EQT CORP, 10-K filed on 2/18/2026
Annual Report
v3.25.4
Cover - USD ($)
$ in Billions
 12 Months Ended
Dec. 31, 2025
Feb. 11, 2026
Jun. 30, 2025
Cover [Abstract]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2025    
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     $ 34.7
Entity Common Stock, Shares Outstanding   624,274,000  
Documents Incorporated by Reference
EQT Corporation's definitive proxy statement relating to its 2026 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, 2025 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 2025    
Document Fiscal Period Focus FY    
Amendment Flag false    
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Auditor [Abstract]  
Auditor Firm ID 42
Auditor Name Ernst & Young LLP
Auditor Location Pittsburgh, Pennsylvania
v3.25.4
STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating revenues:      
Gain (loss) on derivatives $ 290,994 $ 51,117 $ 1,838,941
Total operating revenues 8,644,211 5,273,309 6,908,923
Operating expenses:      
Transportation and processing 1,532,090 1,915,616 2,157,260
Production 388,696 377,007 239,001
Operating and maintenance 225,131 110,393 15,699
Exploration 3,601 2,735 3,330
Selling, general and administrative 380,066 336,724 236,171
Depreciation, depletion and amortization 2,600,390 2,162,350 1,732,142
(Gain) loss on sale/exchange of long-lived assets (31,214) (764,044) 17,445
Impairment and expiration of leases 51,152 97,368 109,421
Other operating expenses 244,680 349,864 84,043
Total operating expenses 5,394,592 4,588,013 4,594,512
Operating income 3,249,619 685,296 2,314,411
Income from investments (184,444) (76,039) (7,596)
Other income (4,826) (25,983) (1,231)
Loss on debt extinguishment 22,652 68,299 80
Interest expense, net 438,695 454,825 219,660
Income before income taxes 2,977,542 264,194 2,103,498
Income tax expense 651,884 22,079 368,954
Net income 2,325,658 242,115 1,734,544
Less: Net income (loss) attributable to noncontrolling interests 286,411 11,538 (688)
Net income attributable to EQT Corporation $ 2,039,247 $ 230,577 $ 1,735,232
Income per share of common stock attributable to EQT Corporation:      
Weighted average common stock outstanding - Basic (in shares) 611,571 509,597 380,902
Net income attributable to EQT Corporation - Basic (in dollars per share) $ 3.33 $ 0.45 $ 4.56
Weighted average common stock outstanding - Diluted (in shares) 615,717 514,593 413,224
Net income attributable to EQT Corporation - Diluted (in dollars per share) $ 3.31 $ 0.45 $ 4.22
Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil $ 7,726,712 $ 4,934,366 $ 5,044,768
Pipeline and other      
Operating revenues:      
Pipeline and other $ 626,505 $ 287,826 $ 25,214
v3.25.4
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Net income $ 2,325,658 $ 242,115 $ 1,734,544
Other comprehensive income, net of tax:      
Other postretirement benefits liability adjustment, net of tax: $137, $252 and $59 148 363 310
Comprehensive income 2,325,806 242,478 1,734,854
Less: Comprehensive income (loss) attributable to noncontrolling interests 286,411 11,538 (688)
Comprehensive income attributable to EQT Corporation $ 2,039,395 $ 230,940 $ 1,735,542
v3.25.4
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Other post-retirement benefits liability adjustment, tax expense $ 137 $ 252 $ 59
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Current assets:    
Cash and cash equivalents $ 110,795 $ 202,093
Accounts receivable (less allowance for credit losses: $3,088 and $12,529) 1,457,959 1,132,608
Derivative instruments, at fair value 202,390 143,581
Income tax receivable 27,756 97,378
Prepaid expenses and other 96,251 139,019
Total current assets 1,895,151 1,714,679
Property, plant and equipment 48,472,497 44,505,504
Less: Accumulated depreciation and depletion 14,914,689 12,757,686
Net property, plant and equipment 33,557,808 31,747,818
Investments in unconsolidated entities 3,630,577 3,617,397
Net intangible assets related to acquired transmission services agreements 200,486 215,257
Goodwill 2,062,462 2,079,481
Other assets 446,390 455,623
Total assets 41,792,874 39,830,255
Current liabilities:    
Current portion of debt 507,119 320,800
Accounts payable 1,367,431 1,177,656
Derivative instruments, at fair value 137,299 446,519
Accrued interest 137,505 167,157
Other current liabilities 335,487 349,417
Total current liabilities 2,484,841 2,461,549
Revolving credit facility borrowings 360,000 150,000
Senior notes 6,933,209 8,853,377
Deferred income taxes 3,472,010 2,851,103
Asset retirement obligations and other liabilities 1,182,666 1,236,090
Total liabilities 14,432,726 15,552,119
Equity:    
Common stock, no par value, shares authorized: 1,280,000, shares issued: 624,076 and 596,870 19,517,761 18,014,711
Retained earnings 4,237,089 2,585,238
Accumulated other comprehensive loss (2,173) (2,321)
Total common shareholders' equity 23,752,677 20,597,628
Noncontrolling interest in consolidated subsidiaries 3,607,471 3,680,508
Total equity 27,360,148 24,278,136
Total liabilities and equity $ 41,792,874 $ 39,830,255
v3.25.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
shares in Thousands, $ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Statement of Financial Position [Abstract]    
Allowance for credit loss $ 3,088 $ 12,529
Common stock, par value (in dollars per share) $ 0 $ 0
Common stock, authorized (in shares) 1,280,000 1,280,000
Common stock, issued (in shares) 624,076 596,870
v3.25.4
STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash flows from operating activities:      
Net income $ 2,325,658 $ 242,115 $ 1,734,544
Adjustments to reconcile net income to net cash provided by operating activities:      
Deferred income tax expense 657,836 14,732 384,666
Depreciation, depletion and amortization 2,600,390 2,162,350 1,732,142
(Gain) loss on sale/exchange of long-lived assets (31,214) (764,044) 17,445
Impairments 51,152 97,368 109,421
Income from investments (184,444) (76,039) (7,596)
Loss on debt extinguishment 22,652 68,299 80
Share-based compensation expense 60,781 158,344 49,834
Distributions from equity method investments 257,233 66,200 18,693
Other 15,115 15,069 16,943
Gain on derivatives (290,994) (51,117) (1,838,941)
Net cash settlements (paid) received on derivatives (83,381) 1,217,895 900,650
Net premiums paid on derivatives (44,752) (42,394) (322,663)
Changes in other assets and liabilities:      
Accounts receivable (353,472) (220,446) 867,679
Accounts payable 207,074 16,512 (406,113)
Income tax receivable and payable 73,028 (7,913) (5,120)
Other current assets 45,191 (77,343) 98,907
Other items, net (201,901) 7,385 (171,721)
Net cash provided by operating activities 5,125,952 2,826,973 3,178,850
Cash flows from investing activities:      
Capital expenditures (2,288,425) (2,253,709) (2,019,037)
Cash paid for acquisitions, net of cash acquired (483,522) (874,265) (2,271,881)
Net cash received for sale/exchange of assets 10,234 1,696,121 4,200
Capital contributions to equity method investments (82,949) (148,049) (12,092)
Other investing activities (245) (80) (14,845)
Net cash used in investing activities (2,844,907) (1,579,982) (4,313,655)
Cash flows from financing activities:      
Proceeds from revolving credit facility borrowings 3,529,000 6,887,000 1,007,000
Repayment of revolving credit facility borrowings (3,639,800) (7,451,200) (1,007,000)
Proceeds from issuance of debt 0 750,000 1,250,000
Proceeds from net settlement of Capped Call Transactions (Note 7) 0 93,290 0
Debt issuance costs (9,623) (18,854) (5,336)
Repayment and retirement of debt (1,401,623) (4,313,867) (1,015,836)
Net (premiums paid) discounts received on debt extinguishment (39,311) (52,432) 5,178
Dividends paid (389,633) (326,581) (228,339)
Repurchase and retirement of common stock 0 0 (201,029)
Net proceeds from the sale of units of the Midstream Joint Venture (Note 9) (1,135) 3,410,392 0
Net distributions to noncontrolling interest (359,696) (1,640) (7,322)
Cash paid for taxes to net settle share-based incentive awards (54,175) (102,872) (41,780)
Other financing activities (6,347) 889 1,602
Net cash used in financing activities (2,372,343) (1,125,875) (242,862)
Net change in cash and cash equivalents (91,298) 121,116 (1,377,667)
Cash and cash equivalents at beginning of year 202,093 80,977 1,458,644
Cash and cash equivalents at end of year $ 110,795 $ 202,093 $ 80,977
v3.25.4
STATEMENTS OF CONSOLIDATED EQUITY - USD ($)
shares in Thousands, $ in Thousands
Total
Common Stock
Retained Earnings
Accumulated Other Comprehensive Loss
 [1]
Noncontrolling Interest in Consolidated Subsidiaries
Tug Hill and XcL Midstream
Tug Hill and XcL Midstream
Common Stock
Equitrans Midstream Merger
Equitrans Midstream Merger
Common Stock
Equitrans Midstream Merger
Noncontrolling Interest in Consolidated Subsidiaries
Olympus Energy Acquisition
Olympus Energy Acquisition
Common Stock
Beginning Balance (in shares) at Dec. 31, 2022   365,363                    
Beginning Balance at Dec. 31, 2022 $ 11,213,328 $ 9,891,890 $ 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 (Note 7) 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          
Acquisitions and Merger           $ 2,152,631 $ 2,152,631          
Distributions to noncontrolling interest (11,072)       (11,072)              
Contributions 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 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 (Note 7) 285,608 $ 285,608                    
Acquisitions and Merger (in shares)                 152,428      
Acquisitions and Merger               $ 5,711,601 $ 5,548,608 $ 162,993    
Distributions to noncontrolling interest (1,640)       (1,640)              
Net settlement of Capped Call Transactions (Note 7) 93,290 93,290                    
Change in ownership of consolidated subsidiary, net (Note 9) 3,422,531 $ (77,469)     3,500,000              
Ending Balance (in shares) at Dec. 31, 2024   596,870                    
Ending Balance at Dec. 31, 2024 24,278,136 $ 18,014,711 2,585,238 (2,321) 3,680,508              
Comprehensive income, net of tax:                        
Net income (loss) 2,325,658   2,039,247   286,411              
Other postretirement benefits liability adjustment, net of tax 148     148                
Dividends (387,396)   (387,396)                  
Share-based compensation plans (in shares)   1,977                    
Share-based compensation plans 26,863 $ 26,863                    
Convertible Notes settlements (Note 7) 0                      
Acquisitions and Merger (in shares)                       25,229
Acquisitions and Merger               $ 248   $ 248 $ 1,471,365 $ 1,471,365
Distributions to noncontrolling interest (359,696)       (359,696)              
Change in ownership of consolidated subsidiary, net (Note 9) 4,822 $ 4,822                    
Ending Balance (in shares) at Dec. 31, 2025   624,076                    
Ending Balance at Dec. 31, 2025 $ 27,360,148 $ 19,517,761 $ 4,237,089 $ (2,173) $ 3,607,471              
[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.
v3.25.4
STATEMENTS OF CONSOLIDATED EQUITY (Parenthetical) - USD ($)
$ in Thousands, shares in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]      
Other postretirement benefits liability adjustment, tax $ 137 $ 252 $ 59
Dividends (in dollars per share) $ 0.6375 $ 0.63 $ 0.61
Preferred stock, authorized shares (in shares) 3 3 3
Preferred shares, shares outstanding (in shares) 0 0 0
Preferred stock, shares issued (in shares) 0 0 0
v3.25.4
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2025
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 upstream, 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 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 owns 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.

The Company consolidates its controlling interest in the Midstream Joint Venture (defined in Note 9) under the voting interest entity model. See Note 9 for discussion of the method of allocation used in accounting for the portion of Midstream Joint Venture that is not owned by the Company.

In addition, the Company consolidates its 60% interest in Eureka Midstream Holdings, LLC (Eureka 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. Eureka Holdings conducts its operations through its wholly owned subsidiary, Eureka Midstream, LLC (Eureka), which has a revolving credit facility that is consolidated into the Company's debt. See Note 7.

In 2023, a variable interest entity formed in 2020 and previously consolidated by the Company was dissolved following a pro rata distribution of its assets to its members. The Company had previously consolidated the entity as the Company was its primary beneficiary.

Prior to the NEPA Gathering System Acquisition (defined in Note 11) and the First NEPA Non-Operated Asset Divestiture (defined in Note 12), the Company recorded its pro rata share of the NEPA Gathering System (defined in Note 11) in the Consolidated Financial Statements. Following these transactions, the Company owns 100% of the NEPA Gathering System.

Segments. The Company has three reportable segments reflecting its three lines of business consisting of Upstream, 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, effective as of December 31, 2025, the Company renamed its previously reported "Production" segment as the "Upstream" segment.

