity award in April 2022. The fair value determined through a Monte Carlo simulation at the time of conversion totaled $75.32 per share, which was an increase of $45.59 per share from fair value determined through a Monte Carlo simulation at the grant date.

Total capitalized compensation costs related to the Incentive PSU Programs for the years ended December 31, 2024, 2023 and 2022 were $0.5 million, $0.6 million and $0.6 million, respectively. As of December 31, 2024, $10.2 million and $4.8 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2024 Incentive PSU Program and 2023 Incentive PSU Program, respectively, was expected to be recognized over the remainder of the performance periods.
Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions at grant date:
 Incentive PSU Programs Issued During the Years Ended December 31,
20242023 (a)20222021 (a)2020 (b)
Risk-free rate4.35%4.16%1.52%0.18%1.22%
Volatility factor48.82%59.31%65.38%72.50%45.41%
Expected term3 years3 years3 years3 years3 years

(a)There were two grant dates for the 2023 Incentive PSU Program and the 2021 Incentive PSU Program. Amounts shown represent weighted average.
(b)There were three grant dates for the 2020 Incentive PSU Program. Amounts shown represent weighted average.

Dividends paid from the beginning of the performance period will be cumulatively added as additional shares of common stock; therefore, dividend yield is not applicable.

Restricted Stock Unit Awards

The Company granted 982,990, 953,270 and 1,288,430 restricted stock unit equity awards to employees of the Company during the years ended December 31, 2024, 2023 and 2022, respectively. Awards are subject to a three-year graded vesting schedule commencing with the date of grant, assuming continued service through each vesting date. For the years ended December 31, 2024, 2023 and 2022, the weighted average fair value of these restricted stock unit grants, based on the grant date fair value of EQT common stock, was approximately $34.54, $31.88 and $21.65, respectively.

In conjunction with the Equitrans Midstream Merger, the Company assumed all outstanding and unvested share-based compensation awards of Equitrans Midstream and converted those assumed awards into 5,175,814 restricted stock unit equity awards. Employees who were terminated on the closing date were immediately vested in their Company awards. Company awards of those employees who continued employment with the Company under a transition agreement will vest upon the earlier of (i) the end of the vesting period set forth in the original award agreement or (ii) the end of such employee's employment period set forth in their transition agreement, in both cases subject to continued service through such date. Company awards of those employees who continued employment with the Company on an at will basis will vest in accordance with the vesting period set forth in the original award agreement, assuming continued service through such date. The fair value of these converted restricted stock awards was approximately $106.3 million of post-combination expense as of December 31, 2024.

The total fair value of restricted stock unit equity awards vested during the years ended December 31, 2024, 2023 and 2022 was $155.5 million, $23.5 million and $16.6 million, respectively. Total capitalized compensation costs related to the restricted stock unit equity awards was $9.6 million, $5.7 million and $6.6 million for the years ended December 31, 2024, 2023 and 2022, respectively.
 
As of December 31, 2024, $44.1 million of unrecognized compensation cost related to nonvested restricted stock unit equity awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.0 year.
The following table summarizes restricted stock unit equity award activity as of December 31, 2024.
Restricted Stock – Equity SettledNonvested SharesWeighted Average
Fair Value		Aggregate Fair Value
Outstanding at January 1, 20223,104,281 $12.58 $39,056,435 
Granted1,288,430 21.65 27,893,331 
Vested(1,368,577)12.16 (16,644,859)
Forfeited(97,189)15.56 (1,512,333)
Outstanding at December 31, 2022
2,926,945 16.67 48,792,574 
Granted953,270 31.88 30,389,954 
Vested(1,544,968)15.20 (23,482,927)
Forfeited(117,445)24.52 (2,879,751)
Outstanding at December 31, 2023
2,217,802 23.82 52,819,850 
Granted982,990 34.54 33,950,507 
Vested(4,861,796)31.98 (155,480,899)
Conversion of Equitrans Midstream awards5,175,814 35.88 185,708,206 
Forfeited(90,641)31.92 (2,893,279)
Outstanding at December 31, 2024
3,424,169 $33.32 $114,104,385 

Non-Qualified Stock Options
 
The fair value of the Company's option grants was estimated at the grant date using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the year ended December 31, 2020. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of grant. The dividend yield is based on the dividend yield of EQT common stock at the time of grant. Expected volatilities are based on historical volatility of EQT common stock. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. There were no stock options granted in 2024, 2023 and 2022.
 Year Ended
December 31, 2020
Risk-free interest rate1.10 %
Dividend yield— %
Volatility factor60.00 %
Expected term4 years
Number of Options Granted1,000,000 
Weighted Average Grant Date Fair Value$1.61 
 
The total intrinsic value of options exercised during the years ended December 31, 2024, 2023 and 2022 was $0.7 million, $1.4 million and $20.2 million, respectively.

The following table summarizes option activity as of December 31, 2024.
Non-Qualified Stock OptionsSharesWeighted Average
Exercise Price		Weighted Average
Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 20241,523,536 $18.75 
Expired(193,726)46.21   
Exercised(134,474)37.91 
Outstanding and Exercisable at December 31, 20241,195,336 $12.14 2.3 years$40,604,986 
Stock Appreciation Rights

During 2020, the Company granted stock appreciation rights subject to certain performance conditions, such as adjusted well costs and adjusted free cash flow. The participant was entitled to receive, upon exercise, a number of shares of EQT common stock, cash or a combination of the two, based upon the excess of the fair market value as of the date of exercise over a base price of $10.00.

The awards were accounted for as liability awards and, as such, compensation expense was recorded based on the fair value of the awards as remeasured at the end of each reporting period. Assumptions at grant date are indicated in the table below. The risk-free rate was based on the U.S. Treasury yield curve in effect at the reporting date. The dividend yield was based on the dividend yield of EQT common stock at the reporting date. Expected volatilities were based on a 50-50 blend of the expected term-matched historical volatility as of the valuation date and the weighted-average implied volatility from thirty days prior to the valuation date. The expected term represents the period of time between the valuation date and the midpoint of the exercise window.
2020 Stock Appreciation Rights
Risk-free interest rate0.30 %
Dividend yield— %
Volatility factor67.50 %
Expected term3.28 years
Number of Stock Appreciation Rights Granted1,240,000
Weighted Average Grant Date Fair Value$2.61 
Total Intrinsic Value of Exercises$— 

All outstanding stock appreciation rights were exercised during 2023. The total intrinsic value of stock appreciation rights exercised during the year ended December 31, 2023 was $33.4 million. There were no exercises in 2022.

Non-employee Directors' Share-Based Awards

The Company grants to non-employee directors restricted stock unit awards that vest on the date of the Company's annual meeting of shareholders immediately following the grant of such awards. The restricted stock unit awards are settled in EQT common stock on the vesting date or, if elected by the director, following a director's termination of service on the Company's Board of Directors.

Awards granted prior to 2020 that are to be paid in cash are accounted for as liability awards and, as such, compensation expense is recorded based on the fair value of the awards as remeasured at the end of each reporting period. Awards to be settled in EQT common stock are accounted for as equity awards and, as such, compensation expense is recorded based on the fair value of the awards at the grant date fair value. A total of 564,968 non-employee director share-based awards, including accrued dividends, were outstanding as of December 31, 2024. A total of 70,930, 66,300 and 44,800 share-based awards were granted to non-employee directors during the years ended December 31, 2024, 2023 and 2022, respectively. The weighted average fair value of these grants, based on the closing price of EQT common stock on the business day prior to the grant date, was $36.14, $33.31 and $43.97 for the years ended December 31, 2024, 2023 and 2022, respectively.

2025 Awards

Effective in 2025, the Compensation Committee adopted the 2025 Incentive Performance Share Unit Program (2025 Incentive PSU Program) under the 2020 LTIP. The 2025 Incentive PSU Program was established to align the interests of executives and key employees with the interests of shareholders and the strategic objectives of the Company. A total of 374,800 share units were granted under the 2025 Incentive PSU Program. The payout of the share units will vary between zero and 200% of the number of outstanding units contingent upon the Company's absolute total shareholder return and total shareholder return relative to a predefined peer group over the period of January 1, 2025 through December 31, 2027.

Effective in 2025, the Compensation Committee granted 1,111,480 restricted stock unit equity awards that follow a three-year graded vesting schedule commencing with the date of grant, assuming continued employment through each vesting date. The share total includes the Company's "equity-for-all" program, instituted in 2021, pursuant to which the Company grants equity awards to all permanent employees.
v3.25.0.1
Leases
 12 Months Ended
Dec. 31, 2024
Leases [Abstract]  
Leases Leases
The Company leases drilling rigs, facilities (including a water storage facility), vehicles and drilling and compression equipment.

To determine the present value of its right-of-use assets and lease liabilities, the Company calculates a discount rate per lease contract based on an estimate of the rate of interest that the Company would pay to borrow (on a collateralized basis, over a similar term) an amount equal to the lease payment obligation.

The Company has elected a practical expedient to forgo application of the recognition requirements under ASU 2016-02, Leases, to short-term leases; as such, short-term leases are not recorded in the Consolidated Balance Sheets. In addition, the Company has elected a practical expedient to account for lease and nonlease components together as a lease.

Certain of the Company's lease contracts include variable lease payments, such as payments for property taxes and other operating and maintenance expenses and payments based on asset use, which are not included in the lease cost or the present value of the right-of-use asset or lease liability. Certain of the Company's lease contracts provide renewal periods at the Company's option; if a renewal period option is reasonably assured to be exercised, the associated lease payment obligation is included in the present value of the right-of-use asset and lease liability. As of December 31, 2024 and 2023, the Company was not a lessor.

The following table summarizes the Company's lease costs.
Years Ended December 31,
202420232022
(Thousands)
Operating lease costs$41,991 $26,755 $19,922 
Finance lease costs5,546 2,414 1,716 
Variable and short-term lease costs33,475 24,151 13,726 
Total lease costs (a)$81,012 $53,320 $35,364 

(a)Includes drilling rig lease costs capitalized to property, plant and equipment of $50.5 million, $40.8 million and $25.4 million, respectively, of which $33.1 million, $24.5 million and $17.7 million, respectively, were operating lease costs for the years ended December 31, 2024, 2023 and 2022.

For the years ended December 31, 2024, 2023 and 2022, cash paid for operating lease liabilities and reported in net cash provided by operating activities in the Statements of Consolidated Cash Flows was $13.6 million, $10.1 million and $10.3 million, respectively. For the years ended December 31, 2024, 2023 and 2022, cash paid for finance lease liabilities and reported in net cash used in financing activities in the Statements of Consolidated Cash Flows was $4.2 million, $2.3 million and $1.8 million, respectively.

For the Company's operating leases, as of December 31, 2024, 2023 and 2022, the weighted average remaining term was 3.4 years, 1.6 years and 1.8 years, respectively, and the weighted average discount rate was 5.3%, 4.7% and 4.5%, respectively. For the Company's finance leases, as of December 31, 2024, 2023 and 2022, the weighted average remaining term was 6.8 years, 3.8 years and 3.3 years, respectively, and the weighted average discount rate was 5.1%, 4.8% and 3.9%, respectively.
The Company records its right-of-use assets in other assets and the current and noncurrent portions of its lease liabilities in other current liabilities and other liabilities and credits, respectively, in the Consolidated Balance Sheets. The following table summarizes the Company's right-of-use assets and lease liabilities.
December 31,
20242023
(Thousands)
Right-of-Use Assets
Operating$60,496 $42,338 
Finance34,803 6,494 
Total right-of-use assets$95,299 $48,832 
Lease Liabilities
Current lease liabilities
Operating$36,275 $43,891 
Finance5,603 2,489 
Total current lease liabilities41,878 46,380 
Noncurrent lease liabilities
Operating29,391 8,443 
Finance29,263 3,754 
Total noncurrent lease liabilities58,654 12,197 
Total lease liabilities$100,532 $58,577 

The following table summarizes the Company's lease payment obligations as of December 31, 2024.
OperatingFinanceTotal
(Thousands)
2025$38,592 $7,192 $45,784 
20268,289 6,420 14,709 
20277,623 6,057 13,680 
20286,480 4,806 11,286 
20295,804 4,523 10,327 
Thereafter5,207 12,126 17,333 
Total lease payment obligations71,995 41,124 113,119 
Less: Imputed interest6,329 6,258 12,587 
Present value of lease liabilities$65,666 $34,866 $100,532 
Leases Leases
The Company leases drilling rigs, facilities (including a water storage facility), vehicles and drilling and compression equipment.

To determine the present value of its right-of-use assets and lease liabilities, the Company calculates a discount rate per lease contract based on an estimate of the rate of interest that the Company would pay to borrow (on a collateralized basis, over a similar term) an amount equal to the lease payment obligation.

The Company has elected a practical expedient to forgo application of the recognition requirements under ASU 2016-02, Leases, to short-term leases; as such, short-term leases are not recorded in the Consolidated Balance Sheets. In addition, the Company has elected a practical expedient to account for lease and nonlease components together as a lease.

Certain of the Company's lease contracts include variable lease payments, such as payments for property taxes and other operating and maintenance expenses and payments based on asset use, which are not included in the lease cost or the present value of the right-of-use asset or lease liability. Certain of the Company's lease contracts provide renewal periods at the Company's option; if a renewal period option is reasonably assured to be exercised, the associated lease payment obligation is included in the present value of the right-of-use asset and lease liability. As of December 31, 2024 and 2023, the Company was not a lessor.

The following table summarizes the Company's lease costs.
Years Ended December 31,
202420232022
(Thousands)
Operating lease costs$41,991 $26,755 $19,922 
Finance lease costs5,546 2,414 1,716 
Variable and short-term lease costs33,475 24,151 13,726 
Total lease costs (a)$81,012 $53,320 $35,364 

(a)Includes drilling rig lease costs capitalized to property, plant and equipment of $50.5 million, $40.8 million and $25.4 million, respectively, of which $33.1 million, $24.5 million and $17.7 million, respectively, were operating lease costs for the years ended December 31, 2024, 2023 and 2022.

For the years ended December 31, 2024, 2023 and 2022, cash paid for operating lease liabilities and reported in net cash provided by operating activities in the Statements of Consolidated Cash Flows was $13.6 million, $10.1 million and $10.3 million, respectively. For the years ended December 31, 2024, 2023 and 2022, cash paid for finance lease liabilities and reported in net cash used in financing activities in the Statements of Consolidated Cash Flows was $4.2 million, $2.3 million and $1.8 million, respectively.

For the Company's operating leases, as of December 31, 2024, 2023 and 2022, the weighted average remaining term was 3.4 years, 1.6 years and 1.8 years, respectively, and the weighted average discount rate was 5.3%, 4.7% and 4.5%, respectively. For the Company's finance leases, as of December 31, 2024, 2023 and 2022, the weighted average remaining term was 6.8 years, 3.8 years and 3.3 years, respectively, and the weighted average discount rate was 5.1%, 4.8% and 3.9%, respectively.
The Company records its right-of-use assets in other assets and the current and noncurrent portions of its lease liabilities in other current liabilities and other liabilities and credits, respectively, in the Consolidated Balance Sheets. The following table summarizes the Company's right-of-use assets and lease liabilities.
December 31,
20242023
(Thousands)
Right-of-Use Assets
Operating$60,496 $42,338 
Finance34,803 6,494 
Total right-of-use assets$95,299 $48,832 
Lease Liabilities
Current lease liabilities
Operating$36,275 $43,891 
Finance5,603 2,489 
Total current lease liabilities41,878 46,380 
Noncurrent lease liabilities
Operating29,391 8,443 
Finance29,263 3,754 
Total noncurrent lease liabilities58,654 12,197 
Total lease liabilities$100,532 $58,577 

The following table summarizes the Company's lease payment obligations as of December 31, 2024.
OperatingFinanceTotal
(Thousands)
2025$38,592 $7,192 $45,784 
20268,289 6,420 14,709 
20277,623 6,057 13,680 
20286,480 4,806 11,286 
20295,804 4,523 10,327 
Thereafter5,207 12,126 17,333 
Total lease payment obligations71,995 41,124 113,119 
Less: Imputed interest6,329 6,258 12,587 
Present value of lease liabilities$65,666 $34,866 $100,532 
v3.25.0.1
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies
 
Purchase Obligations

The Company has commitments to pay demand charges under long-term contracts and binding precedent agreements with various pipelines as well as charges for processing capacity to extract heavier liquid hydrocarbons from the natural gas stream. Aggregate future payments for such commitments as of December 31, 2024 were $13.6 billion, composed of $1.1 billion in 2025, $1.1 billion in 2026, $1.0 billion in 2027, $0.9 billion in 2028, $0.9 billion in 2029 and $8.6 billion thereafter.

In addition, the Company has commitments to pay for services related to its operations, including electric hydraulic fracturing services, and purchase equipment, materials and sand. Aggregate future payments for such commitments as of December 31, 2024 were $494.3 million, composed of $219.9 million in 2025, $148.4 million in 2026, $88.1 million in 2027 and $37.9 million in 2028.

See Note 14 for a summary of undiscounted future cash flows owed to lessors by the Company as lessee pursuant to contractual agreements in effect as of December 31, 2024.

Legal and Regulatory Proceedings

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings.

The Company evaluates its legal proceedings, including litigation and regulatory and governmental investigations and inquiries, on a regular basis and accrues a liability for such matters when the Company believes that a loss is probable and the amount of the loss can be reasonably estimated. Any such accruals are adjusted thereafter as appropriate to reflect changed circumstances. In the event the Company determines that (i) a loss to the Company is probable but the amount of the loss cannot be reasonably estimated, or (ii) a loss to the Company is less likely than probable but is reasonably possible, then the Company is required to disclose the matter herein, although the Company is not required to accrue such loss.

When able, the Company determines an estimate of reasonably possible losses or ranges of reasonably possible losses, whether in excess of any related accrued liability or where there is no accrued liability, for legal proceedings. In instances where such estimates can be made, any such estimates are based on the Company's analysis of currently available information and are subject to significant judgment and a variety of assumptions and uncertainties and may change as new information is obtained. The ultimate outcome of the matters described below, such as whether the likelihood of loss is remote, reasonably possible, or probable, or if and when the range of loss is reasonably estimable, is inherently uncertain. Furthermore, due to the inherent subjectivity of the assessments and unpredictability of outcomes of legal proceedings, any amounts accrued or estimated as possible losses may not represent the ultimate loss to the Company from the legal proceedings in question and the Company's exposure and ultimate losses may be higher, and possibly significantly so, than the amounts accrued or estimated.

Securities Class Action Litigation. On December 6, 2019, an amended putative class action complaint was filed in the United States District Court for the Western District of Pennsylvania by Cambridge Retirement System, Government of Guam Retirement Fund, Northeast Carpenters Annuity Fund, and Northeast Carpenters Pension Fund, on behalf of themselves and all those similarly situated, against EQT, and certain former executives and current and former board members of EQT (the Securities Class Action). The complaint alleges that certain statements made by EQT regarding its merger with Rice Energy Inc. in 2017 (the Rice Merger) were materially false and violated various federal securities laws. Pursuant to the complaint, the plaintiffs seek compensatory or rescissory damages in an unspecified amount for all damages allegedly sustained by the class as a result of alleged negative impacts to EQT stock price in 2018 and 2019.

Additionally, following the filing of the Securities Class Action complaint, several other lawsuits were filed in the United States District Court for the Western District of Pennsylvania and the Court of Common Pleas of Allegheny County, Pennsylvania by certain shareholders of EQT against EQT and certain former executives and current and former board members of EQT asserting substantially the same allegations as those raised in the Securities Class Action. These matters are currently pending, the majority of which have been stayed pending a ruling on dispositive motions in the Securities Class Action.
Following the commencement of the Securities Class Action, the parties engaged in fact and expert discovery. In June 2024, the discovery phase of the Securities Class Action was completed. On June 27, 2024, the parties to the Securities Class Action participated in a mediation (the Mediation), which did not result in resolution. A trial date for the Securities Class Action has not been determined.

In the second quarter of 2024, the Company recorded an accrual for estimated loss contingencies associated with the Securities Class Action in an amount equal to the settlement offer the Company tendered at the Mediation. Due to the inherent subjectivity of the assessments and unpredictability of outcomes of legal proceedings, the amount accrued for estimated losses associated with the Securities Class Action may not represent the ultimate loss to the Company, and the Company's exposure and ultimate losses may be higher, and possibly significantly so, than the amounts accrued or estimated. The amount accrued for such estimated losses is based on the Company's analysis of currently available information and is subject to significant judgment and a variety of assumptions and uncertainties and may change as new information is obtained. While the parties have completed discovery, various motions, including dispositive motions, have not yet been decided, the matters present meaningful legal uncertainties, and predicting the outcome depends on making assumptions about future decisions of courts and the behavior of other parties for which the Company does not currently have sufficient information. Given these uncertainties, the Company is unable at this time to reasonably estimate the range of possible additional losses above the amount accrued. The Company disputes the claims asserted in the Securities Class Action and related litigation and believes it has meritorious defenses, but unpredictability is inherent in litigation and the Company cannot predict the outcomes with any certainty.

With respect to the matters described above, the Company is unable at this time to estimate the losses that are reasonably possible to be incurred or a range of such losses due to various factors, including that the proceedings are still in their early stages and discovery is not complete; the matters present meaningful legal uncertainties; and predicting the outcome depends on making assumptions about future decisions of courts and the behavior of other parties for which the Company does not currently have sufficient information. The matters described above contain certain information related to claims against the Company as alleged in pleadings. While information of this type may provide insight into the potential magnitude of a matter, it does not necessarily represent the Company’s estimate of a probable or reasonably possible loss or the Company's judgment as to any currently appropriate accrual.

Regulatory and Environmental Matters. The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may result in the assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company's financial position, results of operations or liquidity. The Company has identified situations that require remedial action for which approximately $10.3 million was recorded in other liabilities and credits in the Consolidated Balance Sheet as of December 31, 2024.

Other Matters. In addition to the matters described above, the Company, in the normal course of business, is subject to various other pending and threatened legal proceedings in which claims for monetary damages or other relief are asserted. The Company does not anticipate, at the present time, that the ultimate aggregate liability, if any, arising out of such other legal proceedings will have a material adverse effect on the Company’s financial position, results of operations or liquidity.
v3.25.0.1
Concentrations of Credit Risk
 12 Months Ended
Dec. 31, 2024
Risks and Uncertainties [Abstract]  
Concentrations of Credit Risk Concentrations of Credit Risk
Revenues and related accounts receivable from the Company's Production segment operations are generated primarily from the sale of produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through the Company's transportation portfolio, including markets in the Gulf Coast, Midwest and Northeast United States and Canada. The Company also contracts with certain processors to market a portion of NGLs on behalf of the Company. The Company is not dependent on any single customer and believes that the loss of any one customer would not have an adverse effect on the Company's ability to sell its natural gas, NGLs and oil.
As of December 31, 2024 and 2023, approximately 96% and 93%, respectively, of the Company's sales of natural gas, NGLs and oil accounts receivable balances represented amounts due from non-end users. The Company manages the credit risk of sales to non-end users by limiting its dealings with only non-end users that meet the Company's criteria for credit and liquidity strength and by regularly monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a non-end user for that non-end user to meet the Company's credit criteria. The Company did not experience any significant defaults on sales of natural gas to non-end users during the years ended December 31, 2024, 2023 and 2022.

The Company is exposed to credit loss in the event of nonperformance by counterparties to its derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company's OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as the financial industry as a whole. The Company uses various processes and analyses to monitor and evaluate its credit risk exposures, including monitoring current market conditions and counterparty credit fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions primarily with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.
 
As of December 31, 2024, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts. During the year ended December 31, 2024, the Company made no adjustments to the fair value of its derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company's established fair value procedure. The Company monitors market conditions that may impact the fair value of its derivative contracts.

Revenues and related accounts receivable from the Company's Gathering and Transmission segments operations are generated predominantly from the transportation of natural gas in Pennsylvania and West Virginia. The Company is not dependent on any single third-party customer and believes that the loss of any one customer would not have an adverse effect on the Company's ability to generate revenues through its gathering, transmission and storage services.
v3.25.0.1
Natural Gas Producing Activities (Unaudited)
 12 Months Ended
Dec. 31, 2024
Extractive Industries [Abstract]  
Natural Gas Producing Activities (Unaudited) Natural Gas Producing Activities (Unaudited)
The following supplementary information presents a summary of the results of natural gas and oil activities in accordance with the successful efforts method of accounting for production activities.

Production Costs
 
The following tables present total aggregate capitalized costs and costs incurred related to natural gas, NGLs and oil production activities.
 December 31,
 20242023
 (Thousands)
Capitalized costs
Proved properties$31,986,473 $30,471,164 
Unproved properties1,563,440 2,039,431 
Total capitalized costs33,549,913 32,510,595 
Less: Accumulated depreciation and depletion12,489,317 10,734,099 
Net capitalized costs$21,060,596 $21,776,496 
Years Ended December 31,
202420232022
(Thousands)
Costs incurred (a)
Property acquisition:   
Proved properties (b)$410,805 $4,142,621 $82,276 
Unproved properties (c)98,007 575,130 113,523 
Exploration2,735 3,330 3,438 
Development1,848,000 1,782,428 1,298,665 

(a)Amounts for all years presented exclude costs for facilities, information technology and other corporate items. In addition, amounts for 2024 exclude midstream assets. Amounts for 2023 and 2022 include costs for midstream assets.
(b)Amounts in 2024 include $267.7 million and $74.7 million for wells and leases, respectively, received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $2,522.3 million, $757.6 million and $719.6 million for wells, midstream assets and leases, respectively, acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $40.5 million for leases acquired in the 2022 Asset Acquisition. See Note 6.
(c)Amounts in 2024 include $10.8 million for unproved properties received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $523.0 million for unproved properties acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $17.1 million for unproved properties acquired in the 2022 Asset Acquisition. See Note 6.

Results of Operations for Producing Activities

The following table presents the results of operations related to natural gas, NGLs and oil production.
Years Ended December 31,
202420232022
(Thousands)
Sales of natural gas, NGLs and oil$4,934,366 $5,044,768 $12,114,168 
Transportation and processing1,915,616 2,157,260 2,116,976 
Production377,007 254,700 300,985 
Operating and maintenance37,951 — — 
Exploration2,735 3,330 3,438 
Depreciation and depletion2,016,670 1,732,142 1,665,962 
(Gain) loss on sale/exchange of long-lived assets(764,431)17,445 (8,446)
Impairment and expiration of leases97,368 109,421 176,606 
Income tax expense316,377 187,463 1,987,323 
Results of operations from producing activities, excluding corporate overhead$935,073 $583,007 $5,871,324 

Reserve Information

Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.
The Company's estimate of proved natural gas, NGLs and oil reserves was prepared by Company engineers. The engineer primarily responsible for overseeing the preparation of the reserves estimate has 22 years of experience in the oil and gas industry and holds a bachelor's degree in petroleum engineering from the University of Oklahoma, a master's degree in business administration from Oklahoma City University and a Juris Doctor from the Oklahoma City University School of Law. To support the accurate and timely preparation and disclosure of its reserve estimates, the Company established internal controls over its reserve estimation processes and procedures, including the following: the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves are reviewed by management; division of interest and production volume are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserves reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and oil reserves are audited by Netherland, Sewell & Associates, Inc. (NSAI), an independent consulting firm hired by management. Since 1961, NSAI has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.