Use of Estimates. The preparation of the Consolidated 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 in the Statements of Consolidated Operations.

Accounts Receivable, Net of Allowance for Credit Losses. The Company's accounts receivable relate primarily to sales of natural gas and natural gas liquids (NGLs), pipeline revenue and amounts due from joint interest partners. See Note 3 for a discussion of amounts due from contracts with customers. Allowances for credit losses are recorded in selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required in assessing the ultimate realization of the Company's accounts receivable. The allowance for credit losses is 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,
 20252024
 (Thousands)
Margin requirements with counterparties (see Note 4)
$36,810 $86,975 
Prepaid expenses and other current assets59,441 52,044 
Total prepaid expenses and other$96,251 $139,019 

Property, Plant and Equipment. The following table summarizes the Company's property, plant and equipment.
 December 31,
 20252024
 (Thousands)
Oil and gas producing properties$36,785,910 $33,549,913 
Less: Accumulated depletion14,344,974 12,489,317 
Net oil and gas producing properties22,440,936 21,060,596 
Other upstream assets, at cost less accumulated depreciation
27,073 20,434 
Net upstream assets
22,468,009 21,081,030 
Gathering assets8,677,011 8,067,556 
Less: Accumulated depreciation337,889 131,546 
Net gathering assets8,339,122 7,936,010 
Transmission and storage assets2,751,815 2,667,352 
Less: Accumulated depreciation110,539 30,027 
Net transmission and storage assets2,641,276 2,637,325 
Other property, plant and equipment, at cost less accumulated depreciation109,401 93,453 
Net property, plant and equipment$33,557,808 $31,747,818 

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 2025, 2024 and 2023, the Company capitalized internal costs of approximately $82 million, $69 million and $57 million, respectively, to its oil and gas producing properties. In addition, in 2025, 2024 and 2023, the Company capitalized interest related to well development of approximately $32 million, $54 million and $41 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 $0.95, $0.90 and $0.84 per Mcfe for the years ended December 31, 2025, 2024 and 2023, respectively.

There were no exploratory wells drilled during 2025, 2024 and 2023, and there were no capitalized exploratory well costs for the years ended December 31, 2025, 2024 and 2023.
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 2025 and 2024, the Company capitalized internal costs of approximately $35 million and $25 million, respectively, to its gathering assets and $15 million and $4 million, respectively, to its transmission and storage assets. In addition, in 2025 and 2024, the Company capitalized interest of approximately $8 million and $3 million, respectively, related to its gathering assets.

The Company's gathering, transmission and storage assets are depreciated on a straight-line basis using composite rates over their estimated useful lives. These assets had an average depreciation rate of 2.8% and 3.1% for the years ended December 31, 2025 and 2024, respectively. Depreciation rates for regulated transmission and storage assets are subject to review in connection with filings made with the Federal Energy Regulatory Commission (the FERC).

Impairment of Property, Plant and Equipment

Impairment of Proved Oil and Gas Properties and Related Midstream Assets. The carrying values of the Company's proved oil and gas properties, together with related midstream assets that are operationally and economically interdependent, are reviewed for impairment when events or circumstances indicate that the carrying amount 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 Company's internal planning assumptions, including, among other things, future natural gas and NGLs sales prices; estimated reserve quantities and expected timing of production; projected gathered and processed volumes and transmission throughput; associated fee-based revenues; future operating costs and capital requirements; and discount and inflation assumptions. 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. No indicators of impairment to the Company's material asset groups were identified during 2025, 2024 and 2023.

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, historical experience or changes in market conditions. 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, 2025, 2024 and 2023, the Company recorded $51.2 million, $97.4 million and $109.4 million, respectively, for impairment and expiration of leases. The Company's unproved properties had a net book value of approximately $1,656 million and $1,563 million as of December 31, 2025 and 2024, respectively.

Impairment of Other Property, Plant and Equipment. The Company evaluates its other property, plant and equipment for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. No indicators of impairment were identified during 2025, 2024 and 2023.

Investments in Unconsolidated Entities. The Company applies the equity method of accounting to its investments in entities over which 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. The Company's pro-rata share of income or loss from these investments is recorded in income from investments in the Statements of Consolidated Operations.

The Company accounts for investments in entities over which the Company does not have the ability to exercise significant influence as investments in equity securities. Changes in the fair value of these investments are recorded in income from investments, and dividends received on such investments are recorded in other income in the Statements of Consolidated Operations.

See Note 8 for a discussion of the Company's investments in unconsolidated entities.
The Company evaluates its investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. The Company considers expected future cash flows of the investee, the investee's ability to generate cash flows sufficient to recover its carrying value, and market, operational or financial developments. The recognition of an impairment loss is required if the impairment is considered other than temporary. No indicators of impairment to the Company's investments in unconsolidated entities were identified during 2025, 2024 and 2023.

Net Intangible Assets. The following table summarizes the Company's intangible assets.

December 31,
20252024
(Thousands)
Acquired transmission services agreements$200,000 $200,000 
Less: Accumulated amortization19,234 5,901 
Net intangible assets related to acquired transmission services agreements180,766 194,099 
Other intangible assets24,922 24,922 
Less: Accumulated amortization5,202 3,764 
Net other intangible assets19,720 21,158 
Net intangible assets$200,486 $215,257 

The intangible assets related to acquired transmission services agreements are amortized on a straight-line basis over their estimated useful lives, which reflects the pattern in which the Company expects to consume the economic benefits of the assets. During the years ended December 31, 2025 and 2024, the Company recognized amortization expense of $13.3 million and $5.9 million, respectively, related to these acquired transmission services agreement intangible assets. The estimated annual amortization expense for these intangible assets is $13.3 million for each of the next 5 years.

The Company evaluates its intangible assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. Indicators of potential impairment may include changes in market conditions, customer demand or expected utilization of the underlying contracts. No indicators of impairment to the Company's net intangible assets were identified during 2025 and 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 (including, among other things, the Company's market capitalization and stock price as well as relevant market, economic or regulatory developments) to determine whether it is more likely than not (greater than 50%) that the fair value of the Company's 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 that incorporates forecasted cash flows, discount rate assumptions including weighted-average cost of capital, terminal growth rates and relevant industry multiples. 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, 2025 and determined there were no indicators of impairment. Changes in goodwill during the year ended December 31, 2025 reflect measurement-period adjustments resulting from the finalization of the purchase price allocation for the Equitrans Midstream Merger (defined in Note 11).
Other Current Liabilities. The following table summarizes the Company's other current liabilities.
 December 31,
 20252024
 (Thousands)
Accrued taxes other than income$108,626 $114,700 
Accrued incentive compensation90,694 53,138 
Current portion of lease liabilities58,124 41,878 
Current portion of long-term capacity contracts30,903 43,697 
Accrued payroll9,313 12,115 
Deferred revenue6,240 24,187 
Other accrued liabilities31,587 59,702 
Total other current liabilities$335,487 $349,417 
 
Unamortized Debt Discounts and Issuance Costs. Discounts and costs incurred with the issuance of debt are capitalized as a reduction of debt and amortized into net interest expense over the term of the debt. Costs incurred with the issuance or amendment of revolving credit facilities are capitalized as a noncurrent asset and amortized into net interest expense over the term of the facility. See Note 7.

Leases. See Note 15 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 income. 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.

The Midstream Joint Venture and Eureka Holdings 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. The Midstream Joint Venture's and Eureka Holdings' 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 the Midstream Joint Venture and Eureka Holdings, 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 federal and state taxable income forecasts, state apportionment analyses, reversals of temporary differences, tax planning strategies, prior year carrybacks and the expected utilization of tax credits.
 
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 6.
Insurance. The Company maintains insurance coverage for customary insurable risks, including general liability, workers' compensation, auto liability, environmental liability, property damage, business interruption, fiduciary liability and directors' and officers' liability. These policies are subject to deductibles, self-insured retentions, 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 maintains insurance coverage for such losses arising on or after November 12, 2020.

Certain legacy insurance programs of Equitrans Midstream Corporation (Equitrans Midstream), which the Company acquired in July 2024 (see Note 11), applied to losses arising prior to the transition to the Company's insurance programs. These programs included higher self-insured retentions for certain material losses related to excess liability and environmental liability arising before December 20, 2024 as well as limited co-insurance related to material losses under the property insurance coverage. Losses arising thereafter are included in the Company's insurance programs, which generally do not include high self-insured retentions or co-insurance amounts.

The Company records insurance reserves on an undiscounted basis using analyses of historical claims 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. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims, differ from estimates. There can be no assurance that the insurance policies we maintain to limit our liability for such losses will be adequate to protect the Company from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices or to cover all risks.

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 of the obligation are based on the expected timing of settlement, estimated costs (informed by the Company's historical experience with plugging and abandoning wells and reclaiming or disposing of other assets), the estimated remaining lives of the wells and related assets and the discount rates used to determine the present value of expected future settlement costs.

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 asset retirement obligations and other liabilities in the Consolidated Balance Sheets.
 December 31,
 20252024
 (Thousands)
Balance at January 1$1,003,570 $911,057 
Accretion expense76,745 68,501 
Liabilities incurred31,394 21,587 
Liabilities settled(52,210)(66,729)
Liabilities assumed in acquisitions14,923 45,847 
Liabilities removed in divestitures (a)(98,839)(28,701)
Change in estimates (b)43,922 52,008 
Balance at December 31$1,019,505 $1,003,570 

(a)Primarily attributable to the derecognition of asset retirement obligations associated with the Non-Core Asset Divestiture (defined and discussed in Note 12).
(b)During 2025 and 2024, the Company recorded changes in estimates attributable primarily to increased 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. Equitrans, L.P., a non-wholly owned subsidiary of the Company, owns and operates FERC-regulated transmission and storage assets.

Rate regulation established the rates Equitrans, L.P. may charge for regulated services and provides for the recovery of costs plus an authorized return on invested capital. Regulatory accounting permits the deferral of certain costs and income as regulated assets and liabilities when it is probable that such amounts will be recovered from, or refunded to, customers through future rates. These deferred amounts are recognized in the Statements 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 Statements of Operations. The Company did not have regulated operations during the year ended December 31, 2023.
Years Ended December 31,
 20252024
 (Thousands)
Operating revenues$572,975 $218,569 
Operating expenses194,576 78,908 

The following table presents Equitrans, L.P.'s regulated property, plant and equipment included in the Company's Consolidated Balance Sheets.
December 31,
 20252024
 (Thousands)
Property, plant and equipment$2,751,815 $2,667,352 
Less: Accumulated depreciation110,539 30,027 
Net property, plant and equipment$2,641,276 $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 asset retirement obligations and other liabilities. The following table summarizes Equitrans, L.P.'s regulated assets and liabilities.
December 31,
20252024
 (Thousands)
Regulated assets:
Deferred taxes (a)$139,221 $142,757 
Other recoverable costs (b)17,938 23,182 
Total regulated assets$157,159 $165,939 
Regulated liabilities:
Deferred taxes (a)$8,136 $8,534 
Ongoing postretirement benefits other than pension and other reimbursable costs (c)23,199 20,158 
Total regulated liabilities$31,335 $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 8.5 years, and costs associated with a legacy postretirement benefits plan, which Equitrans, L.P. expects to continue to recover over the next 6.5 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 other revenues.

Share-based Compensation. See Note 14 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,
202520242023
(Thousands)
Changes in legal and environmental reserves, including settlements$185,253 $16,271 $9,342 
Transaction costs35,843 309,419 56,263 
Other23,584 24,174 18,438 
Total other operating expenses$244,680 $349,864 $84,043 

Defined Contribution Plan. The Company recognized expense related to its defined contribution plan of $25.1 million, $14.5 million and $9.0 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Income Per Share. See Note 10 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,
202520242023
(Thousands)
Cash paid (received) during the year for:
Interest, net of amount capitalized$455,091 $401,768 $213,141 
Income taxes, net(79,022)7,960 13,350 
Non-cash activity during the period for:
Issuance of EQT common stock as consideration for acquisition (Note 11)$1,471,365 $5,548,608 $2,152,631 
Increase in asset retirement costs and obligations75,390 73,576 106,548 
Increase in right-of-use assets and lease liabilities, net65,323 29,568 45,774 
Capitalization of non-cash equity share-based compensation20,258 10,095 6,287 
Investments in unconsolidated entities17,981 3,428 — 
Issuance of EQT common stock upon Convertible Notes settlement (Note 7)— 285,608 122,830 
First NEPA Non-Operated Asset Divestiture (Note 12)
— 155,318 — 
Accrued transaction costs related to the sale of units of the Midstream Joint Venture (Note 9)— 1,135 — 
Dissolution of consolidated variable interest entity— — 25,227 

Recently Issued Accounting Standards

In December 2025, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2025-12, Codification Improvements, to clarify guidance, correct technical errors, remove outdated language and improve consistency across various topics in the Accounting Standards Codification. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2026, including interim reporting periods within those annual periods. Early adoption is permitted. The Company is evaluating the impact ASU 2025-12 will have on its financial statements and related disclosures and does not expect adoption of ASU 2025-12 to have a material impact.

In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements, to clarify the scope and presentation requirements for interim GAAP financial statements and to consolidate interim disclosure requirements. Under this ASU, entities must disclose material events or changes occurring after year end that affect interim periods. The amendments in this ASU are effective for interim reporting periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively to any or all prior periods presented in the financial statements. The Company is evaluating the impact ASU 2025-11 will have 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.

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 (i) disclose specific categories in the rate reconciliation and (ii) provide additional information for reconciling items that meet a quantitative threshold. This ASU is effective for annual reporting periods beginning after December 15, 2024. The Company adopted ASU 2023-09 in the fourth quarter of 2025. See Note 6 for related disclosures.
Subsequent Events. The Company has evaluated subsequent events through the date of the financial statement issuance.
v3.25.4
Financial Information by Business Segment
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Financial Information by Business Segment Financial Information by Business Segment
The Company has three reportable segments consisting of Upstream, Gathering and Transmission.

Effective as of December 31, 2025, the Company renamed its previously reported "Production" segment as the "Upstream" segment to better align with the nature of the Company’s operations and the Company's internal reporting framework. This change had no impact on the structure of the Company’s internal organization, including the composition of its reportable segments.

The Company's Upstream segment comprises the Company's natural gas, natural gas liquids (NGLs) and oil extraction, development and production business and supporting operations. The Company's Gathering segment owns and operates the Company's gathering system, which has extensive overlap with the Company's Upstream 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 Company's investment in the MVP Joint Venture (defined in Note 8) is reported in its Transmission segment.

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

Items that are managed on a consolidated basis, including cash and cash equivalents, debt, income taxes and amounts related to the Company's corporate function, and items related to the Company's energy transition initiatives have not been allocated to the Company's reportable segments and have been presented as "Other."

The Company's chief operating decision maker (the CODM), Toby Rice, President and Chief Executive Officer, evaluates performance of, and allocates resources to, the Company's reportable segments using a profitability metric of operating income. The CODM compares each segment's operating income and return on assets when evaluating performance of the Company's reportable segments and considers actual-to-forecast variances in operating income when allocating capital and personnel to the Company's reportable segments. For the Company's Transmission segment, the CODM also reviews equity earnings recognized from, and the carrying value of, the Company's investment in the MVP Joint Venture.

Substantially all of the Company's operating revenues and assets are generated and located in the United States.
Total segment operating income. The following tables present information about segment revenue, segment profit or loss and significant segment expenses and include a reconciliation of total segment amounts to the Company's consolidated totals.
Year Ended December 31, 2025
UpstreamGatheringTransmissionTotal SegmentIntersegment Eliminations and OtherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$7,726,712 $— $— $7,726,712 $— $7,726,712 
Gain on derivatives290,994 — — 290,994 — 290,994 
Pipeline and other6,351 1,301,434 572,252 1,880,037 (1,253,532)626,505 
Total operating revenues8,024,057 1,301,434 572,252 9,897,743 (1,253,532)8,644,211 
Operating expenses (a):
Transportation and processing2,783,455 — — 2,783,455 (1,251,365)1,532,090 
Production388,696 — — 388,696 — 388,696 
Operating and maintenance— 166,990 58,141 225,131 — 225,131 
Exploration3,601 — — 3,601 — 3,601 
Selling, general and administrative217,803 66,642 37,339 321,784 58,282 380,066 
Depreciation, depletion and amortization2,263,105 212,353 101,718 2,577,176 23,214 2,600,390 
(Gain) loss on sale/exchange of long-lived assets(31,513)(29)349 (31,193)(21)(31,214)
Impairment and expiration of leases50,341 811 — 51,152 — 51,152 
Other operating expenses (b)30,438 18,013 (527)47,924 196,756 244,680 
Total operating expenses5,705,926 464,780 197,020 6,367,726 (973,134)5,394,592 
Operating income (loss)$2,318,131 $836,654 $375,232 $3,530,017 $(280,398)$3,249,619 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the CODM.
(b)Corporate other operating expenses consisted primarily of legal reserves related to the Securities Class Action (defined in Note 13) and transaction costs related to the Olympus Energy Acquisition (defined in Note 11). See Notes 13 and 11 for information on the Securities Class Action and Olympus Energy Acquisition, respectively. See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2024
UpstreamGatheringTransmissionTotal 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 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 CODM.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for the Company's change in reportable segments from one reportable segment to three reportable segments as the necessary information was 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 11. See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2023
UpstreamGatheringTotal 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 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 CODM.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for the Company's change in reportable segments from one reportable segment to three reportable segments as the necessary information was 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 11). See Note 1 for a summary of the Company's consolidated other operating expenses.
Reconciliation of total segment operating income to consolidated income before income taxes
Years Ended December 31,
202520242023
(Thousands)
Total segment operating income$3,530,017 $1,075,902 $2,399,042 
Less:
Intersegment eliminations2,303 457 — 
Unallocated amounts:
Unallocated other revenues(136)(34)— 
Corporate selling, general and administrative58,282 36,254 — 
Corporate depreciation and amortization23,214 16,761 9,765 
Corporate gain on sale/exchange of long-lived assets(21)— — 
Corporate other operating expenses (a)196,756 337,168 74,866 
Income from investments (b)(184,444)(76,039)(7,596)
Other income(4,826)(25,983)(1,231)
Loss on debt extinguishment22,652 68,299 80 
Interest expense, net438,695 454,825 219,660 
Income before income taxes$2,977,542 $264,194 $2,103,498 

(a)For the year ended December 31, 2025, corporate other operating expenses consisted primarily of legal reserves related to the Securities Class Action and transaction costs related to the Olympus Energy Acquisition. For the year ended December 31, 2024, corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger. For the year ended December 31, 2023, corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition.
(b)For the years ended December 31, 2025 and 2024, income from investments included $154.3 million and $78.8 million, respectively, of equity earnings from the Company's investment in the MVP Joint Venture.

Total segment assets. The following table presents information about segment assets. The Company's investment in the MVP Joint Venture is presented in investments in unconsolidated entities in the Consolidated Balance Sheets.
UpstreamGatheringTransmissionTotal Segment
December 31, 2025(Thousands)
Investment in the MVP Joint Venture$— $— $3,514,803 $3,514,803 
Goodwill (a)— — 1,231,783 1,231,783 
Other segment assets24,295,091 8,676,118 2,891,096 35,862,305 
Total assets$24,295,091 $8,676,118 $7,637,682 $40,608,891 
December 31, 2024
Investment in the MVP Joint Venture$— $— $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 

(a)Changes in goodwill during the year ended December 31, 2025 reflect measurement-period adjustments resulting from the finalization of the purchase price allocation for the Equitrans Midstream Merger.
Reconciliation of total segment assets to consolidated total assets
December 31,
202520242023
(Thousands)
Total segment assets$40,608,891 $38,513,727 $25,019,540 
Intersegment eliminations(204,403)(318,835)(47,471)
Unallocated amounts:
Cash and cash equivalents110,795 202,093 80,977 
Income tax receivable27,756 97,378 91,414 
Other property, plant and equipment, at cost less accumulated depreciation109,401 93,453 40,739 
Goodwill (a)830,679 861,739 — 
Regulatory asset from deferred taxes139,221 142,757 — 
Other170,534 237,943 99,899 
Total assets$41,792,874 $39,830,255 $25,285,098 

(a)Represents unallocated goodwill attributable to additional deferred tax liabilities recognized in connection with the Equitrans Midstream Merger. Changes in goodwill during the year ended December 31, 2025 reflect measurement-period adjustments resulting from the finalization of the purchase price allocation for the Equitrans Midstream Merger.

Total segment capital expenditures. The following table presents information about segment capital expenditures.
Years Ended December 31,
202520242023
(Thousands)
Upstream
$1,878,052 $2,003,635 $1,878,417 
Gathering367,697 202,264 31,701 
Transmission51,769 31,446 — 
Total segment capital expenditures2,297,518 2,237,345 1,910,118 
Other corporate items26,119 28,603 15,125 
Total capital expenditures$2,323,637 $2,265,948 $1,925,243 
v3.25.4
Revenue from Contracts with Customers
 12 Months Ended
Dec. 31, 2025
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 fee 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 because 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 and other revenues in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
Years Ended December 31,
202520242023
(Thousands)
Revenues from contracts with customers:
Upstream sales
Natural gas$7,018,766 $4,224,882 $4,520,817 
NGLs620,384 615,933 427,760 
Oil87,562 93,551 96,191 
Sales of natural gas, NGLs and oil7,726,712 4,934,366 5,044,768 
Gathering pipeline revenue
Firm reservation fee (a)632,916 313,987 — 
Volumetric-based fee668,518 452,476 161,395 
Total Gathering pipeline revenue1,301,434 766,463 161,395 
Transmission pipeline revenue
Firm reservation fee435,194 183,088 — 
Volumetric-based fee137,058 35,205 — 
Total Transmission pipeline revenue572,252 218,293 — 
Intersegment eliminations and other(1,253,532)(704,517)(148,830)
Total revenues from contracts with customers (b)8,346,866 5,214,605 5,057,333 
Other sources of revenue:
Gain on derivatives290,994 51,117 1,838,941 
Other revenues6,351 7,587 12,649 
Total other sources of revenue297,345 58,704 1,851,590 
Total operating revenues$8,644,211 $5,273,309 $6,908,923 

(a)Firm reservation fee revenue included unbilled revenues supported by MVCs of $18.4 million and $4.2 million for the years ended December 31, 2025 and 2024, respectively.
(b)For contracts with customers in which the Company had satisfied its performance obligations and held an unconditional right to consideration at the balance sheet date, the Company recorded accounts receivable of $1,159.0 million and $939.9 million as of December 31, 2025 and 2024, 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, 2025. The table excludes contracts that qualified for the exception to the relative standalone selling price method as of December 31, 2025.
20262027202820292030ThereafterTotal
(Thousands)
Upstream natural gas sales$4,597 $1,978 $— $— $— $— $6,575 
Gathering firm reservation fee revenue:
Third-party100,794 85,998 85,998 85,998 85,998 287,261 732,047 
Affiliate101,792 101,450 97,701 97,701 103,977 1,403,698 1,906,319 
Total202,586 187,448 183,699 183,699 189,975 1,690,959 2,638,366 
Gathering revenue supported by MVCs:
Third-party96,377 89,203 80,536 67,311 56,762 132,254 522,443 
Affiliate397,966 410,621 411,740 410,622 408,322 1,634,128 3,673,399 
Total494,343 499,824 492,276 477,933 465,084 1,766,382 4,195,842 
Transmission firm reservation fee revenue:
Third-party185,328 176,986 171,814 169,198 165,686 660,199 1,529,211 
Affiliate253,089 262,637 260,776 260,445 260,445 1,704,604 3,001,996 
Total438,417 439,623 432,590 429,643 426,131 2,364,803 4,531,207 
Total remaining performance obligations$1,139,943 $1,128,873 $1,108,565 $1,091,275 $1,081,190 $5,822,144 $11,371,990 

As of December 31, 2025, based on total projected contractual revenues, the Company's firm gathering contracts had weighted average remaining terms of approximately 10 years for third-party contracts and 13 years for affiliate contracts.

As of December 31, 2025, based on total projected contractual revenues, the Company's firm transmission and storage contracts had weighted average remaining terms of approximately 10 years for third-party contracts and 13 years for affiliate contracts.
v3.25.4
Derivative Instruments
 12 Months Ended
Dec. 31, 2025
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 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. See Note 5 for a description of the fair value hierarchy and the valuation techniques and significant inputs used to estimate the fair value of the Company's derivative instruments.
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 945 billion cubic feet (Bcf) of natural gas and 4,022 thousand barrels (Mbbl) of NGLs as of December 31, 2025, and approximately 2,189 Bcf of natural gas and 2,562 Mbbl of NGLs as of December 31, 2024. The open positions at December 31, 2025 and 2024 had maturities extending through December 2030 and December 2027, respectively.

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, 2025, 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, 2025 and 2024, the aggregate fair value of the Company's OTC derivative instruments with credit rating risk-related contingent features in a net liability position was $4.4 million and $61.9 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, 2025 and 2024, 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, 2025 and 2024, there was $36.8 million and $87.0 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, 2025(Thousands)
Asset derivative instruments, at fair value$202,390 $(79,250)$— $123,140 
Liability derivative instruments, at fair value137,299 (79,250)(36,810)21,239 
December 31, 2024
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 
v3.25.4
Fair Value Measurements
 12 Months Ended
Dec. 31, 2025
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 and, when not available, valuation models that incorporate market-based inputs, including forward price curves, discount rates, volatilities and counterparty non-performance risk. 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, 2025(Thousands)
Asset derivative instruments, at fair value$202,390 $43,200 $159,190 $— 
Liability derivative instruments, at fair value137,299 39,164 98,135 — 
December 31, 2024
Asset derivative instruments, at fair value$143,581 $50,300 $93,281 $— 
Liability derivative instruments, at fair value446,519 81,074 365,445 — 

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 and Eureka's revolving credit facilities 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, 2025 and 2024, the Company's senior notes had a fair value of approximately $7.7 billion and $8.8 billion, respectively, and a carrying value of approximately $7.4 billion and $8.9 billion, respectively, inclusive of any current portion. See Note 7 for further discussion of the Company's debt.