In the course of its audit, NSAI conducted a detailed review of 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company's interests as of December 31, 2024. NSAI conducted a detailed, well-by-well audit of all the Company's properties. The estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy and material balance were utilized in the evaluation of reserves. All of the Company's proved reserves are located in the United States.

The Company utilizes reliable technologies in the calculation of its proved undeveloped reserves. The technologies used in the estimation of the Company's proved undeveloped reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.

For all tables presented, NGLs and oil were converted at a rate of one Mbbl to approximately six million cubic feet (MMcf).
 Years Ended December 31,
 202420232022
 (MMcfe)
Natural gas, NGLs and oil   
Proved developed and undeveloped reserves:   
Balance at January 127,596,694 25,002,589 24,961,499 
Revision of previous estimates(1,079,677)(1,402,039)(654,618)
Purchase of hydrocarbons in place413,040 2,600,667 141,038 
Sale of natural gas in place(1,562,849)— — 
Extensions, discoveries and other additions3,125,620 3,411,750 2,494,713 
Production(2,228,159)(2,016,273)(1,940,043)
Balance at December 3126,264,669 27,596,694 25,002,589 
Proved developed reserves:
Balance at January 119,558,176 17,513,645 17,218,655 
Balance at December 3118,804,929 19,558,176 17,513,645 
Proved undeveloped reserves:
Balance at January 18,038,518 7,488,944 7,742,844 
Balance at December 317,459,740 8,038,518 7,488,944 
 Years Ended December 31,
 202420232022
 (MMcf)
Natural gas   
Proved developed and undeveloped reserves:   
Balance at January 125,795,134 23,824,887 23,523,665 
Revision of previous estimates(917,676)(1,461,305)(432,315)
Purchase of natural gas in place395,423 2,012,159 141,038 
Sale of natural gas in place(1,562,849)— — 
Extensions, discoveries and other additions2,921,638 3,326,736 2,434,543 
Production(2,086,441)(1,907,343)(1,842,044)
Balance at December 3124,545,229 25,795,134 23,824,887 
Proved developed reserves:   
Balance at January 118,186,432 16,541,017 16,152,083 
Balance at December 3117,440,191 18,186,432 16,541,017 
Proved undeveloped reserves:
Balance at January 17,608,702 7,283,870 7,371,582 
Balance at December 317,105,038 7,608,702 7,283,870 

 Years Ended December 31,
202420232022
(Mbbl)
NGLs   
Proved developed and undeveloped reserves:   
Balance at January 1285,345 186,141 225,792 
Revision of previous estimates(24,332)11,558 (33,955)
Purchase of NGLs in place2,529 90,604 — 
Extensions, discoveries and other additions30,391 13,592 9,610 
Production(22,025)(16,550)(15,306)
Balance at December 31271,908 285,345 186,141 
Proved developed reserves:  
Balance at January 1218,523 154,921 169,781 
Balance at December 31217,786 218,523 154,921 
Proved undeveloped reserves:
Balance at January 166,822 31,220 56,011 
Balance at December 3154,122 66,822 31,220 
 Years Ended December 31,
 202420232022
 (Mbbl)
Oil   
Proved developed and undeveloped reserves:   
Balance at January 114,915 10,142 13,846 
Revision of previous estimates(2,669)(1,680)(3,095)
Purchase of oil in place407 7,481 — 
Extensions, discoveries and other additions3,606 577 418 
Production(1,595)(1,605)(1,027)
Balance at December 3114,664 14,915 10,142 
Proved developed reserves:   
Balance at January 110,101 7,183 7,981 
Balance at December 319,669 10,101 7,183 
Proved undeveloped reserves:
Balance at January 14,814 2,959 5,865 
Balance at December 314,995 4,814 2,959 

The change in reserves during the year ended December 31, 2024 resulted from the following:

•Conversions of 2,637 billion cubic feet equivalent (Bcfe) of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 3,126 Bcfe, which exceeded 2024 production of 2,228 Bcfe. Extensions, discoveries and other additions included an increase of 2,414 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2024 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan, 498 Bcfe of proved undeveloped additions for previously proved undeveloped properties reclassified from unproved properties due to their addition to the Company's five-year development plan, positive revisions of 157 Bcfe from the extension of lateral lengths of proved undeveloped reserves and 57 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 925 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking primarily as a result of development schedule changes.
•Negative revisions of 87 Bcfe to proved undeveloped locations primarily related to revisions to lateral lengths and type curves.
•Positive revisions to proved undeveloped locations of 189 Bcfe due primarily to changes in ownership interests.
•Negative revisions of 65 Bcfe primarily from proved developed locations as a result of negative curve revisions.
•Negative revisions of 192 Bcfe from proved developed locations as a result of lower pricing, impacting well economics.
•Purchase of hydrocarbons in place of 413 Bcfe in connection with the First NEPA Non-Operated Asset Divestiture described in Note 7.
•Sale of natural gas in place of 1,563 Bcfe in the NEPA Non-Operated Asset Divestitures described in Note 7.
The change in reserves during the year ended December 31, 2023 resulted from the following:

•Conversions of 2,561 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 3,412 Bcfe, which exceeded 2023 production of 2,016 Bcfe. Extensions, discoveries and other additions included an increase of 1,670 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2023 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan, 1,341 Bcfe of proved undeveloped additions for previously proved undeveloped properties reclassified from unproved properties due to their addition to the Company's five-year development plan, positive revisions of 92 Bcfe from the extension of lateral lengths of proved undeveloped reserves and 309 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 755 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking as a result of development schedule changes.
•Negative revisions of 367 Bcfe primarily from proved undeveloped locations as a result of revisions to type curves.
•Positive revisions to proved undeveloped locations of 290 Bcfe due primarily to changes in ownership interests.
•Negative revisions of 208 Bcfe primarily from proved developed locations as a result of negative curve revisions.
•Negative revisions of 362 Bcfe from lower pricing that impacted well economics.
•Purchase of hydrocarbons in place of 2,600 Bcfe from the Tug Hill and XcL Midstream Acquisition described in Note 6.

The change in reserves during the year ended December 31, 2022 resulted from the following:

•Conversions of 1,365 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 2,495 Bcfe, which exceeded 2022 production of 1,940 Bcfe. Extensions, discoveries and other additions included an increase of 2,077 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2022 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan and 418 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 1,625 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking as a result of development schedule changes, driven largely by third-party impacts, which have pushed planned completion dates into a future period from when originally planned.
•Positive revisions to proved undeveloped locations of 518 Bcfe due primarily to changes in ownership interests.
•Positive revisions of 356 Bcfe primarily from proved developed locations as a result of positive curve revisions.
•Positive revisions of 96 Bcfe from higher pricing that impacted well economics.
•Purchase of hydrocarbons in place of 141 Bcfe from the 2022 Asset Acquisition described in Note 6.
Standardized Measure of Discounted Future Cash Flow
 
Management cautions that the standardized measure of discounted future net cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

The following table summarizes estimated future net cash flows from natural gas and oil reserves.
December 31,
 202420232022
 (Thousands)
Future cash inflows (a)$44,871,509 $52,916,665 $140,032,653 
Future production costs (b)(18,979,056)(24,357,033)(22,801,652)
Future development costs(4,352,890)(4,298,372)(3,244,211)
Future income tax expenses(4,445,354)(5,230,629)(26,375,241)
Future net cash flow17,094,209 19,030,631 87,611,549 
10% annual discount for estimated timing of cash flows
(9,095,069)(9,768,282)(47,547,025)
Standardized measure of discounted future net cash flows$7,999,140 $9,262,349 $40,064,524 

(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines. Reserves were computed using average first-day-of-the-month closing prices for the prior twelve months less regional adjustments. Regional adjustments were calculated using historical average realized prices received in the Appalachian Basin. NGLs pricing was calculated using average first-day-of-the-month closing prices for the prior twelve months for NGLs components, adjusted using the regional component makeup of proved NGLs.
December 31,
202420232022
Natural gas for NYMEX ($/MMBtu)$2.130 $2.637 $6.357 
Less regional adjustments ($/MMBtu)0.741 1.029 1.094 
Natural gas price ($/Mcf)1.468 1.700 5.543 
NGLs price ($/Bbl)29.28 28.44 38.66 
Oil for West Texas Intermediate (WTI) ($/Bbl)76.32 78.21 94.14 
Less regional adjustments ($/Bbl)16.87 14.35 17.31 
Oil price ($/Bbl)59.45 63.86 76.83 

(b)Includes approximately $2,553 million, $2,443 million and $2,098 million for future plugging and abandonment costs as of December 31, 2024, 2023 and 2022, respectively.

Holding production and development costs constant, an increase in NYMEX price of $0.10 per Dth for natural gas, an increase in WTI price of $10 per barrel for NGLs and an increase in WTI price of $10 per barrel for oil would result in a change in the December 31, 2024 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,184 million, $1,128 million and $73 million, respectively.
The following table summarizes the changes in the standardized measure of discounted future net cash flows.
Years Ended December 31,
 202420232022
 (Thousands)
Net sales and transfers of natural gas and oil produced$(2,603,792)$(2,632,808)$(9,696,207)
Net changes in prices, production and development costs(1,237,271)(48,739,248)35,353,172 
Extensions, discoveries and improved recovery, net of related costs464,496 6,347,387 1,798,851 
Development costs incurred1,432,315 1,296,380 902,925 
Net purchase of minerals in place269,453 2,131,567 280,233 
Net sale of minerals in place(692,019)— — 
Revision of previous estimates(263,191)(2,768,922)(299,423)
Accretion of discount926,235 4,006,452 1,728,112 
Net change in income taxes411,999 9,190,460 (7,233,051)
Timing and other28,566 366,557 (51,212)
Net (decrease) increase(1,263,209)(30,802,175)22,783,400 
Balance at January 19,262,349 40,064,524 17,281,124 
Balance at December 31$7,999,140 $9,262,349 $40,064,524 

Following the completion of the Equitrans Midstream Merger as described in Note 6, the Company updated certain of its cost assumptions for estimating its proved reserves to reflect the Company's ownership of the assets acquired in the Equitrans Midstream Merger and the elimination of the gathering, transportation and water service costs from the pre-existing contractual relationships between the Company and Equitrans Midstream, which are treated as intercompany transactions on a consolidated basis. Similarly, the Company updated certain of its future cost assumptions to include the additional expenses required to build and maintain the acquired midstream assets, which are needed to transport the Company's produced gas to the first liquid sales point. Lastly, following the completion of the Midstream Joint Venture Transaction as discussed in Note 8, the Company updated certain of its future cost assumptions to account for changes in the noncontrolling interest ownership of the assets owned by the Midstream Joint Venture. The Company believes that the methodology used in developing these assumptions best reflects the current economic conditions affecting the Company's reserves and gives consideration to the Company's ownership interest in its midstream assets.
v3.25.0.1
Schedule II - Valuation and Qualifying Accounts and Reserves
 12 Months Ended
Dec. 31, 2024
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]  
Schedule II - Valuation and Qualifying Accounts and Reserves
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2024
Column AColumn BColumn CColumn DColumn E
DescriptionBalance at Beginning of PeriodAdditions Charged to
Costs and Expenses		Deductions Charged to Other AccountsDeductionsBalance at End
of Period
(Thousands)
Valuation allowance for deferred tax assets:
2024$290,812 $21,564 $— $(55,158)$257,218 
2023$365,140 $12,549 $— $(86,877)$290,812 
2022$550,967 $869 $— $(186,696)$365,140 

See Note 9 to the Consolidated Financial Statements for a discussion of the change in valuation allowance.

All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
v3.25.0.1
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) $ 230,577 $ 1,735,232 $ 1,770,965
v3.25.0.1
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
v3.25.0.1
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.0.1
Cybersecurity Risk Management and Strategy Disclosure
 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]
We maintain a management-level Enterprise Risk Committee, composed of our Chief Financial Officer, Chief Legal and Policy Officer and other members of senior management, which oversees the identification and management of corporate-level risks, including cybersecurity risk, using the COSO Enterprise Risk Management Framework. To support the identification of emerging risks and align our focus on our primary business risks, our Manager Enterprise Risk, whose job responsibilities are dedicated to enterprise risk management, surveys senior leaders at least annually to assess our most significant, or "Tier 1," enterprise risks. Based in part on this survey, our Enterprise Risk Committee assesses our most significant risks and considers the effectiveness of our risk mitigation efforts, and the Manager Enterprise Risk leads a presentation to our Board of Directors covering this information on an annual basis. Our Enterprise Risk Committee also oversees periodic follow-up assessments to analyze changes in existing, evolving and emerging risks and identify new or more effective measures for mitigation.

Cybersecurity risk was classified as a Tier 1 enterprise risk for our Company by our Enterprise Risk Committee for 2024. Our Manager Enterprise Risk, with oversight by our Enterprise Risk Committee, facilitates the monitoring of all Tier 1 enterprise risks within our digital work environment for changes in risk drivers and supports the evaluation of the potential impacts of each Tier 1 enterprise risk on our Company, taking into consideration the effectiveness of our identified risk mitigants.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] We maintain a management-level Enterprise Risk Committee, composed of our Chief Financial Officer, Chief Legal and Policy Officer and other members of senior management, which oversees the identification and management of corporate-level risks, including cybersecurity risk, using the COSO Enterprise Risk Management Framework.
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]
As part of its regular oversight role, our Board of Directors, with a primary focus on policy, oversight and strategic direction, oversees management's development and maintenance of the enterprise cybersecurity program and its actions to identify, assess, mitigate and remediate cybersecurity threats to our Company. Our Board of Directors has delegated to its Audit Committee (the Audit Committee) primary responsibility for regular oversight of cybersecurity risk at the Board-level and this delegation is reflected in the Audit Committee's Charter. Our Chief Information Officer provides a regular quarterly report to the Audit Committee regarding cybersecurity matters and our enterprise cybersecurity program.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] Our Board of Directors has delegated to its Audit Committee (the Audit Committee) primary responsibility for regular oversight of cybersecurity risk at the Board-level and this delegation is reflected in the Audit Committee's Charter. Our Chief Information Officer provides a regular quarterly report to the Audit Committee regarding cybersecurity matters and our enterprise cybersecurity program.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] Our Chief Information Officer provides a regular quarterly report to the Audit Committee regarding cybersecurity matters and our enterprise cybersecurity program.
Cybersecurity Risk Role of Management [Text Block]
Our Enterprise Risk Committee has delegated to our Chief Information Officer primary responsibility for identifying, assessing and managing cybersecurity-related risks. Our Chief Information Officer has a Bachelor of Science in Computer Science from the University of Kentucky and a Master of Business Administration in Finance from the Wharton School of Business at the University of Pennsylvania. He has served in his current role at EQT since 2019 and has over twenty years of information technology experience within the energy industry.

Our Information Security team, led by our Vice President, Information Technology, who reports directly to our Chief Information Officer, manages our enterprise cybersecurity program and is responsible for managing all reported cybersecurity threats and addressing matters related to cybersecurity risk, information security and technology risk.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]
Our Enterprise Risk Committee has delegated to our Chief Information Officer primary responsibility for identifying, assessing and managing cybersecurity-related risks. Our Chief Information Officer has a Bachelor of Science in Computer Science from the University of Kentucky and a Master of Business Administration in Finance from the Wharton School of Business at the University of Pennsylvania. He has served in his current role at EQT since 2019 and has over twenty years of information technology experience within the energy industry.

Our Information Security team, led by our Vice President, Information Technology, who reports directly to our Chief Information Officer, manages our enterprise cybersecurity program and is responsible for managing all reported cybersecurity threats and addressing matters related to cybersecurity risk, information security and technology risk.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] Our Chief Information Officer has a Bachelor of Science in Computer Science from the University of Kentucky and a Master of Business Administration in Finance from the Wharton School of Business at the University of Pennsylvania. He has served in his current role at EQT since 2019 and has over twenty years of information technology experience within the energy industry.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]
In the event our Information Security team classifies a cybersecurity incident as posing a "critical risk," our Disclosure Committee, which includes our Chief Legal and Policy Officer and Chief Accounting Officer, is immediately notified of such classification via functions within our digital work environment. The Disclosure Committee, in consultation with our Information Security team and Chief Information Officer, engages in an assessment of the materiality of the cybersecurity incident, under applicable disclosure standards, including material developments throughout the incident response process. Our Board of Directors would be promptly informed upon identification of any material cybersecurity event.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.0.1
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Principles of Consolidation
Principles of Consolidation and Noncontrolling Interests. The Consolidated Financial Statements include the accounts of EQT and all subsidiaries, ventures and partnerships in which EQT directly or indirectly holds a controlling interest and variable interest entities for which EQT is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation. The Company records noncontrolling interest in its Consolidated Financial Statements for any non-wholly-owned consolidated subsidiary.

Upon the completion of the Midstream Joint Venture Transaction (defined in Note 8) and as of December 31, 2024, the Company consolidates its controlling interest in the Midstream Joint Venture (defined in Note 8) under the voting interest entity model. See Note 8 for discussion of the formation of the Midstream Joint Venture, the completion of the Midstream Joint Venture Transaction and the method of allocation used in accounting for the portion of Midstream Joint Venture that is not owned by the Company.

In addition, upon the completion of the Equitrans Midstream Merger (defined in Note 6) and as of December 31, 2024, the Company consolidates its 60% interest in Eureka Midstream Holdings, LLC (Eureka Midstream Holdings), a joint venture that owns a gathering header pipeline system that is operated by a subsidiary of EQT, under the voting interest entity model. See Note 10 for discussion of the revolving credit facility of Eureka Midstream, LLC (Eureka), a wholly-owned subsidiary of Eureka Midstream Holdings.

In 2020, the Company entered into a partnership with a third-party investor (the Investor) to form a joint venture, The Mineral Company LLC, for the purpose of purchasing certain mineral rights in the Appalachian Basin. During 2023, The Mineral Company LLC's assets were distributed pro rata to the Company and the Investor, and The Mineral Company LLC was dissolved. Prior to The Mineral Company LLC's dissolution, the Company consolidated The Mineral Company LLC as management had determined that The Mineral Company LLC was a variable interest entity, and the Company was the primary beneficiary of The Mineral Company LLC.

Prior to the NEPA Gathering System Acquisition (defined in Note 6) and the First NEPA Non-Operated Asset Divestiture (defined in Note 7), the Company recorded in the Consolidated Financial Statements its pro rata share of revenues, expenses, assets and liabilities of the NEPA Gathering System (defined in Note 6). Following the completion of the First NEPA Non-Operated Asset Divestiture, the Company owns 100% of the NEPA Gathering System.
Segments
Segments. The Company has three reportable segments reflective of its three lines of business consisting of Production, Gathering and Transmission. See Note 2.
Reclassification
Reclassification. Certain previously reported amounts have been reclassified to conform to the current year presentation. In addition, as discussed further in Note 2, certain prior period amounts have been recast to reflect the Company's change in reportable segments from one reportable segment to three reportable segments consisting of Production, Gathering and Transmission.
Use of Estimates
Use of Estimates. The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported herein. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and Cash Equivalents. The Company considers all highly-liquid investments with an original maturity of three months or less when purchased to be cash equivalents and accounts for such investments at cost. Interest earned on cash equivalents is included as a reduction of interest expense, net.
Accounts Receivable
Accounts Receivable, Net of Allowance for Credit Losses. The Company's accounts receivable relates primarily to the sales of natural gas, natural gas liquids (NGLs) and oil and amounts due from joint interest partners. See Note 3 for a discussion of amounts due from contracts with customers. Reserves for uncollectible accounts are recorded in selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required to assess the ultimate realization of the Company's accounts receivable. Reserves are based on historical experience, current and expected economic trends and specific information about customer accounts, such as the customer's creditworthiness.
Derivative Instruments
Derivative Instruments. See Note 4 for a discussion of the Company's derivative instruments and Note 5 for a description of the fair value hierarchy and a discussion of the Company's fair value measurements.

Prepaid Expenses and Other. The following table summarizes the Company's prepaid expenses and other current assets.
 December 31,
 20242023
 (Thousands)
Margin requirements with counterparties (see Note 4)
$86,975 $13,017 
Prepaid expenses and other current assets52,044 25,238 
Total prepaid expenses and other$139,019 $38,255 
Impairment of Property, Plant and Equipment
Impairment of Property, Plant and Equipment

Impairment of Proved Oil and Gas Properties. The carrying values of the Company's proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the Company's oil and gas properties has occurred, the Company compares the estimated expected undiscounted future cash flows to the carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by the Company for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil adjusted for basis differentials, future operating costs and inflation. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates. There were no indicators of impairment to the Company's material asset groups identified during 2024, 2023 and 2022.
Impairment and Expiration of Leases. Capitalized costs of unproved oil and gas properties are evaluated for recoverability on a prospective basis at least annually. Indicators of potential impairment include changes due to economic factors, potential shifts in business strategy and historical experience. The likelihood of an impairment of unproved oil and gas properties increases as the expiration of a lease term approaches and drilling activity has not commenced. The Company recognizes impairment if the Company does not have the intent to drill on the leased property prior to expiration of the lease or does not have the intent and ability to extend, renew, trade or sell the lease prior to expiration.
Impairment of Other Property, Plant and Equipment. The Company evaluates its other property, plant and equipment for impairment when events or changes in circumstance indicate that the carrying value of such assets may not be recoverable. There were no indicators of impairment to the Company's asset groups identified during 2024, 2023 and 2022.
Impairment of Contract Asset Impairment of Contract Asset. In 2020, the Company recorded a contract asset representing rate relief that the Company was entitled to pursuant to a consolidated gas gathering and compression agreement (the Consolidated GGA) entered into between the Company and an affiliate of EQM Midstream Partners, LP (EQM), which became an indirect wholly-owned subsidiary of EQT upon the closing of the Equitrans Midstream Merger. During 2022, the Company identified indicators that the carrying amount of its contract asset might not be fully recoverable, including increased uncertainty of the estimated timing of completion of the Mountain Valley Pipeline (the MVP) due to court rulings and public statements from Equitrans Midstream Corporation (Equitrans Midstream), the former parent of EQM, with respect to the completion of the MVP
Investments in Unconsolidated Entities Investments in Unconsolidated Entities. See Note 11 for a discussion of the Company's investments in unconsolidated entities, which include EQT's equity method investments and investments in equity securities. The Company evaluates its investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the investment's fair value is less than its carrying amount. The recognition of an impairment loss is required if the impairment is considered other than temporary.
Net Intangible Assets and Goodwill
Net Intangible Assets. As part of the Equitrans Midstream Merger preliminary purchase price allocation, the Company identified intangible assets related to certain of Equitrans Midstream's transmission services contracts. See Note 6. The Company evaluates its intangible assets for impairment when indicators of impairment are present. There were no indicators of impairment to the Company's net intangible assets identified during 2024.

Goodwill. Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. Goodwill is allocated among, and evaluated for impairment at, the reporting unit level, which is defined as an operating segment or one level below an operating segment.

The Company evaluates its goodwill for impairment at least annually or more frequently if indicators of impairment exist. Goodwill is tested for impairment by assessing qualitative factors to determine whether it is more likely than not (greater than 50%) that the fair value of the reporting unit is less than the carrying amount or by performing a quantitative assessment. If the qualitative assessment indicates a possible impairment, then a quantitative impairment test is performed to determine the fair value of the reporting unit using a combination of an income and market approach. Otherwise, no further analysis is required.

Under the quantitative assessment, the evaluation of impairment involves comparing the current fair value of each reporting unit to its carrying value, including goodwill. In the event that the estimated fair value of a reporting unit is less than the carrying value, the Company would recognize an impairment loss equal to the excess of the reporting unit's carrying value over its fair value not to exceed the total amount of goodwill applicable to that reporting unit.
Unamortized Debt Discount and Issuance Expense Unamortized Debt Discount and Issuance Costs. Discounts and costs incurred with the issuance of debt are amortized over the life of the debt. These amounts are presented as a reduction of debt in the Consolidated Balance Sheets.
Income Taxes
Income Taxes. The Company files a consolidated U.S. federal income tax return and uses the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded for the current year and the change in deferred taxes exclusive of amounts recorded in other comprehensive loss. Any refinements to prior year taxes made in the current year due to new information are reflected as adjustments in the current period. Separate income taxes are calculated for items charged or credited directly to shareholders' equity.

EQM, Eureka Midstream Holdings and the Midstream Joint Venture are treated as partnerships for U.S. federal and applicable state income tax purposes and are not separately subject to U.S. federal or state income taxes. EQM's, Eureka Midstream Holdings' and the Midstream Joint Venture's income is included in the Company's pre-tax income; however, the Company does not record income tax expense on income attributable to noncontrolling interests in Eureka Midstream Holdings and the Midstream Joint Venture, which reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the effective tax rate in periods when the Company has consolidated pre-tax losses.
Deferred tax assets and liabilities arise from temporary differences between the financial reporting and tax bases of the Company's assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that a portion or all of the deferred tax asset will not be realized. When evaluating whether or not a valuation allowance should be established, the Company exercises judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of the deferred tax assets will not be realized. To determine whether a valuation allowance is needed, the Company considers all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income.
 
In accounting for uncertainty of a tax position taken or expected to be taken in a tax return, the Company uses a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If it is more likely than not that a tax position will be sustained, the Company measures and recognizes the tax position at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. To determine the amount of financial statement benefit recorded for uncertain tax positions, the Company considers the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense.
Insurance
Insurance. The Company maintains insurance to cover traditional insurable risks such as general liability, workers compensation, auto liability, environmental liability, property damage, business interruption, fiduciary liability, director and officers' liability and other risks. These policies may be subject to deductible or retention amounts, coverage limitations and exclusions. The Company was previously self-insured for certain material losses related to general liability, workers compensation and environmental liability; however, the Company now maintains insurance for such losses arising on or after November 12, 2020. In addition, in conjunction with the Equitrans Midstream Merger, the Company assumed a self-insured retention reserve for certain material losses related to excess liability and environmental liability for losses arising before December 20, 2024. The Company also assumed with the Equitrans Midstream Merger a 10% co-insurance related to material losses on property insurance coverage. Prospectively, coverage is included in the Company's insurance programs that do not have high self-insured and co-insurance amounts. Reserves are recorded on an undiscounted basis using analyses of historical data and, where applicable, actuarial estimates, which represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The reserves are reviewed by the Company quarterly and, where applicable, by independent actuaries annually.
Asset Retirement Obligations
Asset Retirement Obligations. The Company accrues a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of the Company's plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to depreciation and depletion expense. The initial capitalized costs are depleted over the useful lives of the related assets.

The Company's asset retirement obligations related to the abandonment of oil and gas producing facilities include reclaiming well pads, reclaiming water impoundments, plugging wells and dismantling related structures. In addition, the Company records asset retirement obligations on its storage wells with known plugging timelines. Estimates are based on historical experience of plugging and abandoning wells and reclaiming or disposing other assets and estimated remaining lives of the wells and assets.

The Company is under no legal or contractual obligation to restore or dismantle its gathering and transmission pipeline assets upon abandonment. In addition, the Company is responsible for the operation and maintenance of its gathering and transmission assets and intends to continue such operation and maintenance so long as supply and demand for natural gas exists. As the Company expects supply and demand for natural gas to exist into the foreseeable future, the Company has not recorded asset retirement obligations for its gathering and transmission pipeline assets.
Transportation and Processing
Transportation and Processing. Costs incurred to gather, process and transport gas produced by the Company to market sales points are recorded as transportation and processing costs in the Statements of Consolidated Operations. The Company markets some transportation for resale. These costs, which are not incurred to transport gas produced by the Company, are reflected as a deduction from net marketing services and other revenues.
Share-based Compensation The Company typically elects to fund awards paid in stock through stock acquired by the Company in the open market or from any other person, issued directly by the Company or any combination of the foregoing. Prior to 2023, the Company typically used treasury stock to fund awards paid in stock.
Defined Contribution Plan and Other Postretirement Benefits Plan
Defined Contribution Plan and Other Postretirement Benefits Plan. The Company recognized expense related to its defined contribution plan of $14.5 million, $9.0 million and $7.8 million for the years ended December 31, 2024, 2023 and 2022, respectively. In addition, the Company sponsors an other postretirement benefits plan.
Income Per Share
Income Per Share. Basic income per share is computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares outstanding during the period. Diluted income per share is computed by dividing the sum of net income attributable to EQT Corporation plus the applicable numerator adjustments by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards as well as, prior to their redemption, the Convertible Notes. Purchases of treasury shares are calculated using the average share price of EQT common stock during the period. Prior to their redemption, the Company used the if-converted method to calculate the impact of the Convertible Notes on diluted income per share.
Recently Issued Accounting Standards
Recently Issued Accounting Standards

In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, to improve reportable segment disclosure requirements, primarily through the requirement of enhanced disclosure of significant segment expenses. In addition, this ASU enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and provides new segment disclosure requirements for entities with a single reportable segment. This ASU is effective for annual reporting periods beginning after December 15, 2023 and interim periods within annual reporting periods beginning after December 15, 2024. The Company adopted ASU 2023-07 in the fourth quarter of 2024. See Note 2 for segments disclosures.

In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures, to improve 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 annual reporting periods 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, Disaggregation of Income Statement Expenses, to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization and depletion) in commonly presented expense captions (such as cost of sales; selling, general and administrative expense; and research and development). This ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The requirements should be applied prospectively with the option for retrospective application. The Company is evaluating the impact ASU 2024-03 will have on its financial statements and related disclosures.
Subsequent Events Subsequent Events. The Company has evaluated subsequent events through the date of the financial statement issuance.
Revenue Recognition Under the Company's natural gas, NGLs and oil sales contracts, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. These contracts typically require payment within 25 days of the end of the calendar month in which the commodity is delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company's efforts to satisfy the performance obligations. Other contracts, such as fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices, contain fixed consideration. The Company allocates the fixed consideration to each performance obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price.
Based on management's judgment, the performance obligations for the sale of natural gas, NGLs and oil are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas, NGLs or oil is delivered to the designated sales point.

The sales of natural gas, NGLs and oil presented in the Statements of Consolidated Operations represent the Company's share of revenues net of royalties and exclude revenue interests owned by others. When selling natural gas, NGLs and oil on behalf of royalty or working interest owners, the Company acts as an agent and, thus, reports the revenue on a net basis.

Pipeline revenue. The Company provides gathering, transmission and storage services under firm and interruptible service contracts.

Firm service contracts generally require the customer to pay a firm reservation fee, which is a fixed, monthly charge to reserve an agreed upon amount of pipeline or storage capacity regardless of whether the customer uses the capacity. Under its firm service contracts, the Company has a stand-ready obligation to provide the firm service over the life of the contract. The performance obligation for revenue from firm reservation fees is satisfied over time as the pipeline capacity is made available to the customer. As such, the Company recognizes firm reservation fee revenue evenly over the contract period using a time-elapsed output method to measure progress.

Volumetric-based fees, which are charges based on the volume of gas gathered, transported or stored, can also be charged under firm service contracts for each firm contracted volume gathered, transported or stored as well as for volumes gathered, transported or stored in excess of the firm contracted volume so long as capacity exists.

Interruptible service contracts require the customer to pay volumetric-based fees and generally do not guarantee access to the pipeline or storage facility.

The performance obligation for revenue from volumetric-based fees is generally satisfied upon the Company's monthly invoicing to the customer for volumes gathered, transported or stored during the month. The amount invoiced generally corresponds directly to the value of the Company's performance to date as the customer obtains value as each volume is gathered, transported or stored. Gathering service contracts are invoiced on a one-month lag, with payment typically due within 21 days of the invoice date. Revenue for gathering services provided but not yet invoiced is estimated based on contract data, preliminary throughput and allocation measurements on a monthly basis. Transmission and storage service contracts are invoiced at the end of each calendar month, with payment typically due within 10 days of the invoice date.

For both firm reservation and volumetric-based fee revenues, the Company allocates the transaction price to each performance obligation based on the estimated relative standalone selling price. Any excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units-of-production or straight-line methodology as these methods align with the consumption of services provided to the customer. The units-of-production methodology requires the use of judgment to estimate future production volumes.

Certain of the Company's gathering service agreements are structured with MVCs, which specify minimum quantities that the customer will be charged regardless of whether such quantities are gathered. Revenue is recognized for MVCs when the performance obligation has been met, which is the earlier of when the gas is gathered or when the likelihood that the customer will be able to meet its MVC is remote. If a customer fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering services within the specified period), the customer is obligated to pay a contractually-determined fee based on the shortfall between actual volume gathered and the MVC.
Leases
The Company leases drilling rigs, facilities (including a water storage facility), vehicles and drilling and compression equipment.

To determine the present value of its right-of-use assets and lease liabilities, the Company calculates a discount rate per lease contract based on an estimate of the rate of interest that the Company would pay to borrow (on a collateralized basis, over a similar term) an amount equal to the lease payment obligation.

The Company has elected a practical expedient to forgo application of the recognition requirements under ASU 2016-02, Leases, to short-term leases; as such, short-term leases are not recorded in the Consolidated Balance Sheets. In addition, the Company has elected a practical expedient to account for lease and nonlease components together as a lease.
Certain of the Company's lease contracts include variable lease payments, such as payments for property taxes and other operating and maintenance expenses and payments based on asset use, which are not included in the lease cost or the present value of the right-of-use asset or lease liability. Certain of the Company's lease contracts provide renewal periods at the Company's option; if a renewal period option is reasonably assured to be exercised, the associated lease payment obligation is included in the present value of the right-of-use asset and lease liability.
v3.25.0.1
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Schedule Of Prepaid Expense And Other Current Assets The following table summarizes the Company's prepaid expenses and other current assets.
 December 31,
 20242023
 (Thousands)
Margin requirements with counterparties (see Note 4)
$86,975 $13,017 
Prepaid expenses and other current assets52,044 25,238 
Total prepaid expenses and other$139,019 $38,255 
Schedule of Property, Plant and Equipment The following table summarizes the Company's property, plant and equipment.
 December 31,
 20242023
 (Thousands)
Oil and gas producing properties$33,549,913 $32,510,595 
Less: Accumulated depletion12,489,317 10,734,099 
Net oil and gas producing properties21,060,596 21,776,496 
Other production assets, at cost less accumulated depreciation20,434 21,679 
Net production assets21,081,030 21,798,175 
Gathering assets8,067,556 1,153,049 
Less: Accumulated depreciation131,546 41,793 
Net gathering assets7,936,010 1,111,256 
Transmission and storage assets2,667,352 — 
Less: Accumulated depreciation30,027 — 
Net transmission and storage assets2,637,325 — 
Other property, plant and equipment, at cost less accumulated depreciation93,453 40,739 
Net property, plant and equipment$31,747,818 $22,950,170 
Summary of Other Current Liabilities The following table summarizes the Company's other current liabilities.
 December 31,
 20242023
 (Thousands)
Accrued taxes other than income$114,700 62,391 
Accrued incentive compensation53,138 24,542 
Current portion of long-term capacity contracts43,697 43,233 
Current portion of lease liabilities41,878 46,380 
Deferred revenue24,187 2,890 
Accrued payroll12,115 8,870 
Other accrued liabilities59,702 16,697 
Total other current liabilities$349,417 $205,003 
Reconciliation of Asset Retirement Obligations
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company's asset retirement obligations included in other liabilities and credits in the Consolidated Balance Sheets.
 December 31,
 20242023
 (Thousands)
Balance at January 1$911,057 $732,803 
Accretion expense68,501 47,700 
Liabilities incurred21,587 10,515 
Liabilities settled(66,729)(33,938)
Liabilities assumed in acquisitions45,847 64,424 
Liabilities removed in divestitures(28,701)(6,480)
Change in estimates (a)52,008 96,033 
Balance at December 31$1,003,570 $911,057 

(a)During 2024, the Company recorded changes in estimates attributable primarily to increased plugging costs. During 2023, the Company recorded changes in estimates attributable primarily to inflation on estimated plugging costs.
Summary of Other Operating Expenses The following table summarizes the Company's other operating expenses.
Years Ended December 31,
202420232022
(Thousands)
Transaction costs$309,419 $56,263 $14,185 
Changes in legal and environmental reserves, including settlements16,271 9,342 $30,394 
Other24,174 18,438 12,752 
Total other operating expenses$349,864 $84,043 $57,331 
Schedule of Regulatory Assets The following table summarizes Equitrans, L.P.'s regulated assets and liabilities as of December 31, 2024.
 December 31, 2024
 (Thousands)
Regulated assets:
Deferred taxes (a)$142,757 
Other recoverable costs (b)23,182 
Total regulated assets$165,939 
Regulated liabilities:
Deferred taxes (a)$8,534 
Ongoing postretirement benefits other than pension and other reimbursable costs (c)20,158 
Total regulated liabilities$28,692 

(a)The regulated asset from deferred taxes is related primarily to a historical deferred income tax position as well as taxes on the equity component of allowance for funds used during construction (AFUDC). The regulated liability from deferred taxes is related to the revaluation of a historical difference between the regulatory and tax bases of regulated property, plant and equipment. Equitrans, L.P. expects to recover the amortization of the deferred income tax positions ratably over the depreciable lives of the underlying assets. In addition, Equitrans, L.P. expects to recover the taxes on the equity component of AFUDC through future rates over the depreciable lives of the underlying long-lived assets.
(b)The regulated asset from other recoverable costs is related primarily to costs associated with Equitrans, L.P.'s asset retirement obligations, which Equitrans, L.P. expects to continue to recover over the next 9.5 years, and costs associated with a legacy postretirement benefits plan, which Equitrans, L.P. expects to continue to recover over the next 7.5 years.
(c)Equitrans, L.P. defers costs for other postretirement benefits plans, which are subject to recovery in approved rates. The related regulated liability reflects lower cumulative actuarial expenses than the amounts recovered through rates. Equitrans, L.P. expects to continue to recover costs as long as the existing recourse rates provide for recovery.
Schedule of Regulatory Liabilities The following table summarizes Equitrans, L.P.'s regulated assets and liabilities as of December 31, 2024.
 December 31, 2024
 (Thousands)
Regulated assets:
Deferred taxes (a)$142,757 
Other recoverable costs (b)23,182 
Total regulated assets$165,939 
Regulated liabilities:
Deferred taxes (a)$8,534 
Ongoing postretirement benefits other than pension and other reimbursable costs (c)20,158 
Total regulated liabilities$28,692 

(a)The regulated asset from deferred taxes is related primarily to a historical deferred income tax position as well as taxes on the equity component of allowance for funds used during construction (AFUDC). The regulated liability from deferred taxes is related to the revaluation of a historical difference between the regulatory and tax bases of regulated property, plant and equipment. Equitrans, L.P. expects to recover the amortization of the deferred income tax positions ratably over the depreciable lives of the underlying assets. In addition, Equitrans, L.P. expects to recover the taxes on the equity component of AFUDC through future rates over the depreciable lives of the underlying long-lived assets.
(b)The regulated asset from other recoverable costs is related primarily to costs associated with Equitrans, L.P.'s asset retirement obligations, which Equitrans, L.P. expects to continue to recover over the next 9.5 years, and costs associated with a legacy postretirement benefits plan, which Equitrans, L.P. expects to continue to recover over the next 7.5 years.
(c)Equitrans, L.P. defers costs for other postretirement benefits plans, which are subject to recovery in approved rates. The related regulated liability reflects lower cumulative actuarial expenses than the amounts recovered through rates. Equitrans, L.P. expects to continue to recover costs as long as the existing recourse rates provide for recovery.
Schedule of Regulated Operating Revenues, Expenses, Property, Plant and Equipment
The following table presents Equitrans, L.P.'s regulated operating revenues and expenses included in the Company's Consolidated Statement of Operations for the period from July 22, 2024 to December 31, 2024.
 July 22, 2024 to December 31, 2024
 (Thousands)
Operating revenues$218,569 
Operating expenses$78,908 

The following table presents Equitrans, L.P.'s regulated property, plant and equipment included in the Company's Consolidated Balance Sheet as of December 31, 2024.
 December 31, 2024
 (Thousands)
Property, plant and equipment$2,667,352 
Less: Accumulated depreciation30,027 
Net property, plant and equipment$2,637,325 
Schedule of Earnings Per Share, Basic and Diluted
The table below provides the computation for basic and diluted income per share.
Years Ended December 31,
202420232022
(Thousands, except per share amounts)
Net income attributable to EQT Corporation – Basic income available to shareholders$230,577 $1,735,232 $1,770,965 
Add back: Interest expense on Convertible Notes, net of tax86 7,551 8,019 
Diluted income available to shareholders$230,663 $1,742,783 $1,778,984 
Weighted average common stock outstanding – Basic509,597 380,902 370,048 
Options, restricted stock, performance awards and stock appreciation rights
4,625 5,232 5,731 
Convertible Notes371 27,090 30,716 
Weighted average common stock outstanding – Diluted514,593 413,224 406,495 
Income per share of common stock attributable to EQT Corporation:
Basic$0.45 $4.56 $4.79 
Diluted$0.45 $4.22 $4.38 
Supplemental Cash Flow Information The following table summarizes net cash paid for interest and income taxes and non-cash activity included in the Statements of Consolidated Cash Flows.
Years Ended December 31,
202420232022
(Thousands)
Cash paid during the year for:
Interest, net of amount capitalized$401,768 $213,141 $236,797 
Income taxes, net7,960 13,350 20,773 
Non-cash activity during the period for:
Equity issued as consideration for acquisitions (Note 6)$5,548,608 $2,152,631 $— 
Issuance of EQT common stock for Convertible Notes settlement (Note 10)285,608 122,830 63 
First NEPA Non-Operated Asset Divestiture (Note 7)
155,318 — — 
Increase in asset retirement costs and obligations73,576 106,548 54,608 
Increase in right-of-use assets and lease liabilities, net29,568 45,774 23,356 
Capitalization of non-cash equity share-based compensation10,095 6,287 5,406 
Investments in nonconsolidated entities3,428 — — 
Accrued transaction costs related to the sale of units of the Midstream Joint Venture (Note 8)1,135 — — 
Dissolution of consolidated variable interest entity— 25,227 — 
v3.25.0.1
Financial Information by Business Segment (Tables)
 12 Months Ended
Dec. 31, 2024
Segment Reporting [Abstract]  
Schedule Of Financial Information By Business Segment and Capital Expenditures The follow tables present the Company's profit and loss metric of operating income by segment.
Year Ended December 31, 2024
ProductionGatheringTransmissionTotal SegmentIntersegment eliminations and otherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$4,934,366 $— $— $4,934,366 $— $4,934,366 
Gain (loss) on derivatives67,880 (16,763)— 51,117 — 51,117 
Pipeline, net marketing services and other7,587 766,463 218,293 992,343 (704,517)287,826 
Total operating revenues5,009,833 749,700 218,293 5,977,826 (704,517)5,273,309 
Operating expenses (a):
Transportation and processing2,619,710 — — 2,619,710 (704,094)1,915,616 
Production377,007 — — 377,007 — 377,007 
Operating and maintenance— 89,897 20,496 110,393 — 110,393 
Exploration2,735 — — 2,735 — 2,735 
Selling, general and administrative (b)244,450 38,837 17,183 300,470 36,254 336,724 
Depreciation, depletion and amortization2,016,670 89,513 39,406 2,145,589 16,761 2,162,350 
(Gain) loss on sale/exchange of long-lived assets(764,431)(22)409 (764,044)— (764,044)
Impairment and expiration of leases97,368 — — 97,368 — 97,368 
Other operating expenses (c)12,696 — — 12,696 337,168 349,864 
Total operating expenses4,606,205 218,225 77,494 4,901,924 (313,911)4,588,013 
Operating income (loss)$403,628 $531,475 $140,799 $1,075,902 $(390,606)$685,296 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(c)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger. See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2023
ProductionGatheringTotal SegmentIntersegment eliminations and otherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$5,044,768 $— $5,044,768 $— $5,044,768 
Gain on derivatives1,838,941 — 1,838,941 — 1,838,941 
Pipeline, net marketing services and other12,649 161,395 174,044 (148,830)25,214 
Total operating revenues6,896,358 161,395 7,057,753 (148,830)6,908,923 
Operating expenses (a):
Transportation and processing2,306,090 — 2,306,090 (148,830)2,157,260 
Production239,001 — 239,001 — 239,001 
Operating and maintenance— 15,699 15,699 — 15,699 
Exploration3,330 — 3,330 — 3,330 
Selling, general and administrative (b)236,171 — 236,171 — 236,171 
Depreciation, depletion and amortization1,705,311 17,066 1,722,377 9,765 1,732,142 
Loss on sale/exchange of long-lived assets17,445 — 17,445 — 17,445 
Impairment and expiration of leases109,421 — 109,421 — 109,421 
Other operating expenses (c)9,177 — 9,177 74,866 84,043 
Total operating expenses4,625,946 32,765 4,658,711 (64,199)4,594,512 
Operating income (loss)$2,270,412 $128,630 $2,399,042 $(84,631)$2,314,411 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(c)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition (defined in Note 6). See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2022
ProductionGatheringTotal SegmentIntersegment eliminations and otherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$12,114,168 $— $12,114,168 $— $12,114,168 
Loss on derivatives(4,642,932)— (4,642,932)— (4,642,932)
Pipeline, net marketing services and other12,827 96,947 109,774 (83,321)26,453 
Total operating revenues7,484,063 96,947 7,581,010 (83,321)7,497,689 
Operating expenses (a):
Transportation and processing2,200,297 — 2,200,297 (83,321)2,116,976 
Production298,388 — 298,388 — 298,388 
Operating and maintenance— 2,597 2,597 — 2,597 
Exploration3,438 — 3,438 — 3,438 
Selling, general and administrative (b)252,645 — 252,645 — 252,645 
Depreciation, depletion and amortization1,648,808 8,035 1,656,843 9,119 1,665,962 
Gain on sale/exchange of long-lived assets(8,446)— (8,446)— (8,446)
Impairment and expiration of leases176,606 — 176,606 — 176,606 
Impairment of contract asset214,195 — 214,195 — 214,195 
Other operating expenses (c)32,605 — 32,605 24,726 57,331 
Total operating expenses4,818,536 10,632 4,829,168 (49,476)4,779,692 
Operating income (loss)$2,665,527 $86,315 $2,751,842 $(33,845)$2,717,997 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(c)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition. See Note 1 for a summary of the Company's consolidated other operating expenses.
Reconciliation of total segment operating income to income before income taxes
Years Ended December 31,
202420232022
(Thousands)
Total segment operating income$1,075,902 $2,399,042 $2,751,842 
Intersegment eliminations457 — — 
Unallocated amounts:
Other revenue(34)— — 
Corporate selling, general and administrative36,254 — — 
Corporate other depreciation and amortization16,761 9,765 9,119 
Corporate other operating expenses (a)337,168 74,866 24,726 
(Income) loss from investments (b)(76,039)(7,596)4,931 
Other income(25,983)(1,231)(11,280)
Loss on debt extinguishment68,299 80 140,029 
Interest expense, net454,825 219,660 249,655 
Income before income taxes$264,194 $2,103,498 $2,334,662 

(a)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger for the year ended December 31, 2024. Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition for both years ended December 31, 2023 and 2022. See Note 1 for a summary of the Company's consolidated other operating expenses.
(b)Income from investments for the year ended December 31, 2024 included $78.8 million of equity earnings from the Company's investment in the MVP Joint Venture, which is reported in the Company's Transmission segment.
The following table presents the Company's capital expenditures by segment.
Years Ended December 31,
202420232022
(Thousands)
Production$2,003,635 $1,878,417 $1,427,995 
Gathering202,264 31,701 6,155 
Transmission31,446 — — 
Total segment capital expenditures2,237,345 1,910,118 1,434,150 
Other corporate items28,603 15,125 5,962 
Total capital expenditures$2,265,948 $1,925,243 $1,440,112 
Schedule of Segment Assets The following table presents the Company's total assets by segment. The Company's investment in the MVP Joint Venture is presented in investments in unconsolidated entities in the Consolidated Balance Sheet. The Company did not have an investment in the MVP Joint Venture or goodwill prior to completion of the Equitrans Midstream Merger.
ProductionGatheringTransmissionTotal Segment
December 31, 2024(Thousands)
Investment in the MVP Joint Venture$— $— $3,534,730 $3,534,730 
Goodwill— — 1,217,742 1,217,742 
Other segment assets22,546,098 8,295,625 2,919,532 33,761,255 
Total assets$22,546,098 $8,295,625 $7,672,004 $38,513,727 
December 31, 2023
Total assets$23,803,913 $1,215,627 $— $25,019,540 
December 31, 2022
Total assets$20,469,506 $417,117 $— $20,886,623 
Reconciliation of total segment assets to total assets
December 31,
202420232022
(Thousands)
Total segment assets$38,513,727 $25,019,540 $20,886,623 
Intersegment eliminations(318,835)(47,471)(19,288)
Unallocated amounts:
Cash and cash equivalents202,093 80,977 1,458,644 
Income tax receivable97,378 91,414 — 
Other property, plant and equipment, at cost less accumulated depreciation93,453 40,739 32,594 
Goodwill (a)861,739 — — 
Regulated asset from deferred taxes
142,757 — — 
Other237,943 99,899 311,353 
Total assets$39,830,255 $25,285,098 $22,669,926 

(a)Represents goodwill attributable to additional deferred tax liabilities that arose from the differences between the fair value and tax bases of the Equitrans Midstream Merger preliminary purchase price allocation that carried over from Equitrans Midstream to the Company. See Note 6.
v3.25.0.1
Revenue from Contracts with Customers (Tables)
 12 Months Ended
Dec. 31, 2024
Revenue from Contract with Customer [Abstract]  
Disaggregation of Revenue These contracts are reported in pipeline, net marketing services and other revenues in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
Years Ended December 31,
202420232022
(Thousands)
Revenues from contracts with customers:
Production:
Sales of natural gas, NGLs and oil
Natural gas sales$4,224,882 $4,520,817 $11,448,293 
NGLs sales615,933 427,760 586,715 
Oil sales93,551 96,191 79,160 
Sales of natural gas, NGLs and oil4,934,366 5,044,768 12,114,168 
Gathering:
Pipeline revenue
Firm reservation fee revenue (a)313,987 — — 
Volumetric-based fee revenue (b)452,476 161,395 96,947 
Total766,463 161,395 96,947 
Transmission:
Pipeline revenues
Firm reservation fee revenue183,088 — — 
Volumetric-based fee revenue34,968 — — 
Total218,056 — — 
Intersegment eliminations and other(704,517)(148,830)(83,321)
Total revenues from contracts with customers (c)5,214,368 5,057,333 12,127,794 
Other sources of revenue:
Gain (loss) on derivatives51,117 1,838,941 (4,642,932)
Net marketing services and other revenues7,824 12,649 12,827 
Total other sources of revenue58,941 1,851,590 (4,630,105)
Total operating revenues$5,273,309 $6,908,923 $7,497,689 

(a)Firm reservation fee revenue for the year ended December 31, 2024 included unbilled revenues supported by MVCs of $4.2 million.
(b)Volumetric-based fee revenue for the year ended December 31, 2024 included unbilled revenues supported by MVCs of $4.5 million.
(c)For contracts with customers where the Company's performance obligations had been satisfied and an unconditional right to consideration existed as of the balance sheet date, the Company recorded amounts due from contracts with customers of $939.9 million and $584.8 million in accounts receivable in the Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively.
Schedule of Remaining Performance Obligations The table excludes contracts that qualified for the exception to the relative standalone selling price method as of December 31, 2024.
20252026202720282029ThereafterTotal
(Thousands)
Gathering firm reservation fees:
Third-party contracts$101,671 $92,311 $85,651 $85,651 $85,651 $371,792 $822,727 
Affiliate contracts91,918 101,728 101,393 97,701 97,701 1,482,452 1,972,893 
Total Gathering firm reservation fees193,589 194,039 187,044 183,352 183,352 1,854,244 2,795,620 
Gathering revenues supported by MVCs:
Third-party contracts82,396 89,217 80,904 77,153 65,788 185,423 580,881 
Affiliate contracts372,446 397,966 410,621 411,740 410,621 2,042,451 4,045,845 
Total Gathering revenues supported by MVCs454,842 487,183 491,525 488,893 476,409 2,227,874 4,626,726 
Transmission firm reservation fees:
Third-party contracts176,189 174,435 171,768 169,410 166,324 814,742 1,672,868 
Affiliate contracts241,507 261,045 261,045 260,715 260,383 1,964,638 3,249,333 
Total Transmission firm reservation fees417,696 435,480 432,813 430,125 426,707 2,779,380 4,922,201 
Total$1,066,127 $1,116,702 $1,111,382 $1,102,370 $1,086,468 $6,861,498 $12,344,547 