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 assessments of the Company's property, plant and equipment, investments in unconsolidated entities, net intangible assets, goodwill and asset retirement obligations. See Note 8 for a discussion of the fair value measurement of the Company's investment in the Investment Fund (defined in Note 8). See Note 11 for a discussion of the fair value measurement of the assets acquired in the Olympus Energy Acquisition.
v3.25.4
Income Taxes
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
 
The following table summarizes the Company's income tax expense.
 Years Ended December 31,
 202520242023
 (Thousands)
Current:   
Federal$(7,296)$1,222 $(10,894)
State1,344 6,125 (4,818)
Current income tax (benefit) expense(5,952)7,347 (15,712)
Deferred:
Federal551,000 (21,463)450,091 
State106,836 36,195 (65,425)
Deferred income tax expense657,836 14,732 384,666 
Total income tax expense$651,884 $22,079 $368,954 
 
For the year ended December 31, 2025, current income tax benefit is primarily composed of a reduction in prior year income tax liabilities and interest. 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.

On July 4, 2025, President Trump signed the One Big Beautiful Bill Act (the OBBBA) into law. Significant provisions affecting the Company include (i) the reinstatement of 100% bonus depreciation for qualifying property, (ii) the allowance for immediate and full expensing of domestic research and experimentation expenditures and (iii) the use of earnings before interest, taxes, depreciation and amortization, or EBITDA, rather than earnings before interest and taxes, or EBIT, in determining adjusted taxable income for purposes of any interest deduction limitation. The enactment of the OBBBA did not have a material impact on the Company's effective tax rate for the year ended December 31, 2025.
The table below summarizes income tax payments, net of refunds.
 Years Ended December 31,
 202520242023
 (Thousands)
Federal$(81,195)$12,149 $12,876 
State:
Mississippi**670 
Pennsylvania*(4,114)*
Other U.S. states2,173 (75)(196)
Total taxes paid, net of refunds$(79,022)$7,960 $13,350 
*Indicates that the amount paid or refunded did not exceed the applicable disclosure threshold for the periods presented and is included in other U.S. states.

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,
 202520242023
Amount RateAmountRateAmountRate
 (Thousands)(Thousands)(Thousands)
Income before income taxes$2,977,542 $264,194 $2,103,498 
U.S. federal statutory tax rate$625,284 21.0 %$55,481 21.0 %$441,735 21.0 %
State and local income taxes, net of federal benefit (a)95,217 3.2 %35,115 13.3 %(55,993)(2.7)%
Tax credits:
Research and development credits(181)— %(5,779)(2.2)%(4,896)(0.2)%
Other(536)— %(758)(0.3)%180 — %
Changes in valuation allowances:
Capital loss carryforward— — %(52,820)(20.0)%78 — %
Other977 — %818 0.3 %1,301 0.1 %
Nontaxable or nondeductible items:
Transaction costs— — %6,041 2.3 %— — %
Other1,814 0.1 %2,639 1.0 %(2,984)(0.1)%
Changes in unrecognized tax benefits (b)(9,636)(0.3)%(16,977)(6.4)%(7,015)(0.3)%
Other adjustments:
Noncontrolling interests in consolidated subsidiaries(60,156)(2.0)%(2,724)(1.0)%(334)— %
Other(899)— %1,043 0.4 %(3,118)(0.1)%
Total income tax expense and effective tax rate$651,884 21.9 %$22,079 8.4 %$368,954 17.5 %

(a)The majority of the net state and local income tax effect relates to state income taxes in Pennsylvania and West Virginia for all periods presented.
(b)Changes in unrecognized tax benefits are presented on an aggregated basis for all jurisdictions.

The Company's effective tax rate for the year ended December 31, 2025 was higher compared to the U.S. federal statutory rate primarily as a result of state taxes net of valuation allowances, partly offset by the Midstream Joint Venture's and Eureka Holdings' income attributable to the noncontrolling interests.
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 following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.
 December 31,
 20252024
 (Thousands)
Deferred tax asset:
NOL carryforwards$789,888 $708,518 
Federal tax credits98,813 89,644 
Interest disallowance limitation45,222 106,622 
Incentive compensation and deferred compensation plans26,432 18,032 
State capital loss carryforward22,062 44,496 
Net unrealized losses— 80,723 
Other— 2,433 
Deferred tax asset982,417 1,050,468 
Valuation allowance(254,460)(257,218)
Net deferred tax asset727,957 793,250 
Deferred tax liability:
Property, plant and equipment(2,792,495)(2,516,074)
Investment in partnerships(1,392,717)(1,128,279)
Net unrealized gains(13,070)— 
Other(1,685)— 
Deferred tax liability(4,199,967)(3,644,353)
Net deferred tax liability$(3,472,010)$(2,851,103)
 
During 2025, the net deferred tax liability increased by $620.9 million compared to 2024 due primarily to temporary differences created by 100% bonus depreciation enacted with the OBBBA and the incremental accelerated deductions from the Olympus Energy Acquisition.
The following table presents the expiration periods of the net operating loss (NOL) carryforward deferred tax assets and associated valuation allowance by jurisdiction.
 December 31,
 20252024
 (Thousands)
NOL carryforwards:
Federal (expires between 2032 and 2037)$14,644 $14,644 
Federal (indefinite expiration)386,846 322,258 
State (expires between 2026 and 2045)354,822 347,279 
State (indefinite expiration)33,576 24,337 
Total NOL carryforwards$789,888 $708,518 
Valuation allowance on NOL carryforwards:
Federal$(13,870)$(14,263)
State(202,472)(187,321)
Total valuation allowance on NOL carryforwards$(216,342)$(201,584)

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 judgment 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 2025 and 2024, positive evidence considered included forecasts of future taxable income, the reversals of financial-to-tax temporary differences and the implementation of tax planning strategies. 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 (not included in the NOL table above) is related primarily to state limitations on interest expense under Internal Revenue Code Section 163(j) and state capital loss carryforwards generated from the sales of the Company's equity investment in Equitrans Midstream between February 2020 and April 2022. Capital losses may be utilized only to offset capital gains and are generally subject to a three-year carryback and five year carryforward period for potential 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, 2025, the Company had a valuation allowance related to the interest expense limitation of $10.5 million and the capital loss carryforward of $22.1 million for state income tax purposes due to the limitations on future potential utilization. As of December 31, 2024, the Company had a valuation allowance related to the interest expense limitation of $10.4 million and the capital loss carryforward of $44.5 million for state income tax purposes due to the limitations on future potential utilization. The reduction of the valuation allowance during 2025 primarily reflects the expiration of a portion of the capital loss carryforward.
The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, excluding interest and penalties.
 202520242023
 (Thousands)
Balance at January 1$72,743 $89,197 $204,035 
Additions for tax positions taken in current year8,291 11,720 11,986 
(Reductions) additions for tax positions taken in prior years(6,131)15,177 (883)
Reductions for tax positions settled with tax authorities— (29,645)(125,941)
Reductions for lapse in statute of limitations(14,574)(13,706)— 
Balance at December 31$60,329 $72,743 $89,197 

The following table presents specific line items that were included in the reserve for uncertain tax positions.
December 31,
202520242023
(Thousands)
If recognized, effect to the effective tax rate$57,350 $67,105 $83,669 
Reduction of related deferred tax asset for general business credit carryforwards and NOLs50,612 60,415 77,013 

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 $0.2 million, $0.6 million and $(19.8) million for the years ended December 31, 2025, 2024 and 2023, respectively. Interest and penalties of $3.1 million, $2.9 million, and $2.3 million were included in the Consolidated Balance Sheets as of December 31, 2025, 2024 and 2023, respectively.

In October 2025, the statute of limitation expired for an uncertain tax position, which resulted in a $0.9 million net reduction to the state tax liability and accrued interest reserve and a net increase to the state net operating loss of $10.9 million.

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 and was received by the Company in May 2025. During 2025, the IRS commenced an audit of EQM Midstream Partners, LP (EQM), a wholly owned tax partnership of EQT, for the tax year ended December 31, 2023. As of December 31, 2025, 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 2025.
v3.25.4
Debt
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Debt Debt
The table below summarizes the Company's outstanding debt.
December 31, 2025December 31, 2024
 Principal ValueCarrying Value (a)Fair Value (b)Principal ValueCarrying Value (a)Fair Value (b)
 (Thousands)
EQT's revolving credit facility maturing July 23, 2030
$75,000 $75,000 $75,000 $150,000 $150,000 $150,000 
Eureka's revolving credit facility maturing November 13, 2027
285,000 285,000 285,000 320,800 320,800 320,800 
Senior notes and debentures:
EQT's 3.125% notes due May 15, 2026
392,915 392,409 391,037 392,915 391,193 382,994 
EQT's 7.75% debentures due July 15, 2026
115,000 114,710 117,315 115,000 114,213 119,590 
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 6.500% notes due July 1, 2027
344,921 346,255 352,902 — — — 
EQT's 3.900% notes due October 1, 2027
936,158 934,640 932,282 1,169,503 1,166,523 1,137,248 
EQT's 5.700% notes due April 1, 2028
500,000 494,905 516,035 500,000 492,640 508,695 
EQM's 5.500% notes due July 15, 2028
— — — 118,683 118,204 117,382 
EQT's 5.500% notes due July 15, 2028
45,225 45,060 46,099 — — — 
EQT's 5.00% notes due January 15, 2029
318,494 316,448 322,902 318,494 315,785 314,357 
EQM's 4.50% notes due January 15, 2029
— — — 742,923 711,754 711,297 
EQT's 4.50% notes due January 15, 2029
734,583 710,802 736,603 — — — 
EQM's 6.375% notes due April 1, 2029
— — — 600,000 608,667 606,774 
EQT's 6.375% notes due April 1, 2029
596,725 602,840 618,076 — — — 
EQT's 7.000% notes due February 1, 2030 (c)
674,800 672,263 733,676 674,800 671,641 718,358 
EQM's 7.500% notes due June 1, 2030
— — — 500,000 535,671 534,950 
EQT's 7.500% notes due June 1, 2030
494,086 522,749 544,162 — — — 
EQM's 4.75% notes due January 15, 2031
— — — 1,100,000 1,045,219 1,039,995 
EQT's 4.75% notes due January 15, 2031
1,090,218 1,044,098 1,098,329 — — — 
EQT's 3.625% notes due May 15, 2031
435,165 431,496 409,651 435,165 430,818 388,111 
EQT's 5.750% notes due February 1, 2034
750,000 743,589 784,500 750,000 742,796 744,743 
EQM's 6.500% notes due July 15, 2048
— — — 80,233 81,338 81,932 
EQT's 6.500% notes due July 15, 2048
67,196 68,064 68,722 — — — 
Total debt7,855,486 7,800,328 8,032,291 9,368,516 9,324,177 9,299,525 
Less: Current portion of debt (d)507,915 507,119 508,352 320,800 320,800 320,800 
Long-term debt$7,347,571 $7,293,209 $7,523,939 $9,047,716 $9,003,377 $8,978,725 
 
(a)For EQT's and Eureka's revolving credit facilities, the principal value represents carrying value. For all other debt, the principal value less unamortized debt issuance costs, debt discounts and fair value adjustments recorded with the Equitrans Midstream Merger purchase price accounting, as applicable, represents carrying value.
(b)For EQT's and Eureka's revolving credit facilities, the carrying value approximates fair value as their interest rates are based on prevailing market rates; therefore, the Company considers the fair value of EQT's and Eureka's revolving credit facilities to be Level 1 fair value measurements. 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. For all other senior notes, interest rates do not fluctuate.
(d)As of December 31, 2025, the current portion of debt included EQT's 3.125% senior notes and 7.75% debentures. As of December 31, 2024, the current portion of debt included borrowings outstanding under Eureka's revolving credit facility.
Debt Repayments. The Company repaid, redeemed or repurchased the following debt during the year ended December 31, 2025.
Debt TranchePrincipalPremiums Paid/(Discounts Received)Accrued But Unpaid InterestTotal Cost
(Thousands)
EQM's 6.500% notes due July 1, 2027 (a) (c)
$555,077 $14,590 $6,754 $576,421 
EQT's 3.900% notes due October 1, 2027 (a)
233,345 (2,842)4,070 234,573 
EQM's 5.500% notes due July 15, 2028 (b)
73,456 2,878 1,190 77,524 
EQM's 7.500% notes due June 1, 2027 (c)
4,069 76 51 4,196 
EQM's 4.50% notes due January 15, 2029 (c)
8,338 27 17 8,382 
EQM's 6.375% notes due April 1, 2029 (c)
3,265 135 70 3,470 
EQM's 7.500% notes due June 1, 2030 (c)
5,536 666 69 6,271 
EQM's 4.75% notes due January 15, 2031 (c)
9,616 117 20 9,753 
EQM's 6.500% notes due July 15, 2048 (c)
12,989 1,738 37 14,764 
EQT's 7.500% notes due June 1, 2027 (d)
495,925 9,299 2,996 508,220 
Total$1,401,616 $26,684 $15,274 $1,443,574 