As of December 31, 2024, the Company had no remaining performance obligations on its natural gas sales contracts with fixed consideration.
v3.25.0.1
Derivative Instruments (Tables)
 12 Months Ended
Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Offsetting Assets The table below summarizes the impact of netting agreements and margin deposits on gross derivative assets and liabilities.
Gross derivative instruments recorded in the
Consolidated Balance Sheet		Derivative instruments
subject to master
netting agreements		Margin requirements with
counterparties		Net derivative
instruments
December 31, 2024(Thousands)
Asset derivative instruments, at fair value$143,581 $(117,350)$— $26,231 
Liability derivative instruments, at fair value446,519 (117,350)(86,975)242,194 
December 31, 2023
Asset derivative instruments, at fair value$978,634 $(112,203)$— $866,431 
Liability derivative instruments, at fair value186,363 (112,203)(13,017)61,143 
Schedule of Offsetting Liabilities The table below summarizes the impact of netting agreements and margin deposits on gross derivative assets and liabilities.
Gross derivative instruments recorded in the
Consolidated Balance Sheet		Derivative instruments
subject to master
netting agreements		Margin requirements with
counterparties		Net derivative
instruments
December 31, 2024(Thousands)
Asset derivative instruments, at fair value$143,581 $(117,350)$— $26,231 
Liability derivative instruments, at fair value446,519 (117,350)(86,975)242,194 
December 31, 2023
Asset derivative instruments, at fair value$978,634 $(112,203)$— $866,431 
Liability derivative instruments, at fair value186,363 (112,203)(13,017)61,143 
v3.25.0.1
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2024
Fair Value Disclosures [Abstract]  
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis
The table below summarizes assets and liabilities measured at fair value on a recurring basis.
  Fair value measurements at reporting date using:
Gross derivative instruments recorded in the Consolidated Balance SheetsQuoted prices in active markets 
for identical assets
(Level 1)		Significant other
observable inputs
(Level 2)		Significant unobservable inputs
(Level 3)
December 31, 2024(Thousands)
Asset derivative instruments, at fair value$143,581 $50,300 $93,281 $— 
Liability derivative instruments, at fair value446,519 81,074 365,445 — 
December 31, 2023
Asset derivative instruments, at fair value$978,634 $66,302 $912,332 $— 
Liability derivative instruments, at fair value186,363 42,218 144,145 — 
v3.25.0.1
Acquisitions (Tables)
 12 Months Ended
Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]  
Schedule of Allocation of Purchase Price The Company expects to complete the purchase price allocation once it has received all necessary information, at which time the value of the assets acquired and liabilities assumed will be revised if necessary.
Preliminary Purchase Price Allocation
(Thousands)
Consideration:
Equity$5,548,608 
Cash (paid in lieu of fractional shares)29 
Redemption of Equitrans Midstream preferred stock685,337 
Settlement of pre-existing relationships(239,741)
Total consideration$5,994,233 
Fair value of assets acquired:
Cash and cash equivalents$58,767 
Accounts receivable, net82,072 
Income tax receivable2,142 
Prepaid expenses and other22,048 
Property, plant and equipment9,379,642 
Investments in unconsolidated entities3,363,336 
Net intangible assets200,000 
Other assets249,846 
Noncontrolling interest in consolidated subsidiaries(162,993)
Amount attributable to assets acquired$13,194,860 
Fair value of liabilities assumed:
Current portion of debt$699,837 
Accounts payable65,006 
Accrued interest47,996 
Other current liabilities70,951 
Revolving credit facility borrowings1,035,000 
Senior notes6,273,941 
Deferred income taxes935,106 
Other liabilities and credits152,271 
Amount attributable to liabilities assumed$9,280,108 
Goodwill$2,079,481 
Schedule of Post-Acquisition Operating Results The table below summarizes amounts contributed by the assets acquired in the Equitrans Midstream Merger, inclusive of intercompany eliminations, to the Company's consolidated results for the period beginning on July 22, 2024 and ending on December 31, 2024.
July 22, 2024 through December 31, 2024
(Thousands)
Loss on derivatives$(16,763)
Pipeline, net marketing services and other274,646 
Total operating revenues$257,883 
Net loss (a)$(136,946)
Less: Net income attributable to noncontrolling interests12,879 
Net loss attributable to EQT Corporation$(149,825)

(a)Net loss includes $280.6 million of transaction costs related to the Equitrans Midstream Merger.
Such unaudited pro forma information is provided for informational purposes only and does not represent what consolidated results of operations would have been had the Equitrans Midstream Merger occurred on January 1, 2023 nor are they indicative of future consolidated results of operations.
Years Ended December 31,
 20242023
(Thousands, except per share amounts)
Pro forma operating revenues:
Pro forma sales of natural gas, NGLs and oil$4,934,366 $5,044,768 
Pro forma gain on derivatives17,685 1,887,016 
Pro forma pipeline, net marketing services and other621,214 616,245 
Pro forma total operating revenues$5,573,265 $7,548,029 
Pro forma net income (a)$489,503 $2,439,515 
Less: Pro forma net income attributable to noncontrolling interests28,303 30,037 
Pro forma net income attributable to EQT Corporation$461,200 $2,409,478 
Pro forma income per share of common stock attributable to EQT Corporation:
Pro forma net income attributable to EQT Corporation – Basic$0.78 $4.52 
Pro forma net income attributable to EQT Corporation – Diluted$0.77 $4.27 

(a)Pro forma net income for the year ended December 31, 2024 includes $304.8 million of transaction costs related to the Equitrans Midstream Merger.
v3.25.0.1
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2024
Income Tax Disclosure [Abstract]  
Schedule of Income Tax Expense (Benefit)
The following table summarizes the Company's income tax expense.
 Years Ended December 31,
 202420232022
 (Thousands)
Current:   
Federal$1,222 $(10,894)$651 
State6,125 (4,818)18,457 
Subtotal7,347 (15,712)19,108 
Deferred:
Federal(21,463)450,091 527,539 
State36,195 (65,425)7,073 
Subtotal14,732 384,666 534,612 
Total income tax expense$22,079 $368,954 $553,720 
Schedule of Reconciliation of Income Tax Expense (Benefit) to Amount Computed at the Federal Statutory Rate
The table below summarizes the reasons for income tax expense differences from amounts computed at the federal statutory rate of 21% on pre-tax income.
 Years Ended December 31,
 202420232022
Amount RateAmountRateAmountRate
 (Thousands)(Thousands)(Thousands)
Income before income taxes$264,194 $2,103,498 $2,334,662 
Tax at statutory rate$55,481 21.0%$441,735 21.0%$490,279 21.0%
State income taxes5,440 2.1%50,263 2.4%48,970 2.1%
Valuation allowance(9,601)(3.6)%(81,483)(3.9)%12,685 0.5%
Convertible Notes repurchase premium— —%— —%35,957 1.5%
Uncertain tax positions(16,977)(6.4)%(7,015)(0.3)%11,135 0.5%
State law change(11,315)(4.3)%(21,670)(1.0)%(49,511)(2.1)%
Federal and state tax credits(6,537)(2.5)%(4,715)(0.2)%(4,319)(0.2)%
Transaction costs6,041 2.3%— —%— —%
Other(453)(0.2)%(8,161)(0.4)%8,524 0.4%
Income tax expense$22,079 8.4%$368,954 17.5%$553,720 23.7%
Summary of Source and Tax Effects of Temporary Differences Between Financial Reporting and Tax Bases of Asset and Liabilities
The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
 December 31,
 20242023
 (Thousands)
Deferred tax assets:
NOL carryforwards$708,518 $740,802 
Interest disallowance limitation106,622 59,668 
Federal tax credits89,644 92,730 
Net unrealized losses80,723 — 
State capital loss carryforward44,496 99,632 
Incentive compensation and deferred compensation plans18,032 16,854 
Other2,433 1,156 
Deferred tax assets1,050,468 1,010,842 
Valuation allowance(257,218)(290,812)
Net deferred tax asset793,250 720,030 
Deferred tax liabilities:
Property, plant and equipment(2,516,074)(2,457,946)
Investment in partnerships(1,128,279)— 
Net unrealized gains— (166,905)
Deferred tax liability(3,644,353)(2,624,851)
Net deferred tax liability$(2,851,103)$(1,904,821)
Schedule of Operating Loss Carryforwards
The following table presents the expiration periods of the NOL carryforward deferred tax assets and associated valuation allowance by jurisdiction.
 December 31,
 20242023
 (Thousands)
NOL carryforwards:
Federal (expires between 2032 and 2037)$14,644 $67,958 
Federal (indefinite expiration)322,258 323,598 
State (expires between 2025 and 2037)347,279 332,153 
State (indefinite expiration)24,337 17,093 
Total NOL carryforwards$708,518 $740,802 
Valuation allowance on NOL carryforwards:
Federal$(14,263)$(24,927)
State(187,321)(156,700)
Total valuation allowance on NOL carryforwards$(201,584)$(181,627)
Schedule of Reconciliation of the Beginning and Ending Amount of Reserve
The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, excluding interest and penalties.
 202420232022
 (Thousands)
Balance at January 1$89,197 $204,035 $182,032 
Additions for tax positions taken in current year11,720 11,986 9,612 
Additions (reductions) for tax positions taken in prior years15,177 (883)12,391 
Reductions for tax positions settled with tax authorities(29,645)(125,941)— 
Reductions for lapse in statute of limitations(13,706)— — 
Balance at December 31$72,743 $89,197 $204,035 
Schedule of Uncertain tax Positions
The following table presents specific line items that were included in the reserve for uncertain tax positions.
December 31,
202420232022
(Thousands)
If recognized, effect to the effective tax rate$67,105 $83,669 $117,341 
Reduction of related deferred tax asset for general business credit carryforwards and NOLs$60,415 $77,013 $110,744 
v3.25.0.1
Debt (Tables)
 12 Months Ended
Dec. 31, 2024
Debt Disclosure [Abstract]  
Schedule of Long-Term Debt Instruments
The table below summarizes the Company's outstanding debt.
December 31, 2024December 31, 2023
 Principal ValueCarrying Value (a)Fair Value (b)Principal ValueCarrying Value (a)Fair Value (b)
 (Thousands)
EQT's revolving credit facility maturing July 23, 2029$150,000 $150,000 $150,000 $— $— $— 
Eureka's revolving credit facility maturing November 13, 2025320,800 320,800 320,800 — — — 
Term Loan Facility due June 30, 2026— — — 1,250,000 1,244,265 1,244,265 
Debentures and senior notes:
EQT's 6.125% notes due February 1, 2025 (c)
— — — 601,521 600,389 605,082 
EQT's 1.75% convertible notes due May 1, 2026
— — — 290,177 286,185 768,554 
EQT's 3.125% notes due May 15, 2026
392,915 391,193 382,994 392,915 389,978 373,261 
EQT's 7.75% debentures due July 15, 2026
115,000 114,213 119,590 115,000 113,716 121,590 
EQM's 7.500% notes due June 1, 2027
500,000 511,377 510,140 — — — 
EQM's 6.500% notes due July 1, 2027
900,000 915,538 912,159 — — — 
EQT's 3.90% notes due October 1, 2027
1,169,503 1,166,523 1,137,248 1,169,503 1,165,439 1,121,027 
EQT's 5.700% notes due April 1, 2028
500,000 492,640 508,695 500,000 490,376 509,280 
EQM's 5.500% notes due July 15, 2028
118,683 118,204 117,382 — — — 
EQT's 5.00% notes due January 15, 2029
318,494 315,785 314,357 318,494 315,121 316,784 
EQM's 4.50% notes due January 15, 2029
742,923 711,754 711,297 — — — 
EQM's 6.375% notes due April 1, 2029
600,000 608,667 606,774 — — — 
EQT's 7.000% notes due February 1, 2030 (c)
674,800 671,641 718,358 674,800 671,020 726,645 
EQM's 7.500% notes due June 1, 2030
500,000 535,671 534,950 — — — 
EQM's 4.75% notes due January 15, 2031
1,100,000 1,045,219 1,039,995 — — — 
EQT's 3.625% notes due May 15, 2031
435,165 430,818 388,111 435,165 430,141 389,925 
EQT's 5.750% notes due February 1, 2034
750,000 742,796 744,743 — — — 
EQM's 6.500% notes due July 15, 2048
80,233 81,338 81,932 — — — 
EQT's note payable to EQM— — — 88,483 88,483 91,063 
Total debt9,368,516 9,324,177 9,299,525 5,836,058 5,795,113 6,267,476 
Less: Current portion of debt (d)320,800 320,800 320,800 296,424 292,432 774,983 
Long-term debt$9,047,716 $9,003,377 $8,978,725 $5,539,634 $5,502,681 $5,492,493 
 
(a)For EQT's revolving credit facility, Eureka's revolving credit facility and, as of December 31, 2023, EQT's note payable to EQM, the principal value represents carrying value. For all other debt, the principal value less the unamortized debt issuance costs and debt discounts and, for EQM's senior notes, the unamortized fair value adjustments recorded with Equitrans Midstream Merger purchase price accounting represents carrying value.
(b)The carrying value of borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and, as of December 31, 2023, the Term Loan Facility approximates fair value as their interest rates are based on prevailing market rates; therefore, the Company considers the fair value of EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility to be Level 1 fair value measurements. As of December 31, 2023, the Company measured the fair value of EQT's note payable to EQM using Level 3 inputs. For all other debt, fair value is measured using Level 2 inputs. See Note 5 for the fair value hierarchy.
(c)Interest rates for EQT's 7.000% senior notes fluctuate based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Prior to their redemption, interest rates for EQT's 6.125% senior notes fluctuated based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Interest rates for the Company's other senior notes do not fluctuate.
(d)As of December 31, 2024, the current portion of debt included borrowings outstanding under Eureka's revolving credit facility. As of December 31, 2023, the current portion of debt included EQT's 1.75% convertible notes and a portion of EQT's note payable to EQM. Upon the closing of the Equitrans Midstream Merger, EQT's note payable to EQM became an intercompany transaction on a consolidated basis and, as such, was effectively settled on July 22, 2024.
Schedule of Debt Redeemed or Repurchased The Company repaid, redeemed or repurchased the following debt during the year ended December 31, 2024.
Debt TranchePrincipalPremiums/(Discounts)Accrued but Unpaid InterestTotal Cost
(Thousands)
EQM's 6.000% notes due July 1, 2025 (a)
$400,000 $1,284 $11,933 $413,217 
EQM's 4.125% notes due December 1, 2026 (a)
500,000 — 1,662 501,662 
EQM's 5.500% notes due July 15, 2028 (a)
731,317 15,541 18,435 765,293 
EQM's 4.50% notes due January 15, 2029 (a)
57,077 (713)1,177 57,541 
EQM's 6.500% notes due July 15, 2048 (a)
469,767 27,012 13,995 510,774 
EQM's 4.00% notes due August 1, 2024
300,000 — 6,000 306,000 
EQT's 6.125% notes due February 1, 2025
601,521 1,178 13,612 616,311 
Term Loan Facility due June 30, 20261,250,000 15 6,136 1,256,151 
EQT's 1.75% convertible notes due May 1, 2026
583 — — 583 
Total$4,310,265 $44,317 $72,950 $4,427,532 

(a)In addition to call premiums (discounts) disclosed, EQM paid $7.8 million in third-party advisory costs and fees to dealer managers and brokers for the redemption of its 6.000% senior notes, redemption of its 4.125% senior notes and repayment of certain of its senior notes in the EQM Tender Offer (defined below).
v3.25.0.1
Investments in Unconsolidated Entities (Tables)
 12 Months Ended
Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]  
Schedule of equity in the nonconsolidated investments
The table below summarizes the Company's equity method investments.
December 31, 2024December 31, 2023
Ownership InterestCarrying ValueOwnership InterestCarrying Value
(Thousands)(Thousands)
MVP Joint Venture (a):
The MVP (b)49.3 %$3,469,438 — %$— 
MVP Southgate47.2 %65,292 — %— 
Total MVP Joint Venture3,534,730 — 
Laurel Mountain Midstream, LLC (c)31 %28,757 31 %39,923 
WATT Fuel Cell Corporation (d)15.63 %14,533 15.43 %16,700 
Yellowbird Energy LLC (e)50 %6,135 — %— 
Total$3,584,155 $56,623 

(a)Mountain Valley Pipeline, LLC (the MVP Joint Venture) is a Delaware series limited liability company joint venture formed among (i) with respect to Series A, an affiliate of EQT and affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating the MVP and (ii) with respect to Series B, a wholly-owned subsidiary of EQT and affiliates of NextEra Energy, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating MVP Southgate.
(b)As discussed in Note 8, upon the completion of the Midstream Joint Venture Transaction, the Company contributed its interest in the MVP (via its Series A ownership interest in the MVP Joint Venture) to the Midstream Joint Venture.
(c)Laurel Mountain Midstream, LLC is a natural gas gathering and processing joint venture formed among the Company, Williams Companies Inc. and certain other energy companies.
(d)Watt Fuel Cell Corporation is a developer and manufacturer of solid oxide fuel cell systems that operate on common, readily available fuels such as natural gas and propane.
(e)Yellowbird Energy LLC is a joint venture formed in 2024 between a subsidiary of EQT and a third-party investor.
For the year ended December 31, 2024, the Company's Series A ownership interest (with respect to the MVP) in the MVP Joint Venture was significant as defined by the SEC's Regulation S-X Rule 1-02(w). Accordingly, pursuant to Regulation S-X Rule 4-08(g), the following table presents summarized financial information of the MVP Joint Venture in relation to the MVP for the period beginning on July 22, 2024 and ending December 31, 2024 and as of December 31, 2024.
 July 22, 2024 to
December 31, 2024
(Thousands)
Operating revenues$247,360 
Operating income$126,202 
Net income$129,773 
December 31, 2024
(Thousands)
Current assets$204,028 
Noncurrent assets9,535,975 
Total assets$9,740,003 
Current liabilities$69,303 
Noncurrent liabilities1,514 
Total liabilities70,817 
Members' equity9,669,186 
Total liabilities and members' equity$9,740,003 
v3.25.0.1
Common Stock and Income Per Share (Tables)
 12 Months Ended
Dec. 31, 2024
Earnings Per Share [Abstract]  
Schedule of EQT Common Stock Repurchased The table below summarizes the Company's share repurchases under the Share Repurchase Program for the years ended December 31, 2023 and 2022. The Company did not repurchase any equity securities during the year ended December 31, 2024.
Total number of shares purchasedAggregate purchase price (a)Average price paid per share (a)
(Millions)
Year Ended December 31, 202213,139,641 $392.7 $29.89 
Year Ended December 31, 20235,906,159 200.0 $33.86 
Total19,045,800 $592.7 

(a)Excludes fees and broker commissions.
Schedule of Earnings Per Share, Basic and Diluted
The table below provides the computation for basic and diluted income per share.
Years Ended December 31,
202420232022
(Thousands, except per share amounts)
Net income attributable to EQT Corporation – Basic income available to shareholders$230,577 $1,735,232 $1,770,965 
Add back: Interest expense on Convertible Notes, net of tax86 7,551 8,019 
Diluted income available to shareholders$230,663 $1,742,783 $1,778,984 
Weighted average common stock outstanding – Basic509,597 380,902 370,048 
Options, restricted stock, performance awards and stock appreciation rights
4,625 5,232 5,731 
Convertible Notes371 27,090 30,716 
Weighted average common stock outstanding – Diluted514,593 413,224 406,495 
Income per share of common stock attributable to EQT Corporation:
Basic$0.45 $4.56 $4.79 
Diluted$0.45 $4.22 $4.38 
v3.25.0.1
Share-Based Compensation Plans (Tables)
 12 Months Ended
Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]  
Schedule of Share-based Compensation Expense
The following table summarizes the Company's share-based compensation expense.
 Years Ended December 31,
 202420232022
 (Thousands)
Incentive Performance Share Unit Programs$20,919 $23,915 $23,443 
Restricted stock awards25,473 20,119 23,028 
Stock appreciation rights— 4,056 17,406 
Other programs, including non-employee director awards3,596 3,110 3,534 
Total share-based compensation expense (a)$49,988 $51,200 $67,411 
         
(a)For the years ended December 31, 2024 and 2023, share-based compensation expense of $105.4 million and $3.6 million, respectively, was included in other operating expenses. Share-based compensation expense for 2024 related primarily to the Equitrans Midstream Merger. There were no such costs in 2022.
Schedule of Award Types
Incentive PSU Programs – Equity SettledNonvested SharesWeighted Average
Fair Value		Aggregate Fair Value
Outstanding at December 31, 2021
2,754,648 $16.08 $44,281,509 
Granted in Period575,120 29.73 (a)17,098,318 
Granted from Multiplier162,183 29.45 4,776,289 
Vested(625,563)29.45 (18,422,830)
Forfeited(4,398)13.28 (58,405)
Outstanding at December 31, 20222,861,990 16.66 47,674,881 
Granted in Period404,790 38.79 15,701,804 
Granted from Multiplier409,383 6.56 2,685,552 
Vested(1,773,994)6.56 (11,637,401)
Forfeited(70,616)37.59 (2,654,455)
Outstanding at December 31, 2023
1,831,553 28.27 51,770,381 
Granted in Period371,500 40.08 14,889,720 
Granted from Multiplier451,805 23.55 10,640,008 
Vested(1,355,415)23.55 (31,920,023)
Forfeited(7,092)45.94 (325,806)
Outstanding at December 31, 2024
1,292,351 $34.86 $45,054,280 

(a)The 2022 Incentive PSU Program was granted as a liability award and converted to an equity award in April 2022. The fair value determined through a Monte Carlo simulation at the time of conversion totaled $75.32 per share, which was an increase of $45.59 per share from fair value determined through a Monte Carlo simulation at the grant date.
Schedule of Valuation Assumptions
Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions at grant date:
 Incentive PSU Programs Issued During the Years Ended December 31,
20242023 (a)20222021 (a)2020 (b)
Risk-free rate4.35%4.16%1.52%0.18%1.22%
Volatility factor48.82%59.31%65.38%72.50%45.41%
Expected term3 years3 years3 years3 years3 years

(a)There were two grant dates for the 2023 Incentive PSU Program and the 2021 Incentive PSU Program. Amounts shown represent weighted average.
(b)There were three grant dates for the 2020 Incentive PSU Program. Amounts shown represent weighted average.

Dividends paid from the beginning of the performance period will be cumulatively added as additional shares of common stock; therefore, dividend yield is not applicable.
The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. There were no stock options granted in 2024, 2023 and 2022.
 Year Ended
December 31, 2020
Risk-free interest rate1.10 %
Dividend yield— %
Volatility factor60.00 %
Expected term4 years
Number of Options Granted1,000,000 
Weighted Average Grant Date Fair Value$1.61 
The expected term represents the period of time between the valuation date and the midpoint of the exercise window.
2020 Stock Appreciation Rights
Risk-free interest rate0.30 %
Dividend yield— %
Volatility factor67.50 %
Expected term3.28 years
Number of Stock Appreciation Rights Granted1,240,000
Weighted Average Grant Date Fair Value$2.61 
Total Intrinsic Value of Exercises$— 
Summary of Restricted Stock Awards Activity
The following table summarizes restricted stock unit equity award activity as of December 31, 2024.
Restricted Stock – Equity SettledNonvested SharesWeighted Average
Fair Value		Aggregate Fair Value
Outstanding at January 1, 20223,104,281 $12.58 $39,056,435 
Granted1,288,430 21.65 27,893,331 
Vested(1,368,577)12.16 (16,644,859)
Forfeited(97,189)15.56 (1,512,333)
Outstanding at December 31, 2022
2,926,945 16.67 48,792,574 
Granted953,270 31.88 30,389,954 
Vested(1,544,968)15.20 (23,482,927)
Forfeited(117,445)24.52 (2,879,751)
Outstanding at December 31, 2023
2,217,802 23.82 52,819,850 
Granted982,990 34.54 33,950,507 
Vested(4,861,796)31.98 (155,480,899)
Conversion of Equitrans Midstream awards5,175,814 35.88 185,708,206 
Forfeited(90,641)31.92 (2,893,279)
Outstanding at December 31, 2024
3,424,169 $33.32 $114,104,385 
Summary of Option Activity
The following table summarizes option activity as of December 31, 2024.
Non-Qualified Stock OptionsSharesWeighted Average
Exercise Price		Weighted Average
Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 20241,523,536 $18.75 
Expired(193,726)46.21   
Exercised(134,474)37.91 
Outstanding and Exercisable at December 31, 20241,195,336 $12.14 2.3 years$40,604,986 
v3.25.0.1
Leases (Tables)
 12 Months Ended
Dec. 31, 2024
Leases [Abstract]  
Schedule of Lease Cost
The following table summarizes the Company's lease costs.
Years Ended December 31,
202420232022
(Thousands)
Operating lease costs$41,991 $26,755 $19,922 
Finance lease costs5,546 2,414 1,716 
Variable and short-term lease costs33,475 24,151 13,726 
Total lease costs (a)$81,012 $53,320 $35,364 

(a)Includes drilling rig lease costs capitalized to property, plant and equipment of $50.5 million, $40.8 million and $25.4 million, respectively, of which $33.1 million, $24.5 million and $17.7 million, respectively, were operating lease costs for the years ended December 31, 2024, 2023 and 2022.
Schedule of Balance Sheet Information The following table summarizes the Company's right-of-use assets and lease liabilities.
December 31,
20242023
(Thousands)
Right-of-Use Assets
Operating$60,496 $42,338 
Finance34,803 6,494 
Total right-of-use assets$95,299 $48,832 
Lease Liabilities
Current lease liabilities
Operating$36,275 $43,891 
Finance5,603 2,489 
Total current lease liabilities41,878 46,380 
Noncurrent lease liabilities
Operating29,391 8,443 
Finance29,263 3,754 
Total noncurrent lease liabilities58,654 12,197 
Total lease liabilities$100,532 $58,577 
Summary of Lease Payment Obligations
The following table summarizes the Company's lease payment obligations as of December 31, 2024.
OperatingFinanceTotal
(Thousands)
2025$38,592 $7,192 $45,784 
20268,289 6,420 14,709 
20277,623 6,057 13,680 
20286,480 4,806 11,286 
20295,804 4,523 10,327 
Thereafter5,207 12,126 17,333 
Total lease payment obligations71,995 41,124 113,119 
Less: Imputed interest6,329 6,258 12,587 
Present value of lease liabilities$65,666 $34,866 $100,532 
v3.25.0.1
Natural Gas Producing Activities (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2024
Extractive Industries [Abstract]  
Schedule of Cost Incurred Relating to Property Acquisition, Exploration and Development
The following tables present total aggregate capitalized costs and costs incurred related to natural gas, NGLs and oil production activities.
 December 31,
 20242023
 (Thousands)
Capitalized costs
Proved properties$31,986,473 $30,471,164 
Unproved properties1,563,440 2,039,431 
Total capitalized costs33,549,913 32,510,595 
Less: Accumulated depreciation and depletion12,489,317 10,734,099 
Net capitalized costs$21,060,596 $21,776,496 
Years Ended December 31,
202420232022
(Thousands)
Costs incurred (a)
Property acquisition:   
Proved properties (b)$410,805 $4,142,621 $82,276 
Unproved properties (c)98,007 575,130 113,523 
Exploration2,735 3,330 3,438 
Development1,848,000 1,782,428 1,298,665 