(a)On February 24, 2025, the Company announced the commencement of tender offers (the Tender Offers) to purchase all of EQM's outstanding 6.500% senior notes and a specified amount of EQT's outstanding 3.900% senior notes. On March 12, 2025, the Company settled the Tender Offers and repurchased $506.2 million aggregate principal amount of EQM's 6.500% senior notes and $233.3 million aggregate principal amount of EQT's 3.900% senior notes. In addition to call premiums paid (discounts received), the Company paid $2.7 million in fees to dealer managers and other non-lender parties in connection with the Tender Offers.
(b)On April 16, 2025, EQM issued a notice of full redemption to holders of its outstanding 5.500% senior notes, and, on May 1, 2025, EQM redeemed such notes in full.
(c)On July 16, 2025, EQM issued notices of full redemption to holders of each outstanding series of its senior notes, and, on July 31, 2025, EQM redeemed such notes in full. The redeemed notes had an aggregate principal amount of approximately $92.7 million, and, following these redemptions, EQM has no outstanding senior notes.
(d)On December 19, 2025, EQT issued a notice of full redemption to holders of its outstanding 7.500% senior notes, and, on December 30, 2025, EQT redeemed such notes in full.

EQT's Revolving Credit Facility. EQT has a $3.5 billion revolving credit facility governed by that certain Fourth Amended and Restated Credit Agreement, dated as of July 22, 2024 (as amended, the EQT Credit Agreement), among EQT, PNC Bank, National Association, as administrative agent, swing line lender and letter of credit issuer, and the other lenders party thereto. On June 30, 2025, EQT obtained the consent of each of the lenders party to the EQT Credit Agreement to extend the maturity date of the commitments and loans thereunder (the Stated Maturity Date) from July 23, 2029 to July 23, 2030, effective as of July 23, 2025 (the Extension). The terms of the EQT Credit Agreement otherwise remain unchanged. Pursuant to the terms of the EQT Credit Agreement, EQT may request two one-year extensions of the Stated Maturity Date, subject to satisfaction of certain conditions. The Extension is the first such extension.

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, 2025, no single lender in the syndicate for EQT's revolving credit facility held 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, 2025, EQT was in compliance with all provisions and covenants of the EQT Credit Agreement.

As of December 31, 2025 and 2024, the Company had approximately $2 million and $1 million, respectively, of letters of credit outstanding under EQT's revolving credit facility.

During the years ended December 31, 2025, 2024 and 2023, under EQT's revolving credit facility, the maximum amount of outstanding borrowings was $566 million, $2,357 million and $269 million, respectively, the average daily balance was approximately $98 million, $936 million and $40 million, respectively, and interest was incurred at a weighted average annual interest rate of 5.9%, 6.6% and 6.9%, respectively. For all years ended December 31, 2025, 2024 and 2023, EQT incurred commitment fees of 20 basis points on the undrawn portion of its revolving credit facility.

Eureka's Revolving Credit Facility. Through its controlling interest in Eureka Holdings, the Company consolidates Eureka's $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, the Eureka Credit Agreement). On June 30, 2025, Eureka entered into that certain Third Amendment and Master Assignment to Credit Agreement to, among other things, extend the maturity date of the commitments and loans under the Eureka Credit Agreement from November 13, 2025 to November 13, 2027 and reduce the commitment fee spread (calculated based on Eureka's consolidated leverage ratio) from a range of 37.5 to 50 basis points to a range of 32.5 to 45 basis points.

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 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, 2025, Eureka was in compliance with all provisions and covenants of the Eureka Credit Agreement.

As of both December 31, 2025 and 2024, Eureka had no letters of credit outstanding under its revolving credit facility.

During the year ended December 31, 2025, under Eureka's revolving credit facility, the maximum amount of outstanding borrowings was approximately $321 million, the average daily balance was approximately $288 million and interest was incurred at a weighted average annual interest rate of 7.0%. During 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 approximately $330 million, the average daily balance was approximately $328 million and interest was incurred at a weighted average annual interest rate of 7.8%. For the year ended December 31, 2025, Eureka incurred commitment fees ranging from 32.5 to 50 basis points on the undrawn portion of its revolving credit facility. For the period beginning on July 22, 2024 and ending on December 31, 2024, Eureka incurred commitment fees of 50 basis points on the undrawn portion of its revolving credit facility.
EQM Exchange Offers. On February 24, 2025, the Company commenced private offers (the EQM Exchange Offers) to certain eligible holders of EQM's senior notes to exchange any and all outstanding notes issued by EQM (the Existing EQM Notes), including outstanding principal of EQM's 6.500% senior notes due 2027 that remained outstanding following settlement of the Tender Offers, for up to $4,541.8 million aggregate principal amount of new notes issued by EQT (the New EQT Notes) and cash consideration equal to $1.00 per $1,000 principal amount of Existing EQM Notes exchanged. Pursuant to the EQM Exchange Offers, for each $1,000 principal amount of Existing EQM Notes validly tendered on or prior to 5:00 p.m., New York City time, on March 7, 2025 (the Early Tender Date), the holder thereof received $1,000 principal amount of New EQT Notes of the applicable series; for each $1,000 principal amount of Existing EQM Notes validly tendered after the Early Tender Date but on or prior to 5:00 p.m., New York City time, on March 28, 2025 (the Expiration Date), the holder thereof received $950 principal of New EQT Notes of the applicable series.

On April 2, 2025, the Company issued approximately $3,868.9 million of New EQT Notes in exchange for the tender of approximately $3,869.5 million of Existing EQM Notes and paid to holders of the New EQT Notes cash consideration of approximately $3.9 million, which was capitalized as additional debt premium. In addition, the discount received by EQT from holders who validly tendered their Existing EQM Notes after the Early Tender Date but on or prior to the Expiration Date of approximately $0.6 million was capitalized as additional debt discount. In connection with the EQM Exchange Offers, the Company incurred non-lender expenses of approximately $9.6 million in loss on debt extinguishment in the Statement of Consolidated Operations during the year ended December 31, 2025. The maturity date, interest rate and covenants of each New EQT Note are consistent with those of the corresponding Existing EQM Note exchanged.

Consent Solicitation. In conjunction with the Tender Offers and EQM Exchange Offers, the Company solicited and obtained consents with respect to certain proposed amendments to each of the indentures governing the Existing EQM Notes that, upon adoption (which occurred on April 2, 2025), eliminated substantially all of the restrictive covenants, certain events of default and certain other provisions previously contained in such indentures.

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.

As of December 31, 2025, aggregate maturities for EQT's senior notes were approximately $508 million in 2026, $1,281 million in 2027, $545 million in 2028, $1,650 million in 2029, $1,169 million in 2030 and $2,343 million thereafter.

EQT's 1.75% Convertible Notes and Capped Call Transactions. In April 2020, EQT issued $500 million aggregate principal amount of 1.75% convertible senior notes (the Convertible Notes). The Convertible Notes were fully redeemed in January 2024.

In connection with, but separate from, the issuance of the Convertible Notes, 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. In January 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 and the Capped Call Transactions were terminated.
v3.25.4
Investments in Unconsolidated Entities
 12 Months Ended
Dec. 31, 2025
Equity Method Investments and Joint Ventures [Abstract]  
Investments in Unconsolidated Entities Investments in Unconsolidated Entities
Equity Method Investments

The table below summarizes the Company's equity method investments.
December 31, 2025December 31, 2024
Ownership InterestCarrying ValueOwnership InterestCarrying Value
(Thousands)(Thousands)
MVP Joint Venture (a):
MVP A49.3 %$3,097,754 49.3 %$3,469,438 
MVP B
47.2 %42,420 47.2 %65,292 
MVP C
49.3 %374,629 — %— 
Total MVP Joint Venture3,514,803 3,534,730 
Laurel Mountain Midstream, LLC (b)31.0 %47,037 31.0 %28,757 
Other35,724 20,668 
Total$3,597,564 $3,584,155 

(a)Mountain Valley Pipeline, LLC (the MVP Joint Venture) is a Delaware series limited liability company formed as a joint venture for the purpose of constructing and owning natural gas assets. The MVP Joint Venture has three series, as follows (with each term defined below): MVP A, which owns MVP Mainline; MVP B, which owns MVP Southgate; and MVP C, which owns certain assets associated with MVP Boost. A wholly owned subsidiary of the Company serves as the operator for each series of the MVP Joint Venture.
(b)Laurel Mountain Midstream, LLC (LMM) is a midstream company formed as a joint venture among the Company, Williams Companies Inc. and certain other energy companies for the purpose of owning and operating gathering and processing assets.

Certain of the Company's equity method investments have an unamortized basis difference between the Company's investment carrying value and its proportionate share of the underlying net assets of the investees. To the extent the basis difference is amortizable, the related accretion is reflected in income from investments in the Statements of Consolidated Operations. As of December 31, 2025, the aggregate unamortized basis difference was approximately $1.4 billion.

MVP A. Series A of the MVP Joint Venture (MVP A) was formed for the purpose of constructing and owning the Mountain Valley Pipeline (MVP Mainline). As of December 31, 2025, MVP A's members consisted of the Midstream Joint Venture and affiliates of each of NextEra Energy, Inc. (NextEra), Con Edison Gas Pipeline and Storage, LLC (ConEd), AltaGas Ltd. (AltaGas) and RGC Resources, Inc. (RGC). See "MVP A and MVP C Buy-Out Right" below for a discussion of changes in ownership interests occurring after December 31, 2025.

MVP Mainline 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 and is regulated by the FERC. MVP Mainline entered into service on June 14, 2024 and commenced long-term firm capacity obligations on July 1, 2024.

For the year ended December 31, 2025, the Company's ownership interest in MVP A 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 MVP A.
 Year Ended December 31, 2025July 22, 2024 to
December 31, 2024
(Thousands)
Operating revenues$565,312 $247,360 
Operating income270,095 126,202 
Net income275,419 129,773 
December 31,
20252024
(Thousands)
Current assets$129,883 $204,028 
Noncurrent assets9,419,089 9,535,975 
Total assets$9,548,972 $9,740,003 
Current liabilities$24,218 $69,303 
Noncurrent liabilities4,629 1,514 
Total liabilities28,847 70,817 
Members' equity9,520,125 9,669,186 
Total liabilities and members' equity$9,548,972 $9,740,003 

MVP B. Series B of the MVP Joint Venture (MVP B) was formed for the purpose of constructing and owning the MVP Southgate project (MVP Southgate). As of December 31, 2025, MVP B's members consisted of the Company and affiliates of NextEra, AltaGas and RGC.

MVP Southgate is a contemplated interstate pipeline that was approved by the FERC. MVP Southgate was initially designed to extend approximately 75 miles from MVP Mainline 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 an amended project and, among other things, describe certain conditions precedent to the parties' respective obligations regarding MVP Southgate. As amended, the natural gas interstate pipeline would extend approximately 31 miles from the terminus of MVP Mainline in Pittsylvania County, Virginia to planned new delivery points in Rockingham County, North Carolina using 30-inch diameter pipe and have a projected capacity of 0.55 Bcf per day. The proposed 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.

Pending receipt of remaining regulatory approvals, MVP Southgate is expected to be placed into service by mid-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 MVP B.

Under the MVP Joint Venture's limited liability company agreement (the MVP LLC Agreement), the Company is required to provide performance assurance for MVP Southgate, which may take the form of a guarantee from the Company (as a Qualified Guarantor, as defined in the MVP LLC Agreement), a letter of credit or cash collateral. In July 2025, the Company issued a performance guarantee of approximately $14.2 million for MVP Southgate. Upon receipt of the FERC's initial authorization to begin construction of MVP Southgate, the Company's current MVP Southgate performance guarantee will be terminated, and the Company will be required to provide performance assurance equal to 33% of its proportionate share of the remaining capital commitments under MVP Southgate's most recently approved construction budget.

MVP C. Series C of the MVP Joint Venture (MVP C) was formed on November 1, 2025 for the purpose of constructing and owning certain assets associated with the MVP Boost project (MVP Boost). As of December 31, 2025, MVP C's members consisted of the Company and affiliates of NextEra, AltaGas, ConEd and RGC. See "MVP A and MVP C Buy-Out Right" below for a discussion of changes in ownership interests occurring after December 31, 2025.

MVP Boost is a contemplated project to add compression to MVP Mainline, which is projected to increase the capacity on MVP Mainline by 0.6 Bcf per day. As designed, MVP Boost would add compression at three existing compressor stations in West Virginia and construct a new compressor station in Montgomery County, Virginia.

On October 23, 2025, the MVP Joint Venture applied to the FERC for authorization to construct MVP Boost. Pending receipt of regulatory approvals, MVP Boost is expected to be placed into service by mid-2028. MVP Boost is estimated to have a total cost of approximately $400 million to $540 million, excluding AFUDC, of which the Company will fund its proportionate share through capital contributions to MVP C.
Under the MVP LLC Agreement, the Company is required to provide performance assurance for MVP Boost, which may take the form of a guarantee from the Company (as a Qualified Guarantor), a letter of credit or cash collateral. In November 2025, the Company issued a performance guarantee of approximately $14.8 million for MVP Boost. Upon receipt of the FERC's initial authorization to begin construction of MVP Boost, the Company's current MVP Boost performance guarantee will be terminated, and the Company will be required to issue a new performance assurance equal to 33% of its proportionate share of the remaining capital commitments under MVP Boost's most recently approved construction budget.

MVP A and MVP C Buy-Out Right. On November 24, 2025, ConEd entered into a purchase and sale agreement pursuant to which ConEd agreed to sell its approximately 6.60% interest in each of MVP A and MVP C to a third-party investor. On January 2, 2026, the Company provided ConEd notice of its election to exercise its preferential buy-out right in full in accordance with the MVP LLC Agreement. On January 16, 2026, the Company entered into a purchase and sale agreement with ConEd to acquire the Company's pro rata share of ConEd's equity interests in MVP A and MVP C, representing an approximately 3.94% interest in each series. Total consideration for the Company's acquisition of equity interests in MVP A is approximately $200.7 million, of which $98.4 million is expected to be funded by the BXCI Affiliate (defined in Note 9), subject to purchase price adjustments. Total consideration for the Company's acquisition of equity interests in MVP C is approximately $12.5 million, subject to purchase price adjustments. The transaction is expected to close in the first half of 2026, subject to regulatory approvals.

The acquisition of ConEd's remaining 2.66% interest in each series was completed by NextEra in January 2026 pursuant to similar preferential rights under the MVP LLC Agreement.

Investments in Equity Securities

The Investment Fund. The Company holds 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 both December 31, 2025 and 2024, the fair value of the Company's investment in the Investment Fund was approximately $33 million and is 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.
v3.25.4
The Midstream Joint Venture
 12 Months Ended
Dec. 31, 2025
Equity Method Investments and Joint Ventures [Abstract]  
The Midstream Joint Venture The Midstream Joint Venture
In September 2024, the Company, through its wholly owned subsidiary EQM, formed PipeBox LLC (the Midstream Joint Venture) as a wholly owned subsidiary. On December 30, 2024, the Company contributed to the Midstream Joint Venture certain transmission, storage and gathering assets and its ownership interest in MVP A, and an affiliate of Blackstone Credit & Insurance (the BXCI Affiliate) contributed $3.5 billion of cash (such contributions, 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, resulting in the BXCI Affiliate obtaining a noncontrolling interest in the Midstream Joint Venture. The Company retained a controlling voting interest in, and continues to consolidate, the Midstream Joint Venture.

In connection with the Midstream Joint Venture Transaction, on December 30, 2024, certain of the Company's wholly owned subsidiaries and the BXCI Affiliate entered into an amended and restated limited liability company agreement of the Midstream Joint Venture (the JV Agreement). Under the JV Agreement, 40% of available cash flow of the Midstream Joint Venture is distributed to the Company, as holder of the Class A units in the Midstream Joint Venture (Class A Unitholder), and 60% of available cash flow is distributed to the BXCI Affiliate, as holder of the Class B units in the Midstream Joint Venture (Class B Unitholder), until the BXCI Affiliate achieves the Base Return (as defined in the JV Agreement). After the Base Return has been achieved and until the eighth anniversary of the Midstream Joint Venture Transaction, 100% of distributions from the Midstream Joint Venture will be made to the Company. Thereafter, no less than 95% of distributions from the Midstream Joint Venture will be made to the Company and up to 5% of distributions will be made to the BXCI Affiliate, depending on the BXCI Affiliate's ownership interest at the time of such distribution. During the year ended December 31, 2025, the Midstream Joint Venture paid distributions of $354.9 million to the BXCI Affiliate. Distributions from the Midstream Joint Venture to the Company are eliminated in consolidation.
Based on the governing provisions of the JV Agreement, the Company'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 attributable to the noncontrolling interest based on the amounts 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 their recorded amounts and after taking into account any capital transactions between the Company and the BXCI Affiliate.

MVP A Buy-Out Right. As discussed in Note 8, the Company entered into a purchase and sale agreement with ConEd to acquire an approximately 3.94% equity interest in MVP A for consideration of approximately $200.7 million, subject to purchase price adjustments. The acquisition will be funded through capital contributions from the Midstream Joint Venture's members in proportion to their existing ownership interests, and, in exchange, the Midstream Joint Venture will issue additional Class A to the Class A Unitholder and Class B units to the Class B Unitholder to maintain the members' ownership percentages in the Midstream Joint Venture.
v3.25.4
Common Stock and Income Per Share
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Common Stock and Income Per Share Common Stock and Income Per Share
 
As of December 31, 2025, the Company had reserved 16.3 million shares of authorized and unissued EQT common stock for stock compensation plans.

Share Repurchase Program. The Company is authorized to repurchase shares of outstanding EQT common stock under a share repurchase program (the Share Repurchase Program) for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses. On December 18, 2024, the Company announced that its Board of Directors approved a two-year extension of the Share Repurchase Program, extending its expiration date to December 31, 2026. The Share Repurchase Program may be suspended, modified or discontinued at any time without prior notice.

From the Share Repurchase Program's inception in 2021 and through December 31, 2025, 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 Company did not repurchase any equity securities during the years ended December 31, 2025 and 2024. For the year ended December 31, 2023, the total number of shares purchased under the Share Repurchase Program was 5,906,159 for an aggregate purchase price of $200.0 million and an average price paid per share of $33.86, in each case excluding fees and brokerage commissions.

Share Issuances. In July 2025, the Company issued 25,229,166 shares of EQT common stock as part of the consideration for the Olympus Energy Acquisition described in Note 11.

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 11.

During 2023 and in January 2024, the Company issued shares of EQT common stock upon settlement of Convertible Notes conversion right exercises. The Convertible Notes were fully redeemed in January 2024.

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 11.

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 redemption, the Convertible Notes. Purchases of treasury shares are calculated using the average share price of EQT common stock during the period. Prior to 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,
202520242023
(Thousands, except per share amounts)
Net income attributable to EQT Corporation – Basic income available to shareholders$2,039,247 $230,577 $1,735,232 
Add back: Interest expense on Convertible Notes, net of tax— 86 7,551 
Diluted income available to shareholders$2,039,247 $230,663 $1,742,783 
Weighted average common stock outstanding – Basic611,571 509,597 380,902 
Options, restricted stock, performance awards and stock appreciation rights
4,146 4,625 5,232 
Convertible Notes— 371 27,090 
Weighted average common stock outstanding – Diluted615,717 514,593 413,224 
Income per share of common stock attributable to EQT Corporation:
Basic$3.33 $0.45 $4.56 
Diluted$3.31 $0.45 $4.22 
v3.25.4
Acquisitions
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
Acquisitions Acquisitions
Olympus Energy Acquisition

On July 1, 2025, the Company completed its acquisition (the Olympus Energy Acquisition) of certain oil and gas properties and related upstream and midstream assets, including approximately 90,000 net acres with approximately 500 million cubic feet (MMcf) per day of net production, from Olympus Energy LLC, Hyperion Midstream LLC and Bow & Arrow Land Company LLC (collectively, Olympus Energy) pursuant to a purchase and sale agreement dated April 22, 2025, by and among EQT, a wholly owned subsidiary of EQT and Olympus Energy.

The purchase price for the Olympus Energy Acquisition consisted of 25,229,166 shares of EQT common stock, with an aggregate value of approximately $1,471 million based on an EQT common stock share price of $58.32 (the last reported per share sale price of EQT common stock on the day prior to the completion of the Olympus Energy Acquisition), and approximately $473 million in cash, each as adjusted pursuant to customary purchase price adjustments and subject to final post-closing purchase price adjustments. The Company funded the cash consideration with cash on hand and borrowings under EQT's revolving credit facility.
Allocation of Purchase Price. The Olympus Energy Acquisition was accounted for as a business combination using the acquisition method. The Company completed the purchase price allocation for the Olympus Energy Acquisition during the fourth quarter of 2025. The table below summarizes the final purchase price and estimated fair values of the assets acquired and liabilities assumed as of July 1, 2025. No goodwill was recognized for the transaction.
Purchase Price Allocation
(Thousands)
Consideration:
Equity$1,471,365 
Cash473,360 
Total consideration$1,944,725 
Fair value of assets acquired:
Derivative instruments, at fair value$13,188 
Prepaid expenses and other18 
Property, plant and equipment2,019,892 
Amount attributable to assets acquired$2,033,098 
Fair value of liabilities assumed:
Accounts payable$3,082 
Derivative instruments, at fair value66,711 
Other current liabilities3,657 
Asset retirement obligations and other liabilities14,923 
Amount attributable to liabilities assumed$88,373 

The fair values of the developed and undeveloped natural gas properties acquired in the Olympus Energy Acquisition were measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are Level 3 fair value measurements. Significant inputs used in the valuation of developed and undeveloped properties included commodity prices, projected reserve quantities, estimated future rates of production, projected reserve recovery factors, development plans (including timing and amount of development), future development costs, operating costs and a weighted-average cost of capital. For undeveloped properties, significant inputs also included development plans evaluated from a market participant perspective.

The fair value of the gathering system acquired in the Olympus Energy Acquisition 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 included the replacement cost of similar assets, adjusted for depreciation based on asset age and condition, and adjustments for functional and economic obsolescence based on estimated utilization, recoveries and technological differences relative to newly constructed assets.

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 Olympus Energy Acquisition to the Company's consolidated results of operation subsequent to the completion of the Olympus Energy Acquisition.
July 1, 2025 through December 31, 2025
(Thousands)
Sales of natural gas, natural gas liquids and oil$235,388 
Gain on derivatives31,257 
Pipeline and other4,559 
Total operating revenues$271,204 
Net income attributable to EQT Corporation (a)$108,117 

(a)Net income attributable to EQT Corporation includes $29.1 million of transaction costs related to the Olympus Energy Acquisition recognized during the year ended December 31, 2025.

Pro forma results of operations are not presented as the impact of the Olympus Energy Acquisition was not significant to the Company's consolidated financial statements.

Equitrans Midstream Merger

On July 22, 2024, the Company completed its acquisition (the Equitrans Midstream Merger) of Equitrans Midstream. The purchase price for the Equitrans Midstream Merger consisted of 152,427,848 shares of EQT common stock, with an aggregate value of approximately $5.5 billion. 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 following the Equitrans Midstream Merger closing date and 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. Upon completion of the Equitrans Midstream Merger, the pre-existing contractual relationships between the Company and Equitrans Midstream were effectively settled.

The Equitrans Midstream Merger was accounted for as a business combination using the acquisition method. The Company completed the purchase price allocation for the Equitrans Midstream Merger during the second quarter of 2025, resulting in purchase accounting adjustments to deferred income taxes based on updated income tax computations as well as investments in unconsolidated entities and property, plant and equipment based on updated appraisal estimates.

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 purchase price 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 upstream assets from THQ Appalachia I, LLC and 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 Tug Hill and XcL Midstream Acquisition was accounted for 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.
v3.25.4
Divestitures
 12 Months Ended
Dec. 31, 2025
Discontinued Operations and Disposal Groups [Abstract]  
Divestitures Divestitures
Non-Core Asset Divestiture. In December 2025, the Company completed the divestiture of certain non-core upstream and midstream assets (the Non-Core Asset Divestiture) for total consideration of $0.6 million. The transaction was accounted for as a normal retirement, resulting in the derecognition of associated asset retirement obligations of approximately $97 million.

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 to Equinor USA Onshore Properties Inc. and its affiliates (collectively, the Equinor Parties). The carrying amount of the divested assets was approximately $523 million, primarily consisting of property, plant and equipment, net of associated liabilities. In exchange, as consideration, the Company received cash from the Equinor Parties 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.

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.

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 to the Equinor Parties. The carrying amount of the divested assets was approximately $772 million, primarily consisting of property, plant and equipment, net of associated liabilities. In exchange, as consideration, the Company received from the Equinor Parties cash of $1.25 billion, subject to customary post-closing purchase price adjustments.