(a)Amounts for all years presented exclude costs for facilities, information technology and other corporate items. In addition, amounts for 2024 exclude midstream assets. Amounts for 2023 and 2022 include costs for midstream assets.
(b)Amounts in 2024 include $267.7 million and $74.7 million for wells and leases, respectively, received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $2,522.3 million, $757.6 million and $719.6 million for wells, midstream assets and leases, respectively, acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $40.5 million for leases acquired in the 2022 Asset Acquisition. See Note 6.
(c)Amounts in 2024 include $10.8 million for unproved properties received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $523.0 million for unproved properties acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $17.1 million for unproved properties acquired in the 2022 Asset Acquisition. See Note 6.
Results of Operations Related to Natural Gas, NGL and Oil Producing Activities
The following table presents the results of operations related to natural gas, NGLs and oil production.
Years Ended December 31,
202420232022
(Thousands)
Sales of natural gas, NGLs and oil$4,934,366 $5,044,768 $12,114,168 
Transportation and processing1,915,616 2,157,260 2,116,976 
Production377,007 254,700 300,985 
Operating and maintenance37,951 — — 
Exploration2,735 3,330 3,438 
Depreciation and depletion2,016,670 1,732,142 1,665,962 
(Gain) loss on sale/exchange of long-lived assets(764,431)17,445 (8,446)
Impairment and expiration of leases97,368 109,421 176,606 
Income tax expense316,377 187,463 1,987,323 
Results of operations from producing activities, excluding corporate overhead$935,073 $583,007 $5,871,324 
Schedule of the Entity's Proved Reserves
For all tables presented, NGLs and oil were converted at a rate of one Mbbl to approximately six million cubic feet (MMcf).
 Years Ended December 31,
 202420232022
 (MMcfe)
Natural gas, NGLs and oil   
Proved developed and undeveloped reserves:   
Balance at January 127,596,694 25,002,589 24,961,499 
Revision of previous estimates(1,079,677)(1,402,039)(654,618)
Purchase of hydrocarbons in place413,040 2,600,667 141,038 
Sale of natural gas in place(1,562,849)— — 
Extensions, discoveries and other additions3,125,620 3,411,750 2,494,713 
Production(2,228,159)(2,016,273)(1,940,043)
Balance at December 3126,264,669 27,596,694 25,002,589 
Proved developed reserves:
Balance at January 119,558,176 17,513,645 17,218,655 
Balance at December 3118,804,929 19,558,176 17,513,645 
Proved undeveloped reserves:
Balance at January 18,038,518 7,488,944 7,742,844 
Balance at December 317,459,740 8,038,518 7,488,944 
 Years Ended December 31,
 202420232022
 (MMcf)
Natural gas   
Proved developed and undeveloped reserves:   
Balance at January 125,795,134 23,824,887 23,523,665 
Revision of previous estimates(917,676)(1,461,305)(432,315)
Purchase of natural gas in place395,423 2,012,159 141,038 
Sale of natural gas in place(1,562,849)— — 
Extensions, discoveries and other additions2,921,638 3,326,736 2,434,543 
Production(2,086,441)(1,907,343)(1,842,044)
Balance at December 3124,545,229 25,795,134 23,824,887 
Proved developed reserves:   
Balance at January 118,186,432 16,541,017 16,152,083 
Balance at December 3117,440,191 18,186,432 16,541,017 
Proved undeveloped reserves:
Balance at January 17,608,702 7,283,870 7,371,582 
Balance at December 317,105,038 7,608,702 7,283,870 

 Years Ended December 31,
202420232022
(Mbbl)
NGLs   
Proved developed and undeveloped reserves:   
Balance at January 1285,345 186,141 225,792 
Revision of previous estimates(24,332)11,558 (33,955)
Purchase of NGLs in place2,529 90,604 — 
Extensions, discoveries and other additions30,391 13,592 9,610 
Production(22,025)(16,550)(15,306)
Balance at December 31271,908 285,345 186,141 
Proved developed reserves:  
Balance at January 1218,523 154,921 169,781 
Balance at December 31217,786 218,523 154,921 
Proved undeveloped reserves:
Balance at January 166,822 31,220 56,011 
Balance at December 3154,122 66,822 31,220 
 Years Ended December 31,
 202420232022
 (Mbbl)
Oil   
Proved developed and undeveloped reserves:   
Balance at January 114,915 10,142 13,846 
Revision of previous estimates(2,669)(1,680)(3,095)
Purchase of oil in place407 7,481 — 
Extensions, discoveries and other additions3,606 577 418 
Production(1,595)(1,605)(1,027)
Balance at December 3114,664 14,915 10,142 
Proved developed reserves:   
Balance at January 110,101 7,183 7,981 
Balance at December 319,669 10,101 7,183 
Proved undeveloped reserves:
Balance at January 14,814 2,959 5,865 
Balance at December 314,995 4,814 2,959 
Schedule of Estimated Future Net Cash Flows From Natural Gas and Oil Reserves
The following table summarizes estimated future net cash flows from natural gas and oil reserves.
December 31,
 202420232022
 (Thousands)
Future cash inflows (a)$44,871,509 $52,916,665 $140,032,653 
Future production costs (b)(18,979,056)(24,357,033)(22,801,652)
Future development costs(4,352,890)(4,298,372)(3,244,211)
Future income tax expenses(4,445,354)(5,230,629)(26,375,241)
Future net cash flow17,094,209 19,030,631 87,611,549 
10% annual discount for estimated timing of cash flows
(9,095,069)(9,768,282)(47,547,025)
Standardized measure of discounted future net cash flows$7,999,140 $9,262,349 $40,064,524 

(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines. Reserves were computed using average first-day-of-the-month closing prices for the prior twelve months less regional adjustments. Regional adjustments were calculated using historical average realized prices received in the Appalachian Basin. NGLs pricing was calculated using average first-day-of-the-month closing prices for the prior twelve months for NGLs components, adjusted using the regional component makeup of proved NGLs.
December 31,
202420232022
Natural gas for NYMEX ($/MMBtu)$2.130 $2.637 $6.357 
Less regional adjustments ($/MMBtu)0.741 1.029 1.094 
Natural gas price ($/Mcf)1.468 1.700 5.543 
NGLs price ($/Bbl)29.28 28.44 38.66 
Oil for West Texas Intermediate (WTI) ($/Bbl)76.32 78.21 94.14 
Less regional adjustments ($/Bbl)16.87 14.35 17.31 
Oil price ($/Bbl)59.45 63.86 76.83 

(b)Includes approximately $2,553 million, $2,443 million and $2,098 million for future plugging and abandonment costs as of December 31, 2024, 2023 and 2022, respectively.
Schedule of Changes in The Standardized Measure of Discounted Net Cash Flows From Natural Gas and Oil Reserves
The following table summarizes the changes in the standardized measure of discounted future net cash flows.
Years Ended December 31,
 202420232022
 (Thousands)
Net sales and transfers of natural gas and oil produced$(2,603,792)$(2,632,808)$(9,696,207)
Net changes in prices, production and development costs(1,237,271)(48,739,248)35,353,172 
Extensions, discoveries and improved recovery, net of related costs464,496 6,347,387 1,798,851 
Development costs incurred1,432,315 1,296,380 902,925 
Net purchase of minerals in place269,453 2,131,567 280,233 
Net sale of minerals in place(692,019)— — 
Revision of previous estimates(263,191)(2,768,922)(299,423)
Accretion of discount926,235 4,006,452 1,728,112 
Net change in income taxes411,999 9,190,460 (7,233,051)
Timing and other28,566 366,557 (51,212)
Net (decrease) increase(1,263,209)(30,802,175)22,783,400 
Balance at January 19,262,349 40,064,524 17,281,124 
Balance at December 31$7,999,140 $9,262,349 $40,064,524 

Following the completion of the Equitrans Midstream Merger as described in Note 6, the Company updated certain of its cost assumptions for estimating its proved reserves to reflect the Company's ownership of the assets acquired in the Equitrans Midstream Merger and the elimination of the gathering, transportation and water service costs from the pre-existing contractual relationships between the Company and Equitrans Midstream, which are treated as intercompany transactions on a consolidated basis. Similarly, the Company updated certain of its future cost assumptions to include the additional expenses required to build and maintain the acquired midstream assets, which are needed to transport the Company's produced gas to the first liquid sales point. Lastly, following the completion of the Midstream Joint Venture Transaction as discussed in Note 8, the Company updated certain of its future cost assumptions to account for changes in the noncontrolling interest ownership of the assets owned by the Midstream Joint Venture. The Company believes that the methodology used in developing these assumptions best reflects the current economic conditions affecting the Company's reserves and gives consideration to the Company's ownership interest in its midstream assets.
v3.25.0.1
Summary of Significant Accounting Policies - Narrative (Details)
 5 Months Ended 7 Months Ended 12 Months Ended
Dec. 31, 2024
USD ($)
segment
Jul. 21, 2024
segment
Dec. 31, 2024
USD ($)
$ / MBoe
well
Dec. 31, 2023
USD ($)
$ / MBoe
well
Dec. 31, 2022
USD ($)
$ / MBoe
well
May 31, 2024
Property, Plant and Equipment [Line Items]            
Number of operating segments | segment 3          
Number of segments | segment 3 1        
Internal costs $ 69,000,000   $ 69,000,000 $ 57,000,000 $ 48,000,000  
Interest costs capitalized     $ 54,000,000 $ 41,000,000 $ 28,000,000  
Overall average rate of depletion (in dollars per Mcfe) | $ / MBoe     0.90 0.84 0.85  
Number of exploratory dry holes | well     0 0 0  
Capitalized exploratory well costs 0   $ 0 $ 0 $ 0  
Oil and gas producing properties 33,549,913,000   $ 33,549,913,000 32,510,595,000    
Depreciation rate percentage     3.10%      
Impairment and expiration of leases     $ 97,368,000 109,421,000 176,606,000  
Property, plant and equipment 44,505,504,000   44,505,504,000 33,817,169,000    
Impairment of contract asset         214,000,000  
Contract asset         0  
Carrying Value $ 3,584,155,000   $ 3,584,155,000 56,623,000    
Largest amount of benefit threshold, percentage (no greater than) 50.00%   50.00%      
Insurance percentage 10.00%   10.00%      
Expense recognized related to defined contribution plan     $ 14,500,000 $ 9,000,000.0 $ 7,800,000  
Gathering            
Property, Plant and Equipment [Line Items]            
Oil and gas producing properties $ 25,000,000   25,000,000      
EQM Transmission And Storage Assets            
Property, Plant and Equipment [Line Items]            
Oil and gas producing properties $ 4,000,000   $ 4,000,000      
WATT Fuel Cell Corporation            
Property, Plant and Equipment [Line Items]            
Ownership percentage 15.63%   15.63% 15.43%    
Carrying Value $ 14,533,000   $ 14,533,000 $ 16,700,000    
the Investment Fund            
Property, Plant and Equipment [Line Items]            
Investment owned 33,200,000   33,200,000 36,100,000    
Unproved Property            
Property, Plant and Equipment [Line Items]            
Property, plant and equipment $ 1,563,000,000   $ 1,563,000,000 $ 2,039,000,000    
NEPA Gathering System            
Property, Plant and Equipment [Line Items]            
Ownership interest (in percent)           100.00%
Consolidated interest | Eureka Midstream Holdings L L C            
Property, Plant and Equipment [Line Items]            
Ownership interest (in percent) 60.00%   60.00%      
v3.25.0.1
Summary of Significant Accounting Policies - Summary of Prepaid Expenses and Other Current Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Accounting Policies [Abstract]    
Margin requirements with counterparties (see Note $4) $ 86,975 $ 13,017
Prepaid expenses and other current assets 52,044 25,238
Total prepaid expenses and other $ 139,019 $ 38,255
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Property, Plant and Equipment [Line Items]    
Oil and gas producing properties $ 33,549,913 $ 32,510,595
Less: Accumulated depletion 12,489,317 10,734,099
Net oil and gas producing properties 21,060,596 21,776,496
Net property, plant and equipment 31,747,818 22,950,170
Property, plant and equipment 44,505,504 33,817,169
Less: Accumulated depreciation and depletion 12,757,686 10,866,999
Gathering    
Property, Plant and Equipment [Line Items]    
Oil and gas producing properties 25,000  
Operating Segments | Production    
Property, Plant and Equipment [Line Items]    
Oil and gas producing properties 33,549,913 32,510,595
Less: Accumulated depletion 12,489,317 10,734,099
Net oil and gas producing properties 21,060,596 21,776,496
Other property, plant and equipment, at cost less accumulated depreciation 20,434 21,679
Net property, plant and equipment 21,081,030 21,798,175
Operating Segments | Gathering    
Property, Plant and Equipment [Line Items]    
Net property, plant and equipment 7,936,010 1,111,256
Property, plant and equipment 8,067,556 1,153,049
Less: Accumulated depreciation and depletion 131,546 41,793
Operating Segments | Transmission    
Property, Plant and Equipment [Line Items]    
Net property, plant and equipment 2,637,325 0
Property, plant and equipment 2,667,352 0
Less: Accumulated depreciation and depletion 30,027 0
Intersegment eliminations and other    
Property, Plant and Equipment [Line Items]    
Other property, plant and equipment, at cost less accumulated depreciation $ 93,453 $ 40,739
v3.25.0.1
Summary of Significant Accounting Policies - Other Current Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Other Current Liabilities:    
Accrued taxes other than income $ 114,700 $ 62,391
Accrued incentive compensation 53,138 24,542
Current portion of long-term capacity contracts 43,697 43,233
Total current lease liabilities 41,878 46,380
Deferred revenue 24,187 2,890
Accrued payroll 12,115 8,870
Other accrued liabilities 59,702 16,697
Total other current liabilities $ 349,417 $ 205,003
v3.25.0.1
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Asset retirement obligations    
Asset retirement obligation as of beginning of period $ 911,057 $ 732,803
Accretion expense 68,501 47,700
Liabilities incurred 21,587 10,515
Liabilities settled (66,729) (33,938)
Liabilities assumed in acquisitions 45,847 64,424
Liabilities removed in divestitures (28,701) (6,480)
Change in estimates 52,008 96,033
Asset retirement obligation as of end of period $ 1,003,570 $ 911,057
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Regulatory Assets and Liabilities (Details) - Equitrans LP
$ in Thousands
Dec. 31, 2024
USD ($)
Regulated assets:  
Total regulated assets $ 165,939
Regulated liabilities:  
Total regulated liabilities 28,692
Deferred taxes  
Regulated liabilities:  
Total regulated liabilities 8,534
On-going post-retirement benefits other than pension and other reimbursable costs  
Regulated liabilities:  
Total regulated liabilities 20,158
Deferred taxes  
Regulated assets:  
Total regulated assets 142,757
Other recoverable costs  
Regulated assets:  
Total regulated assets $ 23,182
Asset retirement obligations  
Regulated liabilities:  
Remaining recovery period 9 years 6 months
On-going post-retirement benefits other than pension and other reimbursable costs  
Regulated liabilities:  
Remaining recovery period 7 years 6 months
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Regulated Operating Revenues, Expenses, Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
 5 Months Ended
Dec. 31, 2024
Dec. 31, 2023
New Accounting Pronouncements or Change in Accounting Principle [Line Items]    
Property, plant and equipment $ 44,505,504 $ 33,817,169
Less: Accumulated depreciation and depletion 12,757,686 10,866,999
Net property, plant and equipment 31,747,818 $ 22,950,170
Equitrans LP    
New Accounting Pronouncements or Change in Accounting Principle [Line Items]    
Operating revenues 218,569  
Operating expenses 78,908  
Property, plant and equipment 2,667,352  
Less: Accumulated depreciation and depletion 30,027  
Net property, plant and equipment $ 2,637,325  
v3.25.0.1
Summary of Significant Accounting Policies - Other Operating Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Accounting Policies [Abstract]      
Transaction costs $ 309,419 $ 56,263 $ 14,185
Changes in legal and environmental reserves, including settlements 16,271 9,342 30,394
Other 24,174 18,438 12,752
Total other operating expenses $ 349,864 $ 84,043 $ 57,331
v3.25.0.1
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Cash paid during the year for:      
Interest, net of amount capitalized $ 401,768 $ 213,141 $ 236,797
Income taxes, net 7,960 13,350 20,773
Non-cash activity during the period for:      
Equity issued as consideration for acquisitions 5,548,608 2,152,631 0
Issuance of EQT common stock for Convertible Notes settlement (Note 10) 285,608 122,830 63
First NEPA Non-Operated Asset Divestiture 155,318 0 0
Increase in asset retirement costs and obligations 73,576 106,548 54,608
Increase in right-of-use assets and lease liabilities, net 29,568 45,774 23,356
Capitalization of non-cash equity share-based compensation 10,095 6,287 5,406
Investments in nonconsolidated entities 3,428 0 0
Accrued transaction costs related to the sale of units of the Midstream Joint Venture 1,135 0 0
Dissolution of consolidated variable interest entity $ 0 $ 25,227 $ 0
v3.25.0.1
Financial Information by Business Segment - Narrative (Details)
$ in Millions
 3 Months Ended 5 Months Ended 7 Months Ended
Feb. 26, 2020
Bcf / d
Dec. 31, 2024
USD ($)
Dec. 31, 2024
segment
business
Jul. 21, 2024
segment
Dec. 31, 2023
USD ($)
Segment Reporting Information [Line Items]          
Number of segments | segment     3 1  
Number of operating segments | segment     3    
Number of lines of business | business     3    
Henry Hub          
Segment Reporting Information [Line Items]          
Cash bonus payment period   36 months 36 months    
Derivative liability | $         $ 48.0
EQT Producer          
Segment Reporting Information [Line Items]          
Annual minimum volume (in Bcf per day) | Bcf / d 3.0        
EQT Party | EQM Affiliate          
Segment Reporting Information [Line Items]          
Cash bonus payments | $   $ 4.2      
v3.25.0.1
Financial Information by Business Segment - Schedule Of Financial Information By Business Segment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Operating revenues:      
Gain (loss) on derivatives $ 51,117 $ 1,838,941 $ (4,642,932)
Total operating revenues 5,273,309 6,908,923 7,497,689
Operating expenses:      
Transportation and processing 1,915,616 2,157,260 2,116,976
Production 377,007 239,001 298,388
Operating and maintenance 110,393 15,699 2,597
Exploration 2,735 3,330 3,438
Selling, general and administrative 336,724 236,171 252,645
Depreciation, depletion and amortization 2,162,350 1,732,142 1,665,962
(Gain) loss on sale/exchange of long-lived assets (764,044) 17,445 (8,446)
Impairment and expiration of leases 97,368 109,421 176,606
Impairment of contract asset     214,195
Other operating expenses 349,864 84,043 57,331
Total operating expenses 4,588,013 4,594,512 4,779,692
Operating income 685,296 2,314,411 2,717,997
Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 4,934,366 5,044,768 12,114,168
Pipeline, net marketing services and other      
Operating revenues:      
Pipeline, net marketing services and other 287,826 25,214 26,453
Operating Segments      
Operating revenues:      
Gain (loss) on derivatives 51,117 1,838,941 (4,642,932)
Total operating revenues 5,977,826 7,057,753 7,581,010
Operating expenses:      
Transportation and processing 2,619,710 2,306,090 2,200,297
Production 377,007 239,001 298,388
Operating and maintenance 110,393 15,699 2,597
Exploration 2,735 3,330 3,438
Selling, general and administrative 300,470 236,171 252,645
Depreciation, depletion and amortization 2,145,589 1,722,377 1,656,843
(Gain) loss on sale/exchange of long-lived assets (764,044) 17,445 (8,446)
Impairment and expiration of leases 97,368 109,421 176,606
Impairment of contract asset     214,195
Other operating expenses 12,696 9,177 32,605
Total operating expenses 4,901,924 4,658,711 4,829,168
Operating income 1,075,902 2,399,042 2,751,842
Operating Segments | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 4,934,366 5,044,768 12,114,168
Operating Segments | Pipeline, net marketing services and other      
Operating revenues:      
Pipeline, net marketing services and other 992,343 174,044 109,774
Intersegment eliminations and other      
Operating revenues:      
Gain (loss) on derivatives 0 0 0
Total operating revenues (704,517) (148,830) (83,321)
Operating expenses:      
Transportation and processing (704,094) (148,830) (83,321)
Production 0 0 0
Operating and maintenance 0 0 0
Exploration 0 0 0
Selling, general and administrative 36,254 0 0
Depreciation, depletion and amortization 16,761 9,765 9,119
(Gain) loss on sale/exchange of long-lived assets 0 0 0
Impairment and expiration of leases 0 0 0
Impairment of contract asset     0
Other operating expenses 337,168 74,866 24,726
Total operating expenses (313,911) (64,199) (49,476)
Operating income (390,606) (84,631) (33,845)
Intersegment eliminations and other | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 0 0 0
Intersegment eliminations and other | Pipeline, net marketing services and other      
Operating revenues:      
Pipeline, net marketing services and other (704,517) (148,830) (83,321)
Production | Operating Segments      
Operating revenues:      
Gain (loss) on derivatives 67,880 1,838,941 (4,642,932)
Total operating revenues 5,009,833 6,896,358 7,484,063
Operating expenses:      
Transportation and processing 2,619,710 2,306,090 2,200,297
Production 377,007 239,001 298,388
Operating and maintenance 0 0 0
Exploration 2,735 3,330 3,438
Selling, general and administrative 244,450 236,171 252,645
Depreciation, depletion and amortization 2,016,670 1,705,311 1,648,808
(Gain) loss on sale/exchange of long-lived assets (764,431) 17,445 (8,446)
Impairment and expiration of leases 97,368 109,421 176,606
Impairment of contract asset     214,195
Other operating expenses 12,696 9,177 32,605
Total operating expenses 4,606,205 4,625,946 4,818,536
Operating income 403,628 2,270,412 2,665,527
Production | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 4,934,366 5,044,768 12,114,168
Production | Operating Segments | Pipeline, net marketing services and other      
Operating revenues:      
Pipeline, net marketing services and other 7,587 12,649 12,827
Gathering | Operating Segments      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 766,463 161,395 96,947
Gain (loss) on derivatives (16,763) 0 0
Total operating revenues 749,700 161,395 96,947
Operating expenses:      
Transportation and processing 0 0 0
Production 0 0 0
Operating and maintenance 89,897 15,699 2,597
Exploration 0 0 0
Selling, general and administrative 38,837 0 0
Depreciation, depletion and amortization 89,513 17,066 8,035
(Gain) loss on sale/exchange of long-lived assets (22) 0 0
Impairment and expiration of leases 0 0 0
Impairment of contract asset     0
Other operating expenses 0 0 0
Total operating expenses 218,225 32,765 10,632
Operating income 531,475 128,630 86,315
Gathering | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 0 0 0
Gathering | Operating Segments | Pipeline, net marketing services and other      
Operating revenues:      
Pipeline, net marketing services and other 766,463 161,395 96,947
Transmission | Operating Segments      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 218,056 $ 0 $ 0
Gain (loss) on derivatives 0    
Total operating revenues 218,293    
Operating expenses:      
Transportation and processing 0    
Production 0    
Operating and maintenance 20,496    
Exploration 0    
Selling, general and administrative 17,183    
Depreciation, depletion and amortization 39,406    
(Gain) loss on sale/exchange of long-lived assets 409    
Impairment and expiration of leases 0    
Other operating expenses 0    
Total operating expenses 77,494    
Operating income 140,799    
Transmission | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 0    
Transmission | Operating Segments | Pipeline, net marketing services and other      
Operating revenues:      
Pipeline, net marketing services and other $ 218,293    
v3.25.0.1
Financial Information by Business Segment - Schedule of Segment Operating Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment Reporting Information [Line Items]      
Total segment operating income $ 685,296 $ 2,314,411 $ 2,717,997
Unallocated amounts:      
Corporate selling, general and administrative 336,724 236,171 252,645
Corporate other operating expenses 349,864 84,043 57,331
(Income) loss from investments (76,039) (7,596) 4,931
Other income (25,983) (1,231) (11,280)
Loss on debt extinguishment 68,299 80 140,029
Interest expense, net 454,825 219,660 249,655
Income before income taxes 264,194 2,103,498 2,334,662
MVP Joint Venture | Transmission      
Unallocated amounts:      
Total investments 78,800    
Operating Segments      
Segment Reporting Information [Line Items]      
Total segment operating income 1,075,902 2,399,042 2,751,842
Unallocated amounts:      
Corporate selling, general and administrative 300,470 236,171 252,645
Corporate other operating expenses 12,696 9,177 32,605
Operating Segments | Transmission      
Segment Reporting Information [Line Items]      
Total segment operating income 140,799    
Unallocated amounts:      
Corporate selling, general and administrative 17,183    
Corporate other operating expenses 0    
Intersegment eliminations      
Segment Reporting Information [Line Items]      
Total segment operating income 457 0 0
Unallocated amounts      
Segment Reporting Information [Line Items]      
Total segment operating income (390,606) (84,631) (33,845)
Unallocated amounts:      
Other revenue (34) 0 0
Corporate selling, general and administrative 36,254 0 0
Corporate other depreciation and amortization 16,761 9,765 9,119
Corporate other operating expenses 337,168 74,866 24,726
(Income) loss from investments (76,039) (7,596) 4,931
Other income (25,983) (1,231) (11,280)
Loss on debt extinguishment 68,299 80 140,029
Interest expense, net $ 454,825 $ 219,660 $ 249,655
v3.25.0.1
Financial Information by Business Segment - Schedule of Segment Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment assets:      
Investments in unconsolidated entities $ 3,617,397 $ 92,666  
Goodwill 2,079,481 0  
Total assets 39,830,255 25,285,098 $ 22,669,926
Operating Segments      
Segment assets:      
Investments in unconsolidated entities 3,534,730    
Goodwill 1,217,742    
Other segment assets 33,761,255    
Total assets 38,513,727 25,019,540 20,886,623
Production | Operating Segments      
Segment assets:      
Investments in unconsolidated entities 0    
Goodwill 0    
Other segment assets 22,546,098    
Total assets 22,546,098 23,803,913 20,469,506
Gathering | Operating Segments      
Segment assets:      
Investments in unconsolidated entities 0    
Goodwill 0    
Other segment assets 8,295,625    
Total assets 8,295,625 1,215,627 417,117
Transmission | Operating Segments      
Segment assets:      
Investments in unconsolidated entities 3,534,730    
Goodwill 1,217,742    
Other segment assets 2,919,532    
Total assets $ 7,672,004 $ 0 $ 0
v3.25.0.1
Financial Information by Business Segment - Schedule of Segment Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Segment Reporting Information [Line Items]      
Total assets $ 39,830,255 $ 25,285,098 $ 22,669,926
Cash and cash equivalents 202,093 80,977  
Income tax receivable 97,378 91,414  
Goodwill 2,079,481 0  
Other assets 455,623 206,692  
Operating Segments      
Segment Reporting Information [Line Items]      
Total assets 38,513,727 25,019,540 20,886,623
Goodwill 1,217,742    
Intersegment eliminations      
Segment Reporting Information [Line Items]      
Total assets (318,835) (47,471) (19,288)
Intersegment eliminations and other      
Segment Reporting Information [Line Items]      
Cash and cash equivalents 202,093 80,977 1,458,644
Income tax receivable 97,378 91,414 0
Other property, plant and equipment, at cost less accumulated depreciation 93,453 40,739 32,594
Goodwill 861,739 0 0
Total regulated assets 142,757 0 0
Other assets $ 237,943 $ 99,899 $ 311,353
v3.25.0.1
Financial Information by Business Segment - Schedule of Capital Expenditures By Segment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Expenditures for segment assets:      
Total capital expenditures $ 2,265,948 $ 1,925,243 $ 1,440,112
Operating Segments      
Expenditures for segment assets:      
Total capital expenditures 2,237,345 1,910,118 1,434,150
Operating Segments | Production      
Expenditures for segment assets:      
Total capital expenditures 2,003,635 1,878,417 1,427,995
Operating Segments | Gathering      
Expenditures for segment assets:      
Total capital expenditures 202,264 31,701 6,155
Operating Segments | Transmission      
Expenditures for segment assets:      
Total capital expenditures 31,446 0 0
Other corporate items      
Expenditures for segment assets:      
Total capital expenditures $ 28,603 $ 15,125 $ 5,962
v3.25.0.1
Revenue from Contracts with Customers - Narrative (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]    
Amounts due from contracts with customers $ 939.9 $ 584.8
Gathering | Affiliate Contract    
Disaggregation of Revenue [Line Items]    
Weighted average remaining term 14 years  
Gathering | Third-Party Contract    
Disaggregation of Revenue [Line Items]    
Weighted average remaining term 10 years  
Transmission | Affiliate Contract    
Disaggregation of Revenue [Line Items]    
Weighted average remaining term 13 years  
Transmission | Third-Party Contract    
Disaggregation of Revenue [Line Items]    
Weighted average remaining term 11 years  
Natural Gas, Oil, and NGLs Sales    
Disaggregation of Revenue [Line Items]    
Number of days in which payment is required 25 days  
Pipeline Revenue | Gathering    
Disaggregation of Revenue [Line Items]    
Number of days in which payment is required 21 days  
Number of days in which payment is invoiced 1 month  
Pipeline Revenue | Transmission    
Disaggregation of Revenue [Line Items]    
Number of days in which payment is required 10 days  
Gathering revenues supported by MVCs: | Gathering    
Disaggregation of Revenue [Line Items]    
Unbilled revenues $ 4.2  
v3.25.0.1
Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Disaggregation of Revenue [Line Items]      
Gain (loss) on derivatives $ 51,117 $ 1,838,941 $ (4,642,932)
Total operating revenues 5,273,309 6,908,923 7,497,689
Operating Segments      
Disaggregation of Revenue [Line Items]      
Gain (loss) on derivatives 51,117 1,838,941 (4,642,932)
Total operating revenues 5,977,826 7,057,753 7,581,010
Intersegment eliminations      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil (704,517) (148,830) (83,321)
Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Gain (loss) on derivatives 67,880 1,838,941 (4,642,932)
Total operating revenues 5,009,833 6,896,358 7,484,063
Gathering | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 766,463 161,395 96,947
Gain (loss) on derivatives (16,763) 0 0
Total operating revenues 749,700 161,395 96,947
Transmission | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 218,056 0 0
Gain (loss) on derivatives 0    
Total operating revenues 218,293    
Sales of natural gas, natural gas liquids and oil      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 4,934,366 5,044,768 12,114,168
Sales of natural gas, natural gas liquids and oil | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 4,934,366 5,044,768 12,114,168
Sales of natural gas, natural gas liquids and oil | Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 4,934,366 5,044,768 12,114,168
Sales of natural gas, natural gas liquids and oil | Gathering | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 0 0 0
Sales of natural gas, natural gas liquids and oil | Transmission | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 0    
Natural gas sales | Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 4,224,882 4,520,817 11,448,293
NGLs sales | Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 615,933 427,760 586,715
Oil sales | Production | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 93,551 96,191 79,160
Revenues From Contract With Customers      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 5,214,368 5,057,333 12,127,794
Net marketing services and other revenues      
Disaggregation of Revenue [Line Items]      
Net marketing services and other revenues 7,824 12,649 12,827
Total other sources of revenue      
Disaggregation of Revenue [Line Items]      
Total other sources of revenue 58,941 1,851,590 (4,630,105)
Firm reservation fee revenues | Gathering | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 313,987 0 0
Firm reservation fee revenues | Transmission | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 183,088 0 0
Volumetric-based fee revenues | Gathering | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 452,476 161,395 96,947
Volumetric-based fee revenues | Gathering | Operating Segments | Unbilled Revenues      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 4,500    
Volumetric-based fee revenues | Transmission | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil $ 34,968 $ 0 $ 0
v3.25.0.1
Revenue from Contracts with Customers - Remaining Performance Obligations (Details)
$ in Thousands
Dec. 31, 2024
USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 12,344,547
Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 4,922,201
Transmission | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 1,672,868
Transmission | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 3,249,333
Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 2,795,620
Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 4,626,726
Gathering | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 822,727
Gathering | Third-Party Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 580,881
Gathering | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 1,972,893
Gathering | Affiliate Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 4,045,845
Natural gas sales | Fixed-Price Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation 1,066,127
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 417,696
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Transmission | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 176,189
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Transmission | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 241,507
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 193,589
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 454,842
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Gathering | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 101,671
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Gathering | Third-Party Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 82,396
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Gathering | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 91,918
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Gathering | Affiliate Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 372,446
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Natural gas sales  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 1,116,702
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 435,480
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Transmission | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 174,435
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Transmission | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 261,045
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 194,039
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 487,183
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Gathering | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 92,311
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Gathering | Third-Party Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 89,217
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Gathering | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 101,728
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Gathering | Affiliate Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 397,966
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Natural gas sales  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 1,111,382
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 432,813
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Transmission | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 171,768
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Transmission | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 261,045
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 187,044
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 491,525
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Gathering | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 85,651
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Gathering | Third-Party Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 80,904
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Gathering | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 101,393
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Gathering | Affiliate Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 410,621
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Natural gas sales  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 1,102,370
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 430,125
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Transmission | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 169,410
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Transmission | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 260,715
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 183,352
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 488,893
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Gathering | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 85,651
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Gathering | Third-Party Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 77,153
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Gathering | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 97,701
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Gathering | Affiliate Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 411,740
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Natural gas sales  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 1,086,468
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 426,707
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Transmission | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 166,324
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Transmission | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 260,383
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 183,352
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 476,409
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Gathering | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 85,651
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Gathering | Third-Party Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 65,788
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Gathering | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 97,701
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Gathering | Affiliate Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 410,621
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Natural gas sales  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 6,861,498
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 2,779,380
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Transmission | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 814,742
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Transmission | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 1,964,638
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 1,854,244
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 2,227,874
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Third-Party Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 371,792
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Third-Party Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 185,423
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Affiliate Contract  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 1,482,452
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Affiliate Contract | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, remaining performance obligation $ 2,042,451
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Natural gas sales  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Remaining performance obligation, expected timing of satisfaction, period
v3.25.0.1
Derivative Instruments - Narrative (Details)
 12 Months Ended
Dec. 31, 2024
USD ($)
Bcf
Dec. 31, 2024
USD ($)
MBbls
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Bcf
Dec. 31, 2023
USD ($)
MBbls
Derivative Instruments, Gain (Loss) [Line Items]          
Maximum percentage of derivative liability     100.00%    
Aggregate fair value of derivative instruments with credit-risk related contingencies $ 61,900,000 $ 61,900,000 $ 61,900,000 $ 6,400,000 $ 6,400,000
Collateral posted 0 0 0 0 0
Over-the-Counter          
Derivative Instruments, Gain (Loss) [Line Items]          
Aggregate fair value of derivative instruments with credit-risk related contingencies 0 0 0 0 0
Exchange Traded Natural Gas Contracts          
Derivative Instruments, Gain (Loss) [Line Items]          
Collateral posted $ 87,000,000 $ 87,000,000 $ 87,000,000 $ 13,000,000 $ 13,000,000
Cash Flow Hedging | Natural Gas          
Derivative Instruments, Gain (Loss) [Line Items]          
Absolute quantities of derivative commodity instruments 2,189 2,562   2,045 1,049
v3.25.0.1
Derivative Instruments - Schedule of Impact of Netting Agreements and Margin Deposits on Gross Derivative Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Asset derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet $ 143,581 $ 978,634
Liability derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet 446,519 186,363
Commodity Contract    
Asset derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet 143,581 978,634
Derivative instruments subject to master netting agreements (117,350) (112,203)
Margin requirements with counterparties 0 0
Net derivative instruments 26,231 866,431
Liability derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet 446,519 186,363
Derivative instruments subject to master netting agreements (117,350) (112,203)
Margin requirements with counterparties (86,975) (13,017)
Liability derivative instruments, at fair value $ 242,194 $ 61,143
v3.25.0.1
Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset derivative instruments, at fair value $ 143,581 $ 978,634
Derivative instruments, at fair value 446,519 186,363
Recurring | Quoted prices in active markets  for identical assets (Level 1)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset derivative instruments, at fair value 50,300 66,302
Derivative instruments, at fair value 81,074 42,218
Recurring | Significant other observable inputs (Level 2)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset derivative instruments, at fair value 93,281 912,332
Derivative instruments, at fair value 365,445 144,145
Recurring | Significant unobservable inputs (Level 3)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset derivative instruments, at fair value 0 0
Derivative instruments, at fair value 0 0
Recurring | Estimate of Fair Value Measurement    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset derivative instruments, at fair value 143,581 978,634
Derivative instruments, at fair value $ 446,519 $ 186,363
v3.25.0.1
Fair Value Measurements - Narrative (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt, fair value $ 9,299,525 $ 6,267,476
Outstanding borrowings 9,324,177 5,795,113
Senior notes    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Outstanding borrowings 8,900,000 4,500,000
Senior notes | Significant other observable inputs (Level 2)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt, fair value 8,800,000 4,900,000
Note payable | EQT's note payable to EQM    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt, fair value 0  
Outstanding borrowings $ 0 88,483
Note payable | EQT's note payable to EQM | Significant unobservable inputs (Level 3)    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt, fair value   $ 91,063
v3.25.0.1
Acquisitions - Narrative (Details)
$ / shares in Units, $ in Thousands
 1 Months Ended 3 Months Ended 5 Months Ended 12 Months Ended
Jul. 22, 2024
USD ($)
$ / shares
shares
Apr. 11, 2024
USD ($)
Aug. 22, 2023
USD ($)
shares
Jul. 31, 2024
shares
Aug. 31, 2023
shares
Dec. 31, 2022
USD ($)
a
Dec. 31, 2024
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Dec. 31, 2022
USD ($)
a
Dec. 31, 2021
Business Acquisition [Line Items]                      
Transaction costs               $ 309,419 $ 56,263 $ 14,185  
Restructuring Charges, Statement of Income or Comprehensive Income [Extensible Enumeration]               Other Operating Income (Expense), Net      
2022 Asset Acquisition                      
Business Acquisition [Line Items]                      
Acres acquired | a           4,600       4,600  
Asset acquisition, consideration transferred           $ 56,000          
Equitrans Midstream Merger                      
Business Acquisition [Line Items]                      
Number of shares issuable for each existing share converted (in shares) 0.3504                    
Number of shares issued in business combination (in shares) | shares 152,427,848     152,427,848              
Equity issued as consideration for acquisition $ 5,548,608                    
Share price (in dollars per share) | $ / shares $ 35.88                    
Purchase and redemption price $ 685,337                    
Transaction costs             $ 280,600 $ 304,800      
Intangible asset, useful life 15 years                    
Finite-lived intangible assets amortization, year one $ 13,300                    