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.
v3.25.4
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies
 
Contractual Commitments

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, 2025 were $13.2 billion, composed of $1.1 billion in 2026, $1.1 billion in 2027, $1.0 billion in 2028, $0.9 billion in 2029, $0.9 billion in 2030 and $8.2 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, 2025 were $389.3 million, composed of $230.5 million in 2026, $116.6 million in 2027, $41.1 million in 2028, $0.6 million in 2029, $0.4 million in 2030 and $0.1 million thereafter.

See Note 15 for a summary of undiscounted future minimum lease payments owed to lessors by the Company as lessee pursuant to contractual agreements in effect as of December 31, 2025.

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 when it determines, based on historical experience and matter-specific facts, 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 alleged that certain statements made by EQT regarding its merger with Rice Energy Inc. in 2017 were materially false and violated various federal securities laws. Pursuant to the complaint, the plaintiffs sought 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's common 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 settlement of the Securities Class Action referred to below does not resolve these matters.

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 June 2024 Mediation), which did not result in resolution. In the second quarter of 2024, the Company recorded an accrual for estimated loss contingencies related to the Securities Class Action in an amount equal to the settlement offer the Company tendered at the June 2024 Mediation of $17.5 million.

Following the June 2024 Mediation, the parties filed various motions, including motions for summary judgment and motions to exclude expert testimony. While these motions remained pending, on May 12, 2025, the parties to the Securities Class Action participated in a second mediation, at which it was agreed that the Company would pay $167.5 million to the plaintiffs to settle the Securities Class Action. The court issued a final order and judgment approving the settlement on November 4, 2025. The settlement does not constitute an admission of wrongdoing or liability by the Company or the other defendants, who have agreed to the settlement to avoid further protracted and expensive litigation.

In the second quarter of 2025, the Company recorded an increase to its accrual for estimated loss contingencies related to the Securities Class Action of $150.0 million, resulting in a total reserve equal to the settlement amount agreed upon at the May 12, 2025 mediation of $167.5 million. During the third quarter of 2025, the Company paid the settlement amount in full and received insurance recoveries of approximately $16 million.

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 $4 million was recorded in asset retirement obligations and other liabilities credits in the Consolidated Balance Sheet as of December 31, 2025.
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.
v3.25.4
Share-Based Compensation Plans
 12 Months Ended
Dec. 31, 2025
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,
 202520242023
 (Thousands)
Incentive Performance Share Unit Programs$14,505 $20,919 $23,915 
Restricted stock awards41,310 25,473 20,119 
Stock appreciation rights— — 4,056 
Other programs, including non-employee director awards3,784 3,596 3,110 
Total share-based compensation expense (a)$59,599 $49,988 $51,200 
         
(a)For the years ended December 31, 2025, 2024 and 2023, share-based compensation expense of $2.7 million, $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.

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.

There was no cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2025 and 2023. Cash received from exercises under all share-based payment arrangements for employees and directors for the year ended December 31, 2024 was $5.1 million. During the years ended December 31, 2025, 2024 and 2023, share-based payment arrangements paid in stock generated tax benefits of $12.3 million, $7.7 million and $16.5 million, respectively. Cash paid for taxes related to net settlement of share-based incentive awards for the years ended December 31, 2025, 2024 and 2023 were $54.2 million, $102.9 million and $41.8 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):
•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;
•2024 Incentive Performance Share Unit Program (2024 Incentive PSU Program) under the 2020 LTIP; and
•2025 Incentive Performance Share Unit Program (2025 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 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, 2024, and 2025 are earned based on:
•the level of absolute total shareholder return and total shareholder return relative to a predefined peer group.

The 2021 Incentive PSU Program, 2023 Incentive PSU Program, 2024 Incentive PSU Program, and 2025 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 2021 Incentive PSU Program, 2022 Incentive PSU Program, 2023 Incentive PSU Program, 2024 Incentive PSU Program, and 2025 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 January 1, 2023
2,861,990 $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 
Granted in Period377,570 74.14 27,993,040 
Granted from Multiplier649,020 75.32 48,884,186 
Vested(1,213,385)75.32 (91,392,158)
Forfeited(66,009)54.23 (3,579,668)
Outstanding at December 31, 2025
1,039,547 $25.93 $26,959,680 

Total capitalized compensation costs related to the Incentive PSU Programs for the years ended December 31, 2025, 2024 and 2023 were $0.9 million, $0.5 million and $0.6 million, respectively. As of December 31, 2025, unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2025 Incentive PSU Program and 2024 Incentive PSU Program of $18.0 million and $4.6 million, 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,
202520242023 (a)20222021 (a)
Risk-free rate4.22%4.35%4.16%1.52%0.18%
Volatility factor43.15%48.82%59.31%65.38%72.50%
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.
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 1,720,700, 982,990 and 953,270 restricted stock unit equity awards to employees of the Company during the years ended December 31, 2025, 2024 and 2023, 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, 2025, 2024 and 2023, the weighted average fair value of these restricted stock unit grants, based on the grant date fair value of EQT common stock, was approximately $52.80, $34.54 and $31.88, respectively.

The total fair value of restricted stock unit equity awards vested during the years ended December 31, 2025, 2024 and 2023 was $45.5 million, $155.5 million and $23.5 million, respectively. Total capitalized compensation costs related to the restricted stock unit equity awards was $19.4 million, $9.6 million and $5.7 million for the years ended December 31, 2025, 2024 and 2023, respectively.
 
As of December 31, 2025, $66.2 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, 2025.
Restricted Stock – Equity SettledNonvested SharesWeighted Average
Fair Value		Aggregate Fair Value
Outstanding at January 1, 2023
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 awards (a)5,175,814 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 
Granted1,720,700 52.80 90,858,021 
Vested(1,458,200)31.22 (45,519,859)
Forfeited(140,937)35.00 (4,933,212)
Outstanding at December 31, 2025
3,545,732 $43.58 $154,509,335 

(a)In conjunction with the Equitrans Midstream Merger, the Company assumed all outstanding and unvested share-based compensation awards of Equitrans Midstream and converted those awards into restricted stock equity awards.
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 2025, 2024 and 2023.
 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, 2025, 2024 and 2023 was $2.7 million, $0.7 million and $1.4 million, respectively.

The following table summarizes option activity as of December 31, 2025.
Non-Qualified Stock OptionsSharesWeighted Average
Exercise Price		Weighted Average
Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 20251,195,336 $12.14 
Exercised(95,874)23.93 
Outstanding and Exercisable at December 31, 20251,099,462 $11.11 1.3 years$46,713,420 

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 305,556 non-employee director share-based awards, including accrued dividends, were outstanding as of December 31, 2025. A total of 36,630, 70,930 and 66,300 share-based awards were granted to non-employee directors during the years ended December 31, 2025, 2024 and 2023, 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 $50.74, $36.14 and $33.31 for the years ended December 31, 2025, 2024 and 2023, respectively.

2026 Awards

Effective in 2026, the Compensation Committee adopted the 2026 Incentive Performance Share Unit Program (2026 Incentive PSU Program) under the 2020 LTIP. The 2026 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 approximately 505,000 share units were granted under the 2026 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, 2026 through December 31, 2028.
Effective in 2026, the Compensation Committee granted approximately 1,170,000 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.
v3.25.4
Leases
 12 Months Ended
Dec. 31, 2025
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, 2025 and 2024, the Company was not a lessor.

The following table summarizes the Company's lease costs.
Years Ended December 31,
202520242023
(Thousands)
Operating lease costs$43,002 $41,991 $26,755 
Finance lease costs9,585 5,546 2,414 
Variable and short-term lease costs38,935 33,475 24,151 
Total lease costs (a)$91,522 $81,012 $53,320 

(a)Includes drilling rig lease costs capitalized to property, plant and equipment of $47.9 million, $50.5 million and $40.8 million, respectively, of which $30.8 million, $33.1 million and $24.5 million, respectively, were operating lease costs for the years ended December 31, 2025, 2024 and 2023.

The following table summarizes the cash paid for operating and financing lease liabilities reported in the Statements of Consolidated Cash Flows. Cash paid for operating lease liabilities is presented in other items, net as a cash flow from operating activity, and cash paid for finance lease liabilities is presented in other financing activities as a cash flow from financing activity.
Years Ended December 31,
202520242023
(Thousands)
Operating lease liabilities$21,155 $13,595 $10,078 
Finance lease liabilities6,347 4,232 2,305 

For the Company's operating leases, as of December 31, 2025, 2024 and 2023, the weighted average remaining term was 2.4 years, 3.4 years and 1.6 years, respectively, and the weighted average discount rate was 5.1%, 5.3% and 4.7%, respectively. For the Company's finance leases, as of December 31, 2025, 2024 and 2023, the weighted average remaining term was 5.6 years, 6.8 years and 3.8 years, respectively, and the weighted average discount rate was 5.1%, 5.1% and 4.8%, 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 asset retirement obligations and other liabilities, respectively, in the Consolidated Balance Sheets. The following table summarizes the Company's right-of-use assets and lease liabilities.
December 31,
20252024
(Thousands)
Right-of-Use Assets
Operating$74,111 $60,496 
Finance35,650 34,803 
Total right-of-use assets$109,761 $95,299 
Lease Liabilities
Current lease liabilities
Operating$51,042 $36,275 
Finance7,082 5,603 
Total current lease liabilities58,124 41,878 
Noncurrent lease liabilities
Operating27,369 29,391 
Finance29,973 29,263 
Total noncurrent lease liabilities57,342 58,654 
Total lease liabilities$115,466 $100,532 

The following table summarizes the Company's lease payment obligations as of December 31, 2025.
Operating Lease
Finance Lease
Total Lease
(Thousands)
2026$53,639 $8,722 $62,361 
202710,859 8,355 19,214 
20287,915 7,058 14,973 
20295,972 5,879 11,851 
20304,885 4,697 9,582 
Thereafter350 7,705 8,055 
Total lease payment obligations83,620 42,416 126,036 
Less: Imputed interest5,209 5,361 10,570 
Present value of lease liabilities$78,411 $37,055 $115,466 
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, 2025 and 2024, the Company was not a lessor.

The following table summarizes the Company's lease costs.
Years Ended December 31,
202520242023
(Thousands)
Operating lease costs$43,002 $41,991 $26,755 
Finance lease costs9,585 5,546 2,414 
Variable and short-term lease costs38,935 33,475 24,151 
Total lease costs (a)$91,522 $81,012 $53,320 

(a)Includes drilling rig lease costs capitalized to property, plant and equipment of $47.9 million, $50.5 million and $40.8 million, respectively, of which $30.8 million, $33.1 million and $24.5 million, respectively, were operating lease costs for the years ended December 31, 2025, 2024 and 2023.

The following table summarizes the cash paid for operating and financing lease liabilities reported in the Statements of Consolidated Cash Flows. Cash paid for operating lease liabilities is presented in other items, net as a cash flow from operating activity, and cash paid for finance lease liabilities is presented in other financing activities as a cash flow from financing activity.
Years Ended December 31,
202520242023
(Thousands)
Operating lease liabilities$21,155 $13,595 $10,078 
Finance lease liabilities6,347 4,232 2,305 

For the Company's operating leases, as of December 31, 2025, 2024 and 2023, the weighted average remaining term was 2.4 years, 3.4 years and 1.6 years, respectively, and the weighted average discount rate was 5.1%, 5.3% and 4.7%, respectively. For the Company's finance leases, as of December 31, 2025, 2024 and 2023, the weighted average remaining term was 5.6 years, 6.8 years and 3.8 years, respectively, and the weighted average discount rate was 5.1%, 5.1% and 4.8%, 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 asset retirement obligations and other liabilities, respectively, in the Consolidated Balance Sheets. The following table summarizes the Company's right-of-use assets and lease liabilities.
December 31,
20252024
(Thousands)
Right-of-Use Assets
Operating$74,111 $60,496 
Finance35,650 34,803 
Total right-of-use assets$109,761 $95,299 
Lease Liabilities
Current lease liabilities
Operating$51,042 $36,275 
Finance7,082 5,603 
Total current lease liabilities58,124 41,878 
Noncurrent lease liabilities
Operating27,369 29,391 
Finance29,973 29,263 
Total noncurrent lease liabilities57,342 58,654 
Total lease liabilities$115,466 $100,532 

The following table summarizes the Company's lease payment obligations as of December 31, 2025.
Operating Lease
Finance Lease
Total Lease
(Thousands)
2026$53,639 $8,722 $62,361 
202710,859 8,355 19,214 
20287,915 7,058 14,973 
20295,972 5,879 11,851 
20304,885 4,697 9,582 
Thereafter350 7,705 8,055 
Total lease payment obligations83,620 42,416 126,036 
Less: Imputed interest5,209 5,361 10,570 
Present value of lease liabilities$78,411 $37,055 $115,466 
v3.25.4
Concentrations of Credit Risk
 12 Months Ended
Dec. 31, 2025
Risks and Uncertainties [Abstract]  
Concentrations of Credit Risk Concentrations of Credit Risk
Revenues and related accounts receivable from the Company's Upstream 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, 2025 and 2024, approximately 94% and 96%, 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, 2025, 2024 and 2023.