Finite-lived intangible assets amortization, year two 13,300                    
Finite-lived intangible assets amortization, year three 13,300                    
Finite-lived intangible assets amortization, year four 13,300                    
Finite-lived intangible assets amortization, year five $ 13,300                    
Amortization period 5 years                    
Goodwill attributed to synergies expected from the vertical integration of the business $ 1,200,000                    
Goodwill attributable to additional tax liabilities arising from the difference between preliminary purchase price allocation and tax basis 900,000                    
Goodwill, expected tax deductible amount 647,200                    
Purchase price 5,994,233                    
Cash (paid in lieu of fractional shares) 29                    
Equitrans Midstream Merger | Severance and other termination benefits and stock-based compensation                      
Business Acquisition [Line Items]                      
Restructuring charges               165,400      
Payments for restructuring               60,800      
Restructuring costs               104,600      
Equitrans Midstream Merger | Employees Of Equitrans Midstream                      
Business Acquisition [Line Items]                      
Equity issued as consideration for acquisition $ 79,500                    
NEPA Gathering System Acquisition                      
Business Acquisition [Line Items]                      
Percentage of operates and owns interest (percent)                     50.00%
Ownership interest acquired (percent)   33.75%                  
Purchase price   $ 205,000                  
Tug Hill and XcL Midstream                      
Business Acquisition [Line Items]                      
Number of shares issued in business combination (in shares) | shares     49,599,796   49,599,796            
Transaction costs               $ 4,400 $ 56,300    
Cash (paid in lieu of fractional shares)     $ 2,400,000                
v3.25.0.1
Acquisitions - Allocation of Purchase Price (Details) - USD ($)
$ in Thousands
Jul. 22, 2024
Dec. 31, 2024
Dec. 31, 2023
Fair value of liabilities assumed:      
Goodwill   $ 2,079,481 $ 0
Equitrans Midstream Merger      
Consideration:      
Equity $ 5,548,608    
Cash (paid in lieu of fractional shares) 29    
Redemption of Equitrans Midstream preferred stock 685,337    
Settlement of pre-existing relationships (239,741)    
Total consideration 5,994,233    
Fair value of assets acquired:      
Cash and cash equivalents 58,767    
Accounts receivable, net 82,072    
Income tax receivable 2,142    
Prepaid expenses and other 22,048    
Property, plant and equipment 9,379,642    
Investments in unconsolidated entities 3,363,336    
Net intangible assets 200,000    
Other assets 249,846    
Noncontrolling interest in consolidated subsidiaries (162,993)    
Amount attributable to assets acquired 13,194,860    
Fair value of liabilities assumed:      
Current portion of debt 699,837    
Accounts payable 65,006    
Accrued interest 47,996    
Other current liabilities 70,951    
Revolving credit facility borrowings 1,035,000    
Senior notes 6,273,941    
Deferred income taxes 935,106    
Other liabilities and credits 152,271    
Amount attributable to liabilities assumed 9,280,108    
Goodwill $ 2,079,481    
v3.25.0.1
Acquisitions - Post-Acquisition Operating Results (Details) - USD ($)
$ in Thousands
 5 Months Ended 12 Months Ended
Dec. 31, 2024
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Business Acquisition [Line Items]        
Loss on derivatives   $ 51,117 $ 1,838,941 $ (4,642,932)
Transaction costs   309,419 56,263 14,185
Operating Segments        
Business Acquisition [Line Items]        
Loss on derivatives   51,117 1,838,941 (4,642,932)
Operating Segments | Gathering        
Business Acquisition [Line Items]        
Loss on derivatives   (16,763) 0 $ 0
Equitrans Midstream Merger        
Business Acquisition [Line Items]        
Loss on derivatives $ (16,763)      
Pipeline, net marketing services and other 274,646      
Total operating revenues 257,883      
Net loss (a) (136,946)      
Less: Net income attributable to noncontrolling interests 12,879 28,303 $ 30,037  
Net loss attributable to EQT Corporation (149,825)      
Transaction costs $ 280,600 $ 304,800    
v3.25.0.1
Acquisitions - Unaudited Pro Forma Information (Details) - Equitrans Midstream Merger - USD ($)
$ / shares in Units, $ in Thousands
 5 Months Ended 12 Months Ended
Dec. 31, 2024
Dec. 31, 2024
Dec. 31, 2023
Pro forma operating revenues:      
Pro forma sales of natural gas, NGLs and oil   $ 4,934,366 $ 5,044,768
Pro forma gain on derivatives   17,685 1,887,016
Pro forma pipeline, net marketing services and other   621,214 616,245
Pro forma total operating revenues   5,573,265 7,548,029
Pro forma net income (a)   489,503 2,439,515
Less: Net income attributable to noncontrolling interests $ 12,879 28,303 30,037
Pro forma net income attributable to EQT Corporation   $ 461,200 $ 2,409,478
Pro forma net income attributable to EQT Corporation – Basic (in dollars per share)   $ 0.78 $ 4.52
Pro forma net income attributable to EQT Corporation – Diluted (in dollars per share)   $ 0.77 $ 4.27
v3.25.0.1
NEPA Non-Operated Asset Divestitures - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 30, 2024
May 31, 2024
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Gain (loss) on sale of long-lived assets     $ 764,044 $ (17,445) $ 8,446
Disposal group not discontinued operation gain loss on disposal statement of income extensible list not disclosed flag   (gain) loss on sale/exchange of long-lived assets      
EQT's 6.125% notes due February 1, 2025 | Senior notes          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Interest rate (percent)     6.125% 6.125%  
Disposal Group, Disposed of by Sale, Not Discontinued Operations | NEPA Non Operated Asset Divestiture          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Percentage of natural gas asset interest sold (percent)   40.00%      
Carrying amount of divestiture   $ 523,000      
Property, plant and equipment, carrying value   549,000      
Other current liabilities, carrying value   6,000      
Other liabilities, carrying value   20,000      
Proceeds from sale of oil and gas property and equipment   $ 500,000      
Equity interest to be received upon disposal (percent)   16.25%      
Gain (loss) on sale of long-lived assets     $ 299,000    
Divestiture cost     10,000    
Disposal Group, Disposed of by Sale, Not Discontinued Operations | NEPA Non Operated Asset Divestiture | Significant unobservable inputs (Level 3) | Estimate of Fair Value Measurement          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Fair value of consideration received, net of liabilities assumed   $ 832,000      
Property plant and equipment   $ 413,000      
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Second NEPA Non-Operated Assets Divestiture          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Percentage of natural gas asset interest sold (percent) 60.00%        
Carrying amount of divestiture $ 772,000        
Property, plant and equipment, carrying value 812,000        
Other current liabilities, carrying value 9,000        
Proceeds from sale of oil and gas property and equipment 1,250,000        
Gain (loss) on sale of long-lived assets     463,000    
Divestiture cost     $ 7,000    
Other liabilities and credits $ 31,000        
v3.25.0.1
The Midstream Joint Venture Transaction - Narrative (Details)
$ in Thousands, Bcf / d in Billions
 12 Months Ended
Dec. 30, 2024
USD ($)
Bcf / d
shares
Dec. 31, 2024
USD ($)
Schedule of Equity Method Investments [Line Items]    
Increase in noncontrolling interest   $ 3,422,531
Midstream Joint Venture    
Schedule of Equity Method Investments [Line Items]    
Annual minimum volume (in Bcf per day) | Bcf / d 1.6  
Cash consideration $ 3,500,000  
Increase in noncontrolling interest 3,500,000  
Decrease to additional paid in capital 77,500  
Transaction related expense $ 13,300  
Capital Unit, Class A | Midstream Joint Venture    
Schedule of Equity Method Investments [Line Items]    
Shares exchanged (in shares) | shares 364,285,715  
Capital Unit, Class A | Midstream Joint Venture | until the Base Return    
Schedule of Equity Method Investments [Line Items]    
Distribution allocation (percent) 40.00%  
Capital Unit, Class A | Midstream Joint Venture | after the Base Return    
Schedule of Equity Method Investments [Line Items]    
Distribution allocation (percent) 100.00%  
Capital Unit, Class A | Midstream Joint Venture | from the 8th anniversary of December 30, 2024 and thereafter    
Schedule of Equity Method Investments [Line Items]    
Distribution allocation (percent) 95.00%  
Capital Unit, Class B | Midstream Joint Venture    
Schedule of Equity Method Investments [Line Items]    
Shares exchanged (in shares) | shares 350,000,000  
Capital Unit, Class B | Midstream Joint Venture | until the Base Return    
Schedule of Equity Method Investments [Line Items]    
Distribution allocation (percent) 60.00%  
Capital Unit, Class B | Midstream Joint Venture | after the Base Return    
Schedule of Equity Method Investments [Line Items]    
Distribution allocation (percent) 0.00%  
Capital Unit, Class B | Midstream Joint Venture | from the 8th anniversary of December 30, 2024 and thereafter    
Schedule of Equity Method Investments [Line Items]    
Distribution allocation (percent) 5.00%  
v3.25.0.1
Income Taxes - Schedule of Income Tax (Benefit) Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Current:      
Federal $ 1,222 $ (10,894) $ 651
State 6,125 (4,818) 18,457
Subtotal 7,347 (15,712) 19,108
Deferred:      
Federal (21,463) 450,091 527,539
State 36,195 (65,425) 7,073
Subtotal 14,732 384,666 534,612
Total income tax expense $ 22,079 $ 368,954 $ 553,720
v3.25.0.1
Income Taxes - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Sep. 30, 2024
Tax Credit Carryforward [Line Items]        
Increase in deferred tax liability $ 946,300      
Deferred tax benefit (36,195) $ 65,425 $ (7,073)  
Total NOL carryforwards 708,518 740,802    
Valuation allowance 257,218 290,812    
Interest expense 600 (19,800) 6,700  
Interests and penalties 2,900 2,300 $ 22,200  
Decrease in unrecognized tax benefits is reasonably possible 14,600      
R&D tax credits        
Tax Credit Carryforward [Line Items]        
Settlement resulting in reduction of liabilities and deferred tax assets       $ 29,600
Domestic Tax Jurisdiction        
Tax Credit Carryforward [Line Items]        
Decrease in state net operating loss (NOL) carryforwards 214,100      
Decrease in state valuation allowance on NOL carryforwards 198,500      
Total NOL carryforwards 52,800      
Valuation allowance   52,800    
State and Local Jurisdiction        
Tax Credit Carryforward [Line Items]        
Total NOL carryforwards 2,300      
Valuation allowance $ 44,500 $ 46,800    
v3.25.0.1
Income Taxes - Schedule of Reconciliation of Income Tax Expense (Benefit) to Amount Computed at the Federal Statutory Rate (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Amount      
Income before income taxes $ 264,194 $ 2,103,498 $ 2,334,662
Tax at statutory rate 55,481 441,735 490,279
State income taxes 5,440 50,263 48,970
Valuation allowance (9,601) (81,483) 12,685
Convertible Notes repurchase premium 0 0 35,957
State law change (11,315) (21,670) (49,511)
Uncertain tax positions (16,977) (7,015) 11,135
Federal and state tax credits (6,537) (4,715) (4,319)
Transaction costs 6,041 0 0
Other (453) (8,161) 8,524
Total income tax expense $ 22,079 $ 368,954 $ 553,720
Rate      
Tax at statutory rate 21.00% 21.00% 21.00%
State income taxes 2.10% 2.40% 2.10%
Valuation allowance (3.60%) (3.90%) 0.50%
Convertible Notes repurchase premium 0.00% 0.00% 1.50%
State law change (4.30%) (1.00%) (2.10%)
Uncertain tax positions (6.40%) (0.30%) 0.50%
Federal and state tax credits (2.50%) (0.20%) (0.20%)
Transaction costs 2.30% 0.00% 0.00%
Other (0.20%) (0.40%) 0.40%
Income tax expense 8.40% 17.50% 23.70%
v3.25.0.1
Income Taxes - Summary of Source and Tax Effects of Temporary Differences between Financial Reporting and Tax Bases of Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Deferred tax assets:    
NOL carryforwards $ 708,518 $ 740,802
Interest disallowance limitation 106,622 59,668
Federal tax credits 89,644 92,730
Net unrealized losses 80,723 0
State capital loss carryforward 44,496 99,632
Incentive compensation and deferred compensation plans 18,032 16,854
Other 2,433 1,156
Deferred tax assets 1,050,468 1,010,842
Valuation allowance (257,218) (290,812)
Net deferred tax asset 793,250 720,030
Deferred tax liabilities:    
Property, plant and equipment (2,516,074) (2,457,946)
Investment in partnerships (1,128,279) 0
Net unrealized gains 0 (166,905)
Deferred tax liability (3,644,353) (2,624,851)
Net deferred tax liability $ (2,851,103) $ (1,904,821)
v3.25.0.1
Income Taxes - Schedule of Operating Loss Carryforwards (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards $ 708,518 $ 740,802
Total valuation allowance on NOL carryforwards (201,584) (181,627)
Federal NOL DTA    
Operating Loss Carryforwards [Line Items]    
Total valuation allowance on NOL carryforwards (14,263) (24,927)
Federal NOL DTA | Expires between 2032 to 2037    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards 14,644 67,958
Federal NOL DTA | Indefinite expiration    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards 322,258 323,598
State NOL DTA    
Operating Loss Carryforwards [Line Items]    
Total valuation allowance on NOL carryforwards (187,321) (156,700)
State NOL DTA | Indefinite expiration    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards 24,337 17,093
State NOL DTA | Expires between 2025 to 2037    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards $ 347,279 $ 332,153
v3.25.0.1
Income Taxes - Schedule of Reconciliation of the Beginning and Ending Amount of Reserve (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Unrecognized Tax Benefits [Roll Forward]      
Balance at January 1 $ 89,197 $ 204,035 $ 182,032
Additions for tax positions taken in current year 11,720 11,986 9,612
Additions for tax positions taken in prior years 15,177   12,391
(Reductions) for tax positions taken in prior years   (883)  
Reductions for tax positions settled with tax authorities (29,645) (125,941) 0
Reductions for lapse in statute of limitations (13,706) 0 0
Balance at December 31 $ 72,743 $ 89,197 $ 204,035
v3.25.0.1
Income Taxes - Schedule of Uncertain Tax Positions (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Income Tax Disclosure [Abstract]      
If recognized, effect to the effective tax rate $ 67,105 $ 83,669 $ 117,341
Reduction of related deferred tax asset for general business credit carryforwards and NOLs $ 60,415 $ 77,013 $ 110,744
v3.25.0.1
Debt - Schedule of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Jan. 19, 2024
Dec. 31, 2023
Apr. 30, 2020
Debt Instrument [Line Items]        
Principal Value $ 9,368,516   $ 5,836,058  
Carrying Value 9,324,177   5,795,113  
Fair Value 9,299,525   6,267,476  
Less: Current portion of debt, principal value 320,800   296,424  
Current portion of debt 320,800   292,432  
Less: Current portion of debt 320,800   774,983  
Total long-term debt, principal value 9,047,716   5,539,634  
Total long-term debt, carrying value 9,003,377   5,502,681  
Total long-term debt, fair value 8,978,725   5,492,493  
Senior notes        
Debt Instrument [Line Items]        
Carrying Value 8,900,000   4,500,000  
Senior notes | Significant other observable inputs (Level 2)        
Debt Instrument [Line Items]        
Fair Value 8,800,000   4,900,000  
EQT's revolving credit facility maturing July 23, 2029 | Credit facility        
Debt Instrument [Line Items]        
Principal Value 150,000   0  
Carrying Value 150,000   0  
Fair Value 150,000   0  
Eureka's revolving credit facility maturing November 13, 2025 | Credit facility        
Debt Instrument [Line Items]        
Principal Value 320,800   0  
Carrying Value 320,800   0  
Fair Value 320,800   0  
Term Loan Facility due June 30, 2026 | Loans Payable        
Debt Instrument [Line Items]        
Principal Value 0   1,250,000  
Carrying Value 0   1,244,265  
Fair Value $ 0   $ 1,244,265  
EQT's 6.125% notes due February 1, 2025 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 6.125%   6.125%  
Principal Value $ 0   $ 601,521  
Carrying Value 0   600,389  
Fair Value $ 0   $ 605,082  
EQT's 1.75% convertible notes due May 1, 2026 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 1.75%   1.75% 1.75%
Principal Value $ 0   $ 290,177  
Carrying Value 0   286,185  
Fair Value $ 0   $ 768,554  
EQT's 3.125% notes due May 15, 2026 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 3.125%   3.125%  
Principal Value $ 392,915   $ 392,915  
Carrying Value 391,193   389,978  
Fair Value $ 382,994   $ 373,261  
EQT's 7.75% debentures due July 15, 2026 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 7.75%   7.75%  
Principal Value $ 115,000   $ 115,000  
Carrying Value 114,213   113,716  
Fair Value $ 119,590   121,590  
EQM's 7.500% notes due June 1, 2027 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 7.50%      
Principal Value $ 500,000   0  
Carrying Value 511,377   0  
Fair Value $ 510,140   0  
EQM's 6.500% notes due July 1, 2027 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 6.50%      
Principal Value $ 900,000   0  
Carrying Value 915,538   0  
Fair Value $ 912,159   $ 0  
EQT's 3.90% notes due October 1, 2027 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 3.90%   3.90%  
Principal Value $ 1,169,503   $ 1,169,503  
Carrying Value 1,166,523   1,165,439  
Fair Value $ 1,137,248   $ 1,121,027  
EQT's 5.700% notes due April 1, 2028 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 5.70%   5.70%  
Principal Value $ 500,000   $ 500,000  
Carrying Value 492,640   490,376  
Fair Value $ 508,695   509,280  
EQM's 5.500% notes due July 15, 2028 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 5.50%      
Principal Value $ 118,683   0  
Carrying Value 118,204   0  
Fair Value $ 117,382   $ 0  
EQT's 5.00% notes due January 15, 2029 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 5.00%   5.00%  
Principal Value $ 318,494   $ 318,494  
Carrying Value 315,785   315,121  
Fair Value $ 314,357   316,784  
EQM's 4.50% notes due January 15, 2029 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 4.50%      
Principal Value $ 742,923   0  
Carrying Value 711,754   0  
Fair Value $ 711,297   0  
EQM's 6.375% notes due April 1, 2029 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 6.375%      
Principal Value $ 600,000   0  
Carrying Value 608,667   0  
Fair Value $ 606,774   $ 0  
EQT's 7.000% notes due February 1, 2030 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 7.00%   7.00%  
Principal Value $ 674,800   $ 674,800  
Carrying Value 671,641   671,020  
Fair Value $ 718,358   726,645  
EQM's 7.500% notes due June 1, 2030 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 7.50%      
Principal Value $ 500,000   0  
Carrying Value 535,671   0  
Fair Value $ 534,950   0  
EQM's 4.75% notes due January 15, 2031 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 4.75%      
Principal Value $ 1,100,000   0  
Carrying Value 1,045,219   0  
Fair Value $ 1,039,995   $ 0  
EQT's 3.625% notes due May 15, 2031 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 3.625%   3.625%  
Principal Value $ 435,165   $ 435,165  
Carrying Value 430,818   430,141  
Fair Value $ 388,111   389,925  
EQT's 5.750% notes due February 1, 2034 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 5.75% 5.75%    
Principal Value $ 750,000 $ 750,000 0  
Carrying Value 742,796   0  
Fair Value $ 744,743   0  
EQM's 6.500% notes due July 15, 2048 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent) 6.50%      
Principal Value $ 80,233   0  
Carrying Value 81,338   0  
Fair Value 81,932   0  
EQT's note payable to EQM | Note payable        
Debt Instrument [Line Items]        
Principal Value 0   88,483  
Carrying Value 0   88,483  
Fair Value $ 0      
EQT's note payable to EQM | Note payable | Significant unobservable inputs (Level 3)        
Debt Instrument [Line Items]        
Fair Value     $ 91,063  
1.75% convertible notes due May 1, 2026 | Senior notes        
Debt Instrument [Line Items]        
Interest rate (percent)       1.75%
Principal Value       $ 500,000
v3.25.0.1
Debt - Debt Instrument Redemption (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 10, 2024
Nov. 25, 2024
Dec. 31, 2023
Apr. 30, 2020
Senior notes          
Debt Instrument [Line Items]          
Principal $ 4,310,265        
Premium/(Discounts) 44,317        
Accrued but Unpaid Interest 72,950        
Total Cost 4,427,532        
Third party costs $ 7,800        
EQM Midstream 6.000% notes due July 1, 2025 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 6.00%        
Principal $ 400,000        
Premium/(Discounts) 1,284        
Accrued but Unpaid Interest 11,933        
Total Cost $ 413,217        
EQM Midstream 4.125% notes due December 1, 2026 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 4.125%        
Principal $ 500,000        
Premium/(Discounts) 0        
Accrued but Unpaid Interest 1,662        
Total Cost $ 501,662        
EQM's 5.500% notes due July 15, 2028 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 5.50%        
Principal $ 731,317        
Premium/(Discounts) 15,541        
Accrued but Unpaid Interest 18,435        
Total Cost $ 765,293        
EQM's 4.50% notes due January 15, 2029 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 4.50%        
Principal $ 57,077        
Premium/(Discounts) (713)        
Accrued but Unpaid Interest 1,177        
Total Cost $ 57,541        
EQM's 6.500% notes due July 15, 2048 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 6.50%        
Principal $ 469,767        
Premium/(Discounts) 27,012        
Accrued but Unpaid Interest 13,995        
Total Cost $ 510,774        
EQM's 4.00% notes due August 1, 2024 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 4.00%     4.00%  
Principal $ 300,000        
Premium/(Discounts) 0        
Accrued but Unpaid Interest 6,000        
Total Cost $ 306,000        
EQT's 6.125% notes due February 1, 2025 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 6.125%     6.125%  
Principal $ 601,521        
Premium/(Discounts) 1,178        
Accrued but Unpaid Interest 13,612        
Total Cost 616,311        
Term Loan Facility due June 30, 2026 | Loans Payable          
Debt Instrument [Line Items]          
Principal 1,250,000        
Premium/(Discounts) 15        
Accrued but Unpaid Interest 6,136        
Total Cost $ 1,256,151        
EQT's 1.75% convertible notes due May 1, 2026 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 1.75%     1.75% 1.75%
Principal $ 583        
Premium/(Discounts) 0        
Accrued but Unpaid Interest 0        
Total Cost $ 583        
EQT's note payable to EQM | Senior notes          
Debt Instrument [Line Items]          
Total Cost   $ 1,300,000 $ 1,275,000    
v3.25.0.1
Debt - Narrative (Details)
 1 Months Ended 4 Months Ended 5 Months Ended 9 Months Ended 12 Months Ended
Dec. 30, 2024
USD ($)
Dec. 27, 2024
USD ($)
Jul. 22, 2024
USD ($)
extension
Jan. 22, 2024
USD ($)
Jan. 19, 2024
USD ($)
Jan. 17, 2024
USD ($)
Jan. 12, 2024
USD ($)
shares
Aug. 21, 2023
USD ($)
Nov. 09, 2022
USD ($)
Jan. 31, 2024
USD ($)
$ / shares
shares
Jan. 17, 2024
Apr. 30, 2020
USD ($)
$ / shares
Dec. 31, 2023
USD ($)
Dec. 31, 2024
USD ($)
Aug. 20, 2023
Dec. 31, 2024
USD ($)
Dec. 30, 2024
Dec. 31, 2023
USD ($)
Dec. 31, 2022
USD ($)
Dec. 10, 2024
USD ($)
Nov. 25, 2024
USD ($)
Nov. 22, 2024
USD ($)
Debt Instrument [Line Items]                                            
Proceeds from revolving credit facility borrowings                               $ 6,887,000,000   $ 1,007,000,000 $ 10,242,000,000      
Debt instrument, face amount                         $ 5,836,058,000 $ 9,368,516,000   9,368,516,000   5,836,058,000        
Repayments of long-term debt                               4,313,867,000   1,015,836,000 917,039,000      
Outstanding borrowings                         5,795,113,000 9,324,177,000   9,324,177,000   5,795,113,000        
Payments of debt issuance costs                               18,854,000   5,336,000 26,506,000      
Issuance of common stock for convertible notes settlement                               285,608,000   122,830,000 63,000      
Settlement of capped call transaction                               93,290,000   0 0      
Capped call                                            
Debt Instrument [Line Items]                                            
Settlement of capped call transaction       $ 93,300,000                                    
Senior notes                                            
Debt Instrument [Line Items]                                            
Outstanding borrowings                         $ 4,500,000,000 8,900,000,000   8,900,000,000   4,500,000,000        
Aggregate purchase price                           4,427,532,000   4,427,532,000            
Aggregate maturities in 2025                           0   0            
Aggregate maturities in 2026                           508,000,000   508,000,000            
Aggregate maturities in 2027                           1,170,000,000   1,170,000,000            
Aggregate maturities in 2028                           500,000,000   500,000,000            
Aggregate maturities in 2029                           318,000,000   318,000,000            
Aggregate maturities thereafter                           1,860,000,000   1,860,000,000            
Conversion strike price (in dollars per share) | $ / shares                       $ 15.00                    
Capped price (in dollars per share) | $ / shares                       $ 18.75                    
Senior notes | Capped call                                            
Debt Instrument [Line Items]                                            
Capped call transaction                       $ 32,500,000                    
Senior Unsecured Bridge Term Loan | Unsecured Debt | EQM                                            
Debt Instrument [Line Items]                                            
Proceeds from revolving credit facility borrowings   $ 2,230,000,000                                        
Debt instrument, face amount                                           $ 2,300,000,000
EQM Revolving Credit Facility | Note payable | EQM                                            
Debt Instrument [Line Items]                                            
Repayments of long-term debt     $ 705,000,000                                      
Payments of interest and fees     4,500,000                                      
Term Loan Facility due June 30, 2026 | Loans Payable                                            
Debt Instrument [Line Items]                                            
Weighted average interest rates                         6.90%       6.80%          
Unused commitment fee paid to maintain credit facility                             0.20%              
Debt instrument, face amount                         $ 1,250,000,000 0   0   1,250,000,000        
Repayments of long-term debt $ 500,000,000       $ 750,000,000                                  
Proceeds from issuance of debt               $ 1,250,000,000 $ 1,250,000,000                          
Net of issuance costs               $ 1,242,900,000                            
Outstanding borrowings                         1,244,265,000 0   0   1,244,265,000        
Aggregate purchase price                           1,256,151,000   1,256,151,000            
EQT's 5.750% notes due February 1, 2034 | Senior notes                                            
Debt Instrument [Line Items]                                            
Debt instrument, face amount         $ 750,000,000               0 $ 750,000,000   $ 750,000,000   0        
Interest rate (percent)         5.75%                 5.75%   5.75%            
Outstanding borrowings                         0 $ 742,796,000   $ 742,796,000   0        
Net proceeds from issuance of the senior notes         $ 742,000,000                                  
EQT's note payable to EQM                                            
Debt Instrument [Line Items]                                            
Aggregate maturities in 2025                           0   0            
Aggregate maturities in 2026                           0   0            
Aggregate maturities in 2027                           1,400,000,000   1,400,000,000            
Aggregate maturities in 2028                           119,000,000   119,000,000            
Aggregate maturities in 2029                           1,343,000,000   1,343,000,000            
Aggregate maturities thereafter                           1,680,000,000   1,680,000,000            
EQT's note payable to EQM | Note payable                                            
Debt Instrument [Line Items]                                            
Debt instrument, face amount                         88,483,000 0   0   88,483,000        
Outstanding borrowings                         88,483,000 0   0   88,483,000        
EQT's note payable to EQM | Senior notes                                            
Debt Instrument [Line Items]                                            
Aggregate purchase price                                       $ 1,300,000,000 $ 1,275,000,000  
EQM's 6.500% notes due July 15, 2048 | Senior notes                                            
Debt Instrument [Line Items]                                            
Debt instrument, face amount                         0 $ 80,233,000   $ 80,233,000   0        
Interest rate (percent)                           6.50%   6.50%            
Outstanding borrowings                         0 $ 81,338,000   $ 81,338,000   0        
Aggregate purchase price                           510,774,000   510,774,000            
EQM's 5.500% notes due July 15, 2028 | Senior notes                                            
Debt Instrument [Line Items]                                            
Debt instrument, face amount                         0 $ 118,683,000   $ 118,683,000   0        
Interest rate (percent)                           5.50%   5.50%            
Outstanding borrowings                         0 $ 118,204,000   $ 118,204,000   0        
Aggregate purchase price                           765,293,000   765,293,000            
EQM's 4.50% notes due January 15, 2029 | Senior notes                                            
Debt Instrument [Line Items]                                            
Debt instrument, face amount                         0 $ 742,923,000   $ 742,923,000   0        
Interest rate (percent)                           4.50%   4.50%            
Outstanding borrowings                         0 $ 711,754,000   $ 711,754,000   0        
Aggregate purchase price                           57,541,000   57,541,000            
EQM's 7.500% notes due June 1, 2030 | Senior notes                                            
Debt Instrument [Line Items]                                            
Debt instrument, face amount                         0 $ 500,000,000   $ 500,000,000   0        
Interest rate (percent)                           7.50%   7.50%            
Outstanding borrowings                         0 $ 535,671,000   $ 535,671,000   0        
EQM Midstream 6.000% notes due July 1, 2025 | Senior notes                                            
Debt Instrument [Line Items]                                            
Interest rate (percent)                           6.00%   6.00%            
Aggregate purchase price                           $ 413,217,000   $ 413,217,000            
EQM Midstream 4.125% notes due December 1, 2026 | Senior notes                                            
Debt Instrument [Line Items]                                            
Interest rate (percent)                           4.125%   4.125%            
Aggregate purchase price                           $ 501,662,000   $ 501,662,000            
1.75% convertible notes due May 1, 2026 | Senior notes                                            
Debt Instrument [Line Items]                                            
Debt instrument, face amount                       $ 500,000,000                    
Interest rate (percent)                       1.75%                    
Effective interest rate (percent)           2.40%         2.40%                      
Conversion ratio             0.0690364                              
Debt principal repaid           $ 600,000                                
January 2024 | Senior notes                                            
Debt Instrument [Line Items]                                            
Redemption price, percentage                     100.00%                      
Debt conversion, converted instrument, amount             $ 289,600,000                              
Shares issued (in shares) | shares             19,992,482                              
Issuance of common stock for convertible notes settlement             $ 285,600,000                              
Convertible Debt Settled January 2024, Including Exercise Notices Received In December 2023 | Senior notes                                            
Debt Instrument [Line Items]                                            
Debt conversion, converted instrument, amount                   $ 290,200,000                        
Shares issued (in shares) | shares                   20,036,639                        
Average conversion price (in dollars per share) | $ / shares                   $ 38.03                        
Revolving Credit Facility | PNC Bank, National Association                                            
Debt Instrument [Line Items]                                            
Financial commitments held under revolving credit facility (percent)                               10.00%            
Revolving Credit Facility | EQT Fourth A& R Revolving Credit Facility                                            
Debt Instrument [Line Items]                                            
Line of credit facility, maximum borrowing capacity     $ 3,500,000,000                     $ 3,500,000,000   $ 3,500,000,000            
Number of extensions | extension     2                                      
Extension term     1 year                                      
Commitment amount     $ 1,000,000,000                                      
Financial commitments under facility percentage                           65.00%   65.00%            
Letters of credit outstanding                         $ 15,000,000 $ 1,000,000   $ 1,000,000   15,000,000        
Maximum amount of outstanding borrowings                               2,357,000,000   269,000,000 1,300,000,000      
Average daily balance of loans outstanding                               $ 936,000,000   $ 40,000,000 $ 466,000,000      
Weighted average interest rates                               6.60%   6.90% 2.80%      
Unused commitment fee paid to maintain credit facility                               0.20%   0.20% 0.20%      
Revolving Credit Facility | EQT Fourth A& R Revolving Credit Facility | Secured Overnight Financing Rate (SOFR)                                            
Debt Instrument [Line Items]                                            
Credit spread adjustment (percent)     0.10%                                      
Revolving Credit Facility | EQT Fourth A& R Revolving Credit Facility | Minimum | Base Rate                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)     0.125%                                      
Revolving Credit Facility | EQT Fourth A& R Revolving Credit Facility | Minimum | Secured Overnight Financing Rate (SOFR)                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)     1.125%                                      
Revolving Credit Facility | EQT Fourth A& R Revolving Credit Facility | Maximum | Base Rate                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)     1.00%                                      
Revolving Credit Facility | EQT Fourth A& R Revolving Credit Facility | Maximum | Secured Overnight Financing Rate (SOFR)                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)     2.00%                                      
Revolving Credit Facility | Eureka Revolving Credit Facility                                            
Debt Instrument [Line Items]                                            
Line of credit facility, maximum borrowing capacity                           400,000,000   $ 400,000,000            
Letters of credit outstanding                           0   $ 0            
Maximum amount of outstanding borrowings                           330,000,000                
Average daily balance of loans outstanding                           $ 328,000,000                
Weighted average interest rates                           7.80%                
Unused commitment fee paid to maintain credit facility                           0.50%                
Revolving Credit Facility | Eureka Revolving Credit Facility | Secured Overnight Financing Rate (SOFR)                                            
Debt Instrument [Line Items]                                            
Credit spread adjustment (percent)                           0.10%                
Revolving Credit Facility | Eureka Revolving Credit Facility | Minimum | Base Rate                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)                           1.00%                
Revolving Credit Facility | Eureka Revolving Credit Facility | Minimum | Secured Overnight Financing Rate (SOFR)                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)                           2.00%                
Revolving Credit Facility | Eureka Revolving Credit Facility | Maximum | Base Rate                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)                           2.25%                
Revolving Credit Facility | Eureka Revolving Credit Facility | Maximum | Secured Overnight Financing Rate (SOFR)                                            
Debt Instrument [Line Items]                                            
Basis spread on variable rate (percent)                           3.25%                
v3.25.0.1
Investments in Unconsolidated Entities - Schedule of Equity Method Investments (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]    
Carrying Value $ 3,584,155 $ 56,623
MVP Joint Venture    
Schedule of Equity Method Investments [Line Items]    
Carrying Value $ 3,534,730 $ 0
The MVP    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 49.30% 0.00%
Carrying Value $ 3,469,438 $ 0
MVP Southgate    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 47.20% 0.00%
Carrying Value $ 65,292 $ 0
Laurel Mountain Midstream, LLC    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 31.00% 31.00%
Carrying Value $ 28,757 $ 39,923
WATT Fuel Cell Corporation    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 15.63% 15.43%
Carrying Value $ 14,533 $ 16,700
Yellowbird Energy LLC    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 50.00% 0.00%
Carrying Value $ 6,135 $ 0
v3.25.0.1
Investments in Unconsolidated Entities - Narrative (Details)
Dekatherm in Thousands, $ in Millions
 1 Months Ended 5 Months Ended 12 Months Ended
Dec. 31, 2023
USD ($)
Dekatherm
mi
in
Dec. 31, 2024
USD ($)
mi
in
Dec. 31, 2024
USD ($)
Bcf / d
mi
in
Feb. 03, 2025
USD ($)
the Investment Fund        
Schedule of Equity Method Investments [Line Items]        
Investment owned $ 36.1 $ 33.2 $ 33.2  
Mountain Valley Pipeline | MVP Joint Venture        
Schedule of Equity Method Investments [Line Items]        
Natural gas interstate pipeline (in miles) | mi   303 303  
Pipeline diameter (in inches) | in   42 42  
Annual minimum volume (in Bcf per day) | Bcf / d     2.0  
Estimated total project costs, excluding allowance for funds used   $ 8,100.0 $ 8,100.0  
Merger related costs   142.8    
Accretion, net   $ 1,300.0 $ 1,300.0  
MVP Southgate | MVP Joint Venture        
Schedule of Equity Method Investments [Line Items]        
Pipeline diameter (in inches) | in 30      
Annual minimum volume (in Bcf per day) | Dekatherm 550      
Remaining capital obligation, percentage 33.00%      
MVP Southgate | Pittsylvania | MVP Joint Venture        
Schedule of Equity Method Investments [Line Items]        
Natural gas interstate pipeline (in miles) | mi 31 75 75  
MVP Southgate | Rockingham County, North Carolina | MVP Joint Venture        
Schedule of Equity Method Investments [Line Items]        
Pipeline diameter (in inches) | in   24 24  
MVP Southgate | Alamance County, North Carolina | MVP Joint Venture        
Schedule of Equity Method Investments [Line Items]        
Pipeline diameter (in inches) | in   16 16  
Minimum | MVP Southgate | Subsequent Event        
Schedule of Equity Method Investments [Line Items]        
Estimated cost       $ 370.0
Maximum | MVP Southgate | Subsequent Event        
Schedule of Equity Method Investments [Line Items]        
Estimated cost       $ 430.0
v3.25.0.1
Investments in Unconsolidated Entities - Schedule of Financial Statements For The Investment in Unconsolidated Equity (Details) - USD ($)
$ in Thousands
 5 Months Ended 12 Months Ended
Dec. 31, 2024
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]          
Operating revenues   $ 5,273,309 $ 6,908,923 $ 7,497,689  
Net income   242,115 1,734,544 1,780,942  
Current assets $ 1,714,679 1,714,679 2,012,975    
Total assets 39,830,255 39,830,255 25,285,098 22,669,926  
Current liabilities 2,461,549 2,461,549 2,036,840    
Total liabilities 15,552,119 15,552,119 10,504,281    
Members' equity 24,278,136 24,278,136 14,780,817 $ 11,213,328 $ 9,970,999
Total liabilities and equity 39,830,255 39,830,255 $ 25,285,098    
MVP Joint Venture          
Schedule of Equity Method Investments [Line Items]          
Operating revenues 247,360        
Operating income 126,202        
Net income 129,773        
Current assets 204,028 204,028      
Noncurrent assets 9,535,975 9,535,975      
Total assets 9,740,003 9,740,003      
Current liabilities 69,303 69,303      
Noncurrent liabilities 1,514 1,514      
Total liabilities 70,817 70,817      
Members' equity 9,669,186 9,669,186      
Total liabilities and equity $ 9,740,003 $ 9,740,003      
v3.25.0.1
Common Stock and Income Per Share - Narrative (Details) - USD ($)
$ in Millions
 1 Months Ended 37 Months Ended
Jul. 22, 2024
Aug. 22, 2023
Jul. 31, 2024
Aug. 31, 2023
Dec. 31, 2024
Dec. 18, 2024
Jul. 18, 2024
Jul. 17, 2024
Dec. 31, 2023
Apr. 26, 2023
Dec. 31, 2022
Sep. 06, 2022
Dec. 13, 2021
Class of Stock [Line Items]                          
Common stock, authorized shares (in shares)         1,280,000,000   1,280,000,000 640,000,000 640,000,000   640,000,000    
Equitrans Midstream Merger                          
Class of Stock [Line Items]                          
Number of shares issued in business combination (in shares) 152,427,848   152,427,848                    
Tug Hill and XcL Midstream                          
Class of Stock [Line Items]                          
Number of shares issued in business combination (in shares)   49,599,796   49,599,796                  
Share Repurchase Program                          
Class of Stock [Line Items]                          
Aggregate purchase price authorized (up to)                       $ 2,000.0 $ 1,000.0
Increase to the authorized repurchase amount                       $ 1,000.0  
Extension           2 years       1 year      
Shares repurchased since inception         $ 622.1                
Stock compensation plans                          
Class of Stock [Line Items]                          
Common stock authorized and unissued (in shares)         19,300,000                
v3.25.0.1
Common Stock and Income Per Share - EQT Common Stock Repurchased (Details) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended 36 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2024
Class of Stock [Line Items]        
Stock repurchased (in shares) 0      
Share Repurchase Program        
Class of Stock [Line Items]        
Shares of EQT Corporation Common Stock Repurchased (in shares)   5,906,159 13,139,641 19,045,800
Aggregate Purchase Price   $ 200.0 $ 392.7 $ 592.7
Average Price Per Share (in dollars per share)   $ 33.86 $ 29.89  
v3.25.0.1
Common Stock and Income Per Share - Schedule of Earnings Per Share, Basic and Diluted (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Equity [Abstract]      
Net income attributable to EQT Corporation – Basic income available to shareholders $ 230,577 $ 1,735,232 $ 1,770,965
Add back: Interest expense on Convertible Notes, net of tax 86 7,551 8,019
Diluted income available to shareholders $ 230,663 $ 1,742,783 $ 1,778,984
Weighted average common stock outstanding - Basic (in shares) 509,597 380,902 370,048
Options, restricted stock, performance awards and stock appreciation rights (in shares) 4,625 5,232 5,731
Convertible Notes (in shares) 371 27,090 30,716
Weighted average common stock outstanding - diluted (in shares) 514,593 413,224 406,495
Net income attributable to EQT Corporation - Basic (in dollars per share) $ 0.45 $ 4.56 $ 4.79
Net income attributable to EQT Corporation - Diluted (in dollars per share) $ 0.45 $ 4.22 $ 4.38
v3.25.0.1
Share-Based Compensation Plans - Schedule of Share-Based Compensation Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense $ 49,988 $ 51,200 $ 67,411
Other operating expense      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 105,400 3,600 0
Restricted stock awards      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 25,473 20,119 23,028
Stock appreciation rights      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 0 4,056 17,406
Other programs, including non-employee director awards      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 3,596 3,110 3,534
Incentive Performance Share Unit Programs      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense $ 20,919 $ 23,915 $ 23,443
v3.25.0.1
Share-Based Compensation Plans - Narrative (Details) - USD ($)
 1 Months Ended 2 Months Ended 12 Months Ended
Apr. 30, 2022
Feb. 19, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Cash received from exercises of all share-based payment arrangements for employees and directors     $ 5,100,000 $ 0 $ 15,900,000  
Income tax benefit by the exercise of nonqualified employee stock options and vesting of restricted share awards     7,700,000 16,500,000 4,100,000  
Cash paid for taxes related to net settlement of share-based incentive awards     102,872,000 41,780,000 24,773,000  
Capitalized compensation cost     10,095,000 6,287,000 5,406,000  
Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Capitalized compensation cost     $ 500,000 $ 600,000 $ 600,000  
Performance Shares            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Award requisite service period     36 months      
Risk-free rate term     3 years      
Performance Shares | 2023 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Unrecognized compensation costs on non-vested awards     $ 4,800,000      
Performance Shares | 2024 Incentive Performance Share Unit Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Unrecognized compensation costs on non-vested awards     $ 10,200,000      
Performance Shares | Incentive PSU Programs – Equity Settled            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Non-vested shares, granted in period (in shares)     371,500 404,790 575,120  
Weighted average fair value, granted in period (in dollars per share) $ 75.32   $ 40.08 $ 38.79 $ 29.73  
Value     $ 31,920,023 $ 11,637,401 $ 18,422,830  
Performance Shares | Minimum | 2020 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     0.00%      
Performance Shares | Minimum | 2023 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     0.00%      
Performance Shares | Minimum | 2021 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     0.00%      
Performance Shares | Minimum | 2022 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     0.00%      
Performance Shares | Minimum | 2024 Incentive Performance Share Unit Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     0.00%      
Performance Shares | Maximum | 2020 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     150.00%      
Performance Shares | Maximum | 2023 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     200.00%      
Performance Shares | Maximum | 2021 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     200.00%      
Performance Shares | Maximum | 2022 Incentive PSU Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     220.00%      
Performance Shares | Maximum | 2024 Incentive Performance Share Unit Program            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level     200.00%      
Performance Share, Equity Awards | 2025 Incentive Performance Share Unit Program | Subsequent Event            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Non-vested shares, granted in period (in shares)   374,800        
Performance Share, Equity Awards | Minimum | 2025 Incentive Performance Share Unit Program | Subsequent Event            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level   0.00%        
Performance Share, Equity Awards | Maximum | 2025 Incentive Performance Share Unit Program | Subsequent Event            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Compensation plan, award as a percentage of target award level   200.00%        
Restricted stock awards            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Capitalized compensation cost     $ 9,600,000 5,700,000 6,600,000  
Unrecognized compensation costs on non-vested awards     44,100,000      
Value     $ 155,500,000 $ 23,500,000 $ 16,600,000  
Period for recognition     1 year      
Restricted stock awards | Key Employees            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Non-vested shares, granted in period (in shares)     982,990 953,270 1,288,430  
Period after which the shares granted will be fully vested     3 years      
Weighted average fair value, granted in period (in dollars per share)     $ 34.54 $ 31.88 $ 21.65  
Restricted stock awards | Incentive PSU Programs – Equity Settled            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Non-vested shares, granted in period (in shares)     982,990 953,270 1,288,430  
Weighted average fair value, granted in period (in dollars per share)     $ 34.54 $ 31.88 $ 21.65  
Aggregate fair value, conversion     $ 185,708,206      
Value     $ 155,480,899 $ 23,482,927 $ 16,644,859  
Restricted Stock Units (RSUs)            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Awards issued (in shares)     5,175,814      
Aggregate fair value, conversion     $ 106,300,000      
Restricted Stock Units (RSUs) | Subsequent Event            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Non-vested shares, granted in period (in shares)   1,111,480        
Period after which the shares granted will be fully vested   3 years        
Non-Qualified Stock Options            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Number of options granted (in shares)     0 0 0 1,000,000
Total Intrinsic Value of Exercises     $ 700,000 $ 1,400,000 $ 20,200,000  
Stock appreciation rights            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Weighted average fair value, granted in period (in dollars per share)           $ 10.00
Number of options granted (in shares)           1,240,000
Total Intrinsic Value of Exercises       $ 33,400,000 $ 0 $ 0
Other programs, including non-employee director awards            
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]            
Shares outstanding (in shares)     564,968      
Shares granted (in shares)     70,930 66,300 44,800  
Weighted average fair value, granted (in dollars per share)     $ 36.14 $ 33.31 $ 43.97  
v3.25.0.1
Share-Based Compensation Plans - Schedule of Executive Performance Incentive Programs (Details) - Incentive PSU Programs – Equity Settled - USD ($)
 1 Months Ended 4 Months Ended 12 Months Ended
Apr. 30, 2022
Apr. 30, 2022
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Aggregate Fair Value          
Increase in weighted average grant date fair value (in dollars per share)   $ 45.59      
Performance Shares          
Non- Vested Shares          
Non-vested shares, outstanding, beginning balance (in shares)   2,754,648 1,831,553 2,861,990 2,754,648
Non-vested shares, granted in period (in shares)     371,500 404,790 575,120
Non-vested shares, granted from multiplier (in shares)     451,805 409,383 162,183
Non-vested shares, vested (in shares)     (1,355,415) (1,773,994) (625,563)
Non-vested shares, forfeited (in shares)     (7,092) (70,616) (4,398)
Non-vested shares, outstanding, ending balance (in shares)     1,292,351 1,831,553 2,861,990
Weighted Average Fair Value          
Weighted average fair value, outstanding, beginning balance (in dollars per share)   $ 16.08 $ 28.27 $ 16.66 $ 16.08
Weighted average fair value, granted in period (in dollars per share) $ 75.32   40.08 38.79 29.73
Weighted average fair value, granted from multiplier (in dollars per share)     23.55 6.56 29.45
Weighted average fair value, vested (in dollars per share)     23.55 6.56 29.45
Weighted average fair value, forfeited (in dollars per share)     45.94 37.59 13.28
Weighted average fair value, outstanding, ending balance (in dollars per share)     $ 34.86 $ 28.27 $ 16.66
Aggregate Fair Value          
Aggregate fair value, beginning balance   $ 44,281,509 $ 51,770,381 $ 47,674,881 $ 44,281,509
Aggregate fair value, granted in period     14,889,720 15,701,804 17,098,318
Aggregate fair value, granted from multiplier     10,640,008 2,685,552 4,776,289
Aggregate fair value, vested     (31,920,023) (11,637,401) (18,422,830)
Aggregate fair value, forfeited     (325,806) (2,654,455) (58,405)
Aggregate fair value, ending balance     $ 45,054,280 $ 51,770,381 $ 47,674,881
v3.25.0.1
Share-Based Compensation Plans - Summary of Monte Carlo Simulation Valuation Method (Details) - PSU incentives - grant_date
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Risk-free interest rate 4.35% 4.16% 1.52% 0.18% 1.22%
Volatility factor 48.82% 59.31% 65.38% 72.50% 45.41%
Expected term 3 years 3 years 3 years 3 years 3 years
Number of grant dates   2   2 3
v3.25.0.1
Share-Based Compensation Plans - Summary of Restricted Stock Activity (Details) - Restricted Stock - USD ($)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Aggregate Fair Value      
Aggregate fair value, vested $ (155,500,000) $ (23,500,000) $ (16,600,000)
Incentive PSU Programs – Equity Settled      
Non- Vested Shares      
Non-vested shares, outstanding, beginning balance (in shares) 2,217,802 2,926,945 3,104,281
Non-vested shares, granted in period (in shares) 982,990 953,270 1,288,430
Non-vested shares, vested (in shares) (4,861,796) (1,544,968) (1,368,577)
Non-vested shares, conversion (in shares) 5,175,814    
Non-vested shares, forfeited (in shares) (90,641) (117,445) (97,189)
Non-vested shares, outstanding, ending balance (in shares) 3,424,169 2,217,802 2,926,945
Weighted Average Fair Value      
Weighted average fair value, outstanding, beginning balance (in dollars per share) $ 23.82 $ 16.67 $ 12.58
Weighted average fair value, granted in period (in dollars per share) 34.54 31.88 21.65
Weighted average fair value, vested (in dollars per share) 31.98 15.20 12.16
Weighted average fair value, conversion (in dollars per share) 35.88    
Weighted average fair value, forfeited (in dollars per share) 31.92 24.52 15.56
Weighted average fair value, outstanding, ending balance (in dollars per share) $ 33.32 $ 23.82 $ 16.67
Aggregate Fair Value      
Aggregate fair value, outstanding, beginning balance $ 52,819,850 $ 48,792,574 $ 39,056,435
Aggregate fair value, granted 33,950,507 30,389,954 27,893,331
Aggregate fair value, vested (155,480,899) (23,482,927) (16,644,859)
Aggregate fair value, conversion 185,708,206    
Aggregate fair value, forfeited (2,893,279) (2,879,751) (1,512,333)
Aggregate fair value, outstanding, ending balance $ 114,104,385 $ 52,819,850 $ 48,792,574
v3.25.0.1
Share-Based Compensation Plans - Schedule of Valuation Assumptions for Non-Qualified Stock Options (Details) - Non-qualified Stock Options - $ / shares
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]        
Risk-free interest rate       1.10%
Dividend yield       0.00%
Volatility factor       60.00%
Expected term       4 years
Number of options granted (in shares) 0 0 0 1,000,000
Weighted Average Grant Date Fair Value (in dollars per share)       $ 1.61
v3.25.0.1
Share-Based Compensation Plans - Summary of Non-qualified Option Activity (Details) - Non-Qualified Stock Options
 12 Months Ended
Dec. 31, 2024
USD ($)
$ / shares
shares
Shares  
Outstanding, beginning balance (in shares) | shares 1,523,536
Expired (in shares) | shares (193,726)
Exercised (in shares) | shares (134,474)
Outstanding, ending balance (in shares) | shares 1,195,336
Weighted Average Exercise Price  
Weighted average exercise price, outstanding, beginning balance (in dollars per share) | $ / shares $ 18.75
Weighted average exercise price, outstanding, Expired (in dollars per share) | $ / shares 46.21
Weighted average exercise price, outstanding, Exercised (in dollars per share) | $ / shares 37.91
Weighted average exercise price, outstanding, ending balance (in dollars per share) | $ / shares $ 12.14
Weighted Average Remaining Contractual Term  
Weighted average remaining contractual term, outstanding 2 years 3 months 18 days
Aggregate Intrinsic Value  
Aggregate intrinsic value, outstanding, end of period | $ $ 40,604,986
v3.25.0.1
Share-Based Compensation Plans - Valuation of Stock Appreciation Rights (Details) - Stock appreciation rights - USD ($)
$ / shares in Units, shares in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Risk-free interest rate     0.30%
Dividend yield     0.00%
Volatility factor     67.50%
Expected term     3 years 3 months 10 days
Number of Stock Appreciation Rights Granted (in shares)     1,240
Weighted Average Grant Date Fair Value (in dollars per share)     $ 2.61
Total Intrinsic Value of Exercises $ 33,400,000 $ 0 $ 0
v3.25.0.1
Leases - Narrative (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Leases [Abstract]      
Operating lease, payments $ 13.6 $ 10.1 $ 10.3
Finance lease, payments $ 4.2 $ 2.3 $ 1.8
Operating lease, weighted average remaining lease term 3 years 4 months 24 days 1 year 7 months 6 days 1 year 9 months 18 days
Operating lease, discount rate 5.30% 4.70% 4.50%
Finance lease, weighted average remaining lease term 6 years 9 months 18 days 3 years 9 months 18 days 3 years 3 months 18 days
Finance lease, discount rate 5.10% 4.80% 3.90%
Operating lease, right-of-use asset, statement of financial position [Extensible List] Other assets Other assets  
Operating lease, liability, current, statement of financial position [Extensible List] Other current liabilities Other current liabilities  
Operating lease, liability, noncurrent, statement of financial position [Extensible Enumeration] Other liabilities and credits Other liabilities and credits  
v3.25.0.1
Leases - Lease Cost (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Lessee, Lease, Description [Line Items]      
Operating lease costs $ 41,991 $ 26,755 $ 19,922
Finance lease costs 5,546 2,414 1,716
Variable and short-term lease costs 33,475 24,151 13,726
Total lease costs 81,012 53,320 35,364
Property, Plant and Equipment      
Lessee, Lease, Description [Line Items]      
Operating lease costs 33,100 24,500 17,700
Total lease costs $ 50,500 $ 40,800 $ 25,400
v3.25.0.1
Leases - Schedule of Balance Sheet Information (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Right-of-Use Assets    
Operating $ 60,496 $ 42,338
Finance lease, right-of-use asset, statement of financial position [Extensible Enumeration] Other assets Other assets
Finance $ 34,803 $ 6,494
Total right-of-use assets $ 95,299 $ 48,832
Lease Liabilities    
Operating lease, liability, current, statement of financial position [Extensible List] Other current liabilities Other current liabilities
Current portion of lease liabilities $ 36,275 $ 43,891
Finance lease, liability, current, statement of financial position [Extensible Enumeration] Other current liabilities Other current liabilities
Finance $ 5,603 $ 2,489
Total current lease liabilities 41,878 46,380
Operating $ 29,391 $ 8,443
Finance lease, liability, noncurrent, statement of financial position [Extensible Enumeration] Other liabilities and credits Other liabilities and credits
Finance $ 29,263 $ 3,754
Total noncurrent lease liabilities 58,654 12,197
Total lease liabilities $ 100,532 $ 58,577
Operating lease, liability, noncurrent, statement of financial position [Extensible Enumeration] Other liabilities and credits Other liabilities and credits
Operating lease, right-of-use asset, statement of financial position [Extensible List] Other assets Other assets
v3.25.0.1
Leases - Lease Maturity (Details)
$ in Thousands
Dec. 31, 2024
USD ($)
Operating  
2025 $ 38,592
2026 8,289
2027 7,623
2028 6,480
2029 5,804
Thereafter 5,207
Total lease payment obligations 71,995
Less: Imputed interest 6,329
Present value of lease liabilities 65,666
Finance  
2025 7,192
2026 6,420
2027 6,057
2028 4,806
2029 4,523
Thereafter 12,126
Total lease payment obligations 41,124
Less: Imputed interest 6,258
Present value of lease liabilities 34,866
Total  
2025 45,784
2026 14,709
2027 13,680
2028 11,286
2029 10,327
Thereafter 17,333
Total lease payment obligations 113,119
Less: Imputed interest 12,587
Present value of lease liabilities $ 100,532
v3.25.0.1
Commitment and Contingencies (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Long-Term Purchase Commitment [Line Items]  
Remedial action included in other credits $ 10.3
Environmental loss contingency, statement of financial position [Extensible Enumeration] Other liabilities and credits
Demand Charge Payments | Pipeline Demand Charges  
Long-Term Purchase Commitment [Line Items]  
2025 $ 1,100.0
2026 1,100.0
2027 1,000.0
2028 900.0
2029 900.0
Thereafter 8,600.0
Total 13,600.0
Services and Materials Payment Commitment | Frac Sand and Equipment  
Long-Term Purchase Commitment [Line Items]  
2025 219.9
2026 148.4
2027 88.1
2028 37.9
Total $ 494.3
v3.25.0.1
Concentrations of Credit Risk (Details) - USD ($)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Concentration Risk    
Adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment $ 0  
Accounts receivable | Customer concentration | Non-End Users    
Concentration Risk    
Concentration risk 96.00% 93.00%
v3.25.0.1
Natural Gas Producing Activities (Unaudited) - Costs Incurred Relating to Natural Gas, NGL, and Oil Production Activities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Capitalized costs      
Proved properties $ 31,986,473 $ 30,471,164  
Unproved properties 1,563,440 2,039,431  
Total capitalized costs 33,549,913 32,510,595  
Less: Accumulated depletion 12,489,317 10,734,099  
Net oil and gas producing properties 21,060,596 21,776,496  
Property acquisition:      
Proved properties 410,805 4,142,621 $ 82,276
Unproved properties 98,007 575,130 113,523
Exploration 2,735 3,330 3,438
Development 1,848,000 1,782,428 1,298,665
NEPA Non Operated Asset Divestiture      
Property acquisition:      
Unproved properties 10,800    
Marcellus leases | NEPA Non Operated Asset Divestiture      
Property acquisition:      
Proved properties 74,700    
Marcellus wells | NEPA Non Operated Asset Divestiture      
Property acquisition:      
Proved properties $ 267,700    
2022 Asset Acquisition      
Property acquisition:      
Unproved properties     17,100
2022 Asset Acquisition | Marcellus leases      
Property acquisition:      
Proved properties     $ 40,500
Tug Hill and XcL Midstream      
Property acquisition:      
Unproved properties   523,000  
Tug Hill and XcL Midstream | Marcellus leases      
Property acquisition:      
Proved properties   719,600  
Tug Hill and XcL Midstream | Marcellus wells      
Property acquisition:      
Proved properties   2,522,300  
Tug Hill and XcL Midstream | Marcellus Midstream Assets      
Property acquisition:      
Proved properties   $ 757,600  
v3.25.0.1
Natural Gas Producing Activities (Unaudited) - Results of Operations Related to Natural Gas, NGL and Oil Production (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Transportation and processing $ 1,915,616 $ 2,157,260 $ 2,116,976
Production 377,007 239,001 298,388
Operating and maintenance 37,951 0 0
Exploration 2,735 3,330 3,438
Depreciation and depletion 2,016,670 1,732,142 1,665,962
(Gain) loss on sale/exchange of long-lived assets (764,431) 17,445 (8,446)
Impairment and expiration of leases 97,368 109,421 176,606
Income tax expense 316,377 187,463 1,987,323
Results of operations from producing activities, excluding corporate overhead 935,073 583,007 5,871,324
un-recast      
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Production   254,700 300,985
Sales of natural gas, natural gas liquids and oil      
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Sales of natural gas, natural gas liquids and oil $ 4,934,366 $ 5,044,768 $ 12,114,168
v3.25.0.1
Natural Gas Producing Activities (Unaudited) - Narrative (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2024
Dec. 31, 2024
MMcfe
Dec. 31, 2024
Bcfe
Dec. 31, 2024
$ / MBoe
Dec. 31, 2024
$ / Dekatherm
Dec. 31, 2024
$ / bbl
Dec. 31, 2024
USD ($)
Dec. 31, 2023
MMcfe
Dec. 31, 2023
Bcfe
Dec. 31, 2022
MMcfe
Dec. 31, 2022
Bcfe
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                        
Engineer experience (in years) 22 years                      
Percentage of total net natural gas, NGL and oil proved reserves reviewed   100.00%                    
Conversions of proved undeveloped reserves to proved developed reserves (in Bcfe)       2,637           2,561   1,365
Extensions, discoveries and other additions (in Bcfe)       3,126           3,412   2,495
Production (in Bcfe)     2,228,159 2,228         2,016,273 2,016 1,940,043 1,940
Reserve development converting previously unproved acreage to proved reserves (Energy)       2,414           1,670    
Development plan, term 5 years                      
Increased reserves (in Bcfe)     3,125,620 157         3,411,750 92 2,494,713 2,077
Inclusion in drilling plan (in Bcfe)       498           1,341   418
Converting unproved reserves to proved developed reserves (in Bcfe)       57           309    
Negative revisions from proved undeveloped locations (in Bcfe)       925           (755)    
Revision of curves (in bcfe)                   367    
Changes in ownership interests (in Bcfe)       189 87         290    
Negative curve revisions at proved developed locations (in Bcfe)       (65)           208    
Removal of locations, economic and lack of development (in Bcfe)       192           (362)   518
Purchase of minerals in place (in Bcfe) | MMcfe     413,040           2,600,667   141,038  
Sale of natural gas in place (in Bcfe) | MMcfe     (1,562,849)           0   0  
Discount for estimated timing of cash flows (percent) 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00%
Discounted future net cash flows relating to proved oil and gas reserves, change in price of natural gas sensitivity (in usd per dth) | $ / Dekatherm           0.10            
Discounted future net cash flows relating to proved oil and gas reserves, change in price of natural gas liquids (in usd per bbl) | $ / bbl             10          
Discounted future net cash flows relating to proved oil and gas reserves, change in price of oil sensitivity (in usd per bbl) | $ / bbl             10          
Change in discounted future cash flows for assumed natural gas price change | $               $ 1,184        
Change in discounted future cash flows for assumed natural gas liquids price change | $               1,128        
Change in discounted future cash flows for assumed oil price change | $               $ 73        
NEPA Non Operated Asset Divestiture                        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                        
Purchase of minerals in place (in Bcfe)       413                
Sale of natural gas in place (in Bcfe)       (1,563)                
2022 Asset Acquisition                        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                        
Purchase of minerals in place (in Bcfe)                       141
Tug Hill and XcL Midstream                        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                        
Purchase of minerals in place (in Bcfe)                   2,600    
Ohio, Pennsylvania, and West Virginia Marcellus Acres                        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                        
Increased reserves (in Bcfe)                       356
Ohio, Pennsylvania, and West Virginia Marcellus                        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                        
Removal of locations, economic and lack of development (in Bcfe)                       96
Ohio Utica                        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                        
Negative revisions from proved undeveloped locations (in Bcfe)                       1,625
v3.25.0.1
Natural Gas Producing Activities (Unaudited) - Schedule of the Entity's Proved and Unproved Reserves (Details)
 12 Months Ended
Dec. 31, 2024
MMcf
Dec. 31, 2024
MMcfe
Dec. 31, 2024
MBbls
Dec. 31, 2024
Bcfe
Dec. 31, 2023
MMcf
Dec. 31, 2023
MMcfe
Dec. 31, 2023
MBbls
Dec. 31, 2023
Bcfe
Dec. 31, 2022
MMcf
Dec. 31, 2022
MMcfe
Dec. 31, 2022
MBbls
Dec. 31, 2022
Bcfe
Proved developed and undeveloped reserves:                        
Balance at January 1 | MMcfe   27,596,694       25,002,589       24,961,499    
Revision of previous estimates | MMcfe   (1,079,677)       (1,402,039)       (654,618)    
Purchase of hydrocarbons in place | MMcfe   413,040       2,600,667       141,038    
Sale of natural gas in place | MMcfe   (1,562,849)       0       0    
Extensions, discoveries and other additions   3,125,620   157   3,411,750   92   2,494,713   2,077
Production   (2,228,159)   (2,228)   (2,016,273)   (2,016)   (1,940,043)   (1,940)
Balance at December 31 | MMcfe   26,264,669       27,596,694       25,002,589    
Proved developed reserves:                        
Balance at January 1 | MMcfe   19,558,176       17,513,645       17,218,655    
Balance at December 31 | MMcfe   18,804,929       19,558,176       17,513,645    
Proved undeveloped reserves:                        
Balance at January 1 | MMcfe   8,038,518       7,488,944       7,742,844    
Balance at December 31 | MMcfe   7,459,740       8,038,518       7,488,944    
Natural Gas                        
Proved developed and undeveloped reserves:                        
Balance at January 1 | MMcf 25,795,134       23,824,887       23,523,665      
Revision of previous estimates | MMcf (917,676)       (1,461,305)       (432,315)      
Purchase of hydrocarbons in place | MMcf 395,423       2,012,159       141,038      
Sale of natural gas in place | MMcf (1,562,849)       0       0      
Extensions, discoveries and other additions | MMcf 2,921,638       3,326,736       2,434,543      
Production | MMcf (2,086,441)       (1,907,343)       (1,842,044)      
Balance at December 31 | MMcf 24,545,229       25,795,134       23,824,887      
Proved developed reserves:                        
Balance at January 1 | MMcf 18,186,432       16,541,017       16,152,083      
Balance at December 31 | MMcf 17,440,191       18,186,432       16,541,017      
Proved undeveloped reserves:                        
Balance at January 1 | MMcf 7,608,702       7,283,870       7,371,582      
Balance at December 31 | MMcf 7,105,038       7,608,702       7,283,870      
Natural Gas Liquids (NGL)                        
Oil and Gas, Proved Reserve, Quantity [Line Items]                        
Million cubic feet per thousand barrel | MMcf 6                      
Proved developed and undeveloped reserves:                        
Balance at January 1     285,345       186,141       225,792  
Revision of previous estimates     (24,332)       11,558       (33,955)  
Purchase of hydrocarbons in place     2,529       90,604       0  
Extensions, discoveries and other additions     30,391       13,592       9,610  
Production     (22,025)       (16,550)       (15,306)  
Balance at December 31     271,908       285,345       186,141  
Proved developed reserves:                        
Balance at January 1     218,523       154,921       169,781  
Balance at December 31     217,786       218,523       154,921  
Proved undeveloped reserves:                        
Balance at January 1     66,822       31,220       56,011  
Balance at December 31     54,122       66,822       31,220  
Oil                        
Oil and Gas, Proved Reserve, Quantity [Line Items]                        
Million cubic feet per thousand barrel | MMcf 6                      
Proved developed and undeveloped reserves:                        
Balance at January 1     14,915       10,142       13,846  
Revision of previous estimates     (2,669)       (1,680)       (3,095)  
Purchase of hydrocarbons in place     407       7,481       0  
Extensions, discoveries and other additions     3,606       577       418  
Production     (1,595)       (1,605)       (1,027)  
Balance at December 31     14,664       14,915       10,142  
Proved developed reserves:                        
Balance at January 1     10,101       7,183       7,981  
Balance at December 31     9,669       10,101       7,183  
Proved undeveloped reserves:                        
Balance at January 1     4,814       2,959       5,865  
Balance at December 31     4,995       4,814       2,959  
v3.25.0.1
Natural Gas Producing Activities (Unaudited) - Estimated Future Net Cash Flows from Natural Gas and Oil Reserves (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
USD ($)
$ / bbl
uSDollarsPerThousandCubicFeet
$ / MMBTU
Dec. 31, 2023
USD ($)
$ / bbl
uSDollarsPerThousandCubicFeet
$ / MMBTU
Dec. 31, 2022
USD ($)
$ / bbl
uSDollarsPerThousandCubicFeet
$ / MMBTU
Dec. 31, 2021
USD ($)
Extractive Industries [Abstract]        
Future cash inflows $ 44,871,509 $ 52,916,665 $ 140,032,653  
Future production costs (18,979,056) (24,357,033) (22,801,652)  
Future development costs (4,352,890) (4,298,372) (3,244,211)  
Future income tax expenses (4,445,354) (5,230,629) (26,375,241)  
Future net cash flow $ 17,094,209 $ 19,030,631 $ 87,611,549  
Discount for estimated timing of cash flows (percent) 10.00% 10.00% 10.00%  
annual discount for estimated timing of cash flows $ (9,095,069) $ (9,768,282) $ (47,547,025)  
Standardized measure of discounted future net cash flows $ 7,999,140 $ 9,262,349 $ 40,064,524 $ 17,281,124
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]        
Price used in computation of reserves | $ / bbl 29.28 28.44 38.66  
Future abandonment costs $ 2,553,000 $ 2,443,000 $ 2,098,000  
NYMEX        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]        
Price used in computation of reserves, gross | $ / MMBTU 2.130 2.637 6.357  
Price used in computation of reserves, adjustments | $ / MMBTU 0.741 1.029 1.094  
Price used in computation of reserves | uSDollarsPerThousandCubicFeet 1.468 1.700 5.543  
West Texas Intermediate        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]        
Price used in computation of reserves, gross | $ / bbl 76.32 78.21 94.14  
Price used in computation of reserves, adjustments | $ / bbl 16.87 14.35 17.31  
Price used in computation of reserves | $ / bbl 59.45 63.86 76.83  
v3.25.0.1
Natural Gas Producing Activities (Unaudited) - Summary of Changes in the Standardized Measure of Discounted Net Cash Flows (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Roll Forward]      
Net sales and transfers of natural gas and oil produced $ (2,603,792) $ (2,632,808) $ (9,696,207)
Net changes in prices, production and development costs (1,237,271) (48,739,248) 35,353,172
Extensions, discoveries and improved recovery, net of related costs 464,496 6,347,387 1,798,851
Development costs incurred 1,432,315 1,296,380 902,925
Net purchase of minerals in place 269,453 2,131,567 280,233
Net sale of minerals in place (692,019) 0 0
Revision of previous estimates (263,191) (2,768,922) (299,423)
Accretion of discount 926,235 4,006,452 1,728,112
Net change in income taxes 411,999 9,190,460 (7,233,051)
Timing and other 28,566 366,557 (51,212)
Net (decrease) increase (1,263,209) (30,802,175) 22,783,400
Balance at January 1 9,262,349 40,064,524 17,281,124
Balance at December 31 $ 7,999,140 $ 9,262,349 $ 40,064,524
v3.25.0.1
Schedule II - Valuation and Qualifying Accounts and Reserves (Details) - Deferred Tax Assets - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Beginning of Period $ 290,812 $ 365,140 $ 550,967
Additions Charged to Costs and Expenses 21,564 12,549 869
Deductions Charged to Other Accounts 0 0 0
Deductions (55,158) (86,877) (186,696)
Balance at End of Period $ 257,218 $ 290,812 $ 365,140