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, 2025, 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, 2025, 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 a significant adverse effect on the Company's ability to generate revenues through its gathering, transmission and storage services.
v3.25.4
Natural Gas Producing Activities (Unaudited)
 12 Months Ended
Dec. 31, 2025
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,
 20252024
 (Thousands)
Capitalized costs
Proved properties$35,129,865 $31,986,473 
Unproved properties1,656,045 1,563,440 
Total capitalized costs36,785,910 33,549,913 
Less: Accumulated depreciation and depletion14,344,974 12,489,317 
Net capitalized costs$22,440,936 $21,060,596 
Years Ended December 31,
202520242023
(Thousands)
Costs incurred (a)
Property acquisition:   
Proved properties (b)$1,522,869 $410,805 $4,142,621 
Unproved properties (c)390,103 98,007 575,130 
Exploration3,601 2,735 3,330 
Development1,725,438 1,848,000 1,782,428 

(a)Amounts for all years presented exclude costs related to facilities, information technology and other corporate items. Amounts for 2025 and 2024 exclude costs related to midstream assets, while amounts for 2023 include such costs.
(b)Amounts in 2025 include $1,234.5 million and $288.4 million for wells and leases, respectively, acquired in the Olympus Energy Acquisition. 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. 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.
(c)Amounts in 2025 include $235.5 million for unproved properties acquired in the Olympus Energy Acquisition. Amounts in 2024 include $10.8 million for unproved properties received as consideration for the First NEPA Non-Operated Asset Divestiture. Amounts in 2023 include $523.0 million for unproved properties acquired in the Tug Hill and XcL Midstream Acquisition.

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,
202520242023
(Thousands)
Sales of natural gas, NGLs and oil$7,726,712 $4,934,366 $5,044,768 
Transportation and processing1,532,090 1,915,616 2,157,260 
Production388,696 377,007 254,700 
Operating and maintenance23,013 37,951 — 
Exploration3,601 2,735 3,330 
Depreciation and depletion2,263,105 2,016,670 1,732,142 
(Gain) loss on sale/exchange of long-lived assets(31,513)(764,431)17,445 
Impairment and expiration of leases50,341 97,368 109,421 
Income tax expense851,939 316,377 187,463 
Results of operations from producing activities, excluding corporate overhead$2,645,440 $935,073 $583,007 
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 23 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, 2025. 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 uses 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,
 202520242023
 (MMcfe)
Natural gas, NGLs and oil   
Proved developed and undeveloped reserves:   
Balance at January 126,264,669 27,596,694 25,002,589 
Revision of previous estimates(27,073)(1,079,677)(1,402,039)
Purchase of hydrocarbons in place1,768,560 413,040 2,600,667 
Sale of hydrocarbons in place(22,027)(1,562,849)— 
Extensions, discoveries and other additions2,444,717 3,125,620 3,411,750 
Production(2,382,367)(2,228,159)(2,016,273)
Balance at December 3128,046,479 26,264,669 27,596,694 
Proved developed reserves:
Balance at January 118,804,929 19,558,176 17,513,645 
Balance at December 3120,580,992 18,804,929 19,558,176 
Proved undeveloped reserves:
Balance at January 17,459,740 8,038,518 7,488,944 
Balance at December 317,465,487 7,459,740 8,038,518 
 Years Ended December 31,
 202520242023
 (MMcf)
Natural gas   
Proved developed and undeveloped reserves:   
Balance at January 124,545,229 25,795,134 23,824,887 
Revision of previous estimates(15,493)(917,676)(1,461,305)
Purchase of natural gas in place1,768,120 395,423 2,012,159 
Sale of natural gas in place(16,145)(1,562,849)— 
Extensions, discoveries and other additions2,373,231 2,921,638 3,326,736 
Production(2,238,652)(2,086,441)(1,907,343)
Balance at December 3126,416,290 24,545,229 25,795,134 
Proved developed reserves:   
Balance at January 117,440,191 18,186,432 16,541,017 
Balance at December 3119,237,547 17,440,191 18,186,432 
Proved undeveloped reserves:
Balance at January 17,105,038 7,608,702 7,283,870 
Balance at December 317,178,743 7,105,038 7,608,702 

 Years Ended December 31,
202520242023
(Mbbl)
NGLs   
Proved developed and undeveloped reserves:   
Balance at January 1271,908 285,345 186,141 
Revision of previous estimates750 (24,332)11,558 
Purchase of NGLs in place73 2,529 90,604 
Sale of NGLs in place(902)— — 
Extensions, discoveries and other additions10,317 30,391 13,592 
Production(22,168)(22,025)(16,550)
Balance at December 31259,978 271,908 285,345 
Proved developed reserves:  
Balance at January 1217,786 218,523 154,921 
Balance at December 31215,302 217,786 218,523 
Proved undeveloped reserves:
Balance at January 154,122 66,822 31,220 
Balance at December 3144,676 54,122 66,822 
 Years Ended December 31,
 202520242023
 (Mbbl)
Oil   
Proved developed and undeveloped reserves:   
Balance at January 114,664 14,915 10,142 
Revision of previous estimates(2,680)(2,669)(1,680)
Purchase of oil in place— 407 7,481 
Sale of oil in place(78)— — 
Extensions, discoveries and other additions1,598 3,606 577 
Production(1,784)(1,595)(1,605)
Balance at December 3111,720 14,664 14,915 
Proved developed reserves:   
Balance at January 19,669 10,101 7,183 
Balance at December 318,605 9,669 10,101 
Proved undeveloped reserves:
Balance at January 14,995 4,814 2,959 
Balance at December 313,115 4,995 4,814 

The change in reserves during the year ended December 31, 2025 resulted from the following:

•Conversions of 2,380 billion cubic feet equivalent (Bcfe) of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 2,445 Bcfe, which exceeded 2025 production of 2,382 Bcfe. Extensions, discoveries and other additions included an increase of 1,605 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2025 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan, 393 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 133 Bcfe from the extension of lateral lengths of proved undeveloped reserves and 314 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 560 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 42 Bcfe to proved undeveloped locations primarily related to revisions to lateral lengths and type curves.
•Positive revisions to proved undeveloped locations of 291 Bcfe due primarily to changes in ownership interests.
•Negative revisions of 165 Bcfe primarily from proved developed locations as a result of negative curve revisions.
•Positive revisions of 449 Bcfe from proved developed locations as a result of higher pricing, impacting well economics.
•Purchase of hydrocarbons in place of 1,768 Bcfe in connection with the Olympus Energy Acquisition described in Note 11.
•Sale of natural gas in place of 22 Bcfe in connection with the Non-Core Asset Divestiture described in Note 12.
The change in reserves during the year ended December 31, 2024 resulted from the following:

•Conversions of 2,637 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 12.
•Sale of natural gas in place of 1,563 Bcfe in the NEPA Non-Operated Asset Divestitures described in Note 12.

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 11.
Standardized Measure of Discounted Future Net 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,
 202520242023
 (Thousands)
Future cash inflows (a)$80,216,863 $44,871,509 $52,916,665 
Future production costs (b)(21,496,216)(18,979,056)(24,357,033)
Future development costs(4,456,051)(4,352,890)(4,298,372)
Future income tax expenses(11,001,125)(4,445,354)(5,230,629)
Future net cash flows43,263,471 17,094,209 19,030,631 
10% annual discount for estimated timing of cash flows
(21,953,285)(9,095,069)(9,768,282)
Standardized measure of discounted future net cash flows$21,310,186 $7,999,140 $9,262,349 

(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 differentials. Regional differentials 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,
202520242023
Natural gas for NYMEX ($/MMBtu)$3.387 $2.130 $2.637 
Less: Regional differentials ($/MMBtu)0.786 0.741 1.029 
Natural gas price ($/Mcf)2.749 1.468 1.700 
NGLs price ($/Bbl)26.97 29.28 28.44 
Oil for West Texas Intermediate (WTI) ($/Bbl)66.01 76.32 78.21 
Less: Regional differentials ($/Bbl)15.29 16.87 14.35 
Oil price ($/Bbl)50.72 59.45 63.86 

(b)Includes approximately $2,629 million, $2,553 million and $2,443 million for future plugging and abandonment costs as of December 31, 2025, 2024 and 2023, 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, 2025 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,265 million, $1,104 million and $61 million, respectively.
The following table summarizes the changes in the standardized measure of discounted future net cash flows.
Years Ended December 31,
 202520242023
 (Thousands)
Net sales and transfers of natural gas and oil produced$(5,782,913)$(2,603,792)$(2,632,808)
Net changes in prices, production and development costs16,980,282 (1,237,271)(48,739,248)
Extensions, discoveries and improved recovery, net of related costs292,028 464,496 6,347,387 
Development costs incurred1,281,816 1,432,315 1,296,380 
Net purchase of minerals in place1,874,429 269,453 2,131,567 
Net sale of minerals in place(3,053)(692,019)— 
Revision of previous estimates135,348 (263,191)(2,768,922)
Accretion of discount799,914 926,235 4,006,452 
Net change in income taxes(2,438,815)411,999 9,190,460 
Timing and other172,010 28,566 366,557 
Net increase (decrease)13,311,046 (1,263,209)(30,802,175)
Balance at January 17,999,140 9,262,349 40,064,524 
Balance at December 31$21,310,186 $7,999,140 $9,262,349 

Following the completion of the Equitrans Midstream Merger as described in Note 11, 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 9, 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.
v3.25.4
Schedule II - Valuation and Qualifying Accounts and Reserves
 12 Months Ended
Dec. 31, 2025
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, 2025
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:
2025$257,218 $31,798 $— $(34,556)$254,460 
2024$290,812 $21,564 $— $(55,158)$257,218 
2023$365,140 $12,549 $— $(86,877)$290,812 

See Note 6 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.
v3.25.4
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2025
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
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
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 2025. 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 Audit Committee receives a regular quarterly report regarding cybersecurity matters and our enterprise cybersecurity program. This report is presented to the Audit Committee by our Chief Information Officer or our Vice President, Information Technology.
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 Audit Committee receives a regular quarterly report regarding cybersecurity matters and our enterprise cybersecurity program. This report is presented to the Audit Committee by our Chief Information Officer or our Vice President, Information Technology.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] Our Audit Committee receives a regular quarterly report regarding cybersecurity matters and our enterprise cybersecurity program. This report is presented to the Audit Committee by our Chief Information Officer or our Vice President, Information Technology.
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. During our Chief Information Officer's sabbatical from September 2025 to the beginning of February 2026, our Vice President, Information Technology, who reports directly to our Chief Information Officer, assumed such responsibility and consulted with our Chief Information Officer as he deemed appropriate. 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 20 years of information technology experience within the energy industry.

Our Information Security team, led by our Vice President, Information Technology 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. Our Vice President, Information Technology, has served in his current role since 2019 and has over 25 years of information technology experience. He is responsible for our enterprise technology strategy and operations, including infrastructure, applications, cybersecurity, and data platforms, and previously served as Director of IT Operations at Rice Energy Inc. for four years prior to joining EQT.
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. During our Chief Information Officer's sabbatical from September 2025 to the beginning of February 2026, our Vice President, Information Technology, who reports directly to our Chief Information Officer, assumed such responsibility and consulted with our Chief Information Officer as he deemed appropriate. 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 20 years of information technology experience within the energy industry.

Our Information Security team, led by our Vice President, Information Technology 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. Our Vice President, Information Technology, has served in his current role since 2019 and has over 25 years of information technology experience. He is responsible for our enterprise technology strategy and operations, including infrastructure, applications, cybersecurity, and data platforms, and previously served as Director of IT Operations at Rice Energy Inc. for four years prior to joining EQT.
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 20 years of information technology experience within the energy industry.. Our Vice President, Information Technology, has served in his current role since 2019 and has over 25 years of information technology experience.
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
v3.25.4
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2025
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 owns 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.

The Company consolidates its controlling interest in the Midstream Joint Venture (defined in Note 9) under the voting interest entity model. See Note 9 for discussion of the method of allocation used in accounting for the portion of Midstream Joint Venture that is not owned by the Company.

In addition, the Company consolidates its 60% interest in Eureka Midstream Holdings, LLC (Eureka 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. Eureka Holdings conducts its operations through its wholly owned subsidiary, Eureka Midstream, LLC (Eureka), which has a revolving credit facility that is consolidated into the Company's debt. See Note 7.

In 2023, a variable interest entity formed in 2020 and previously consolidated by the Company was dissolved following a pro rata distribution of its assets to its members. The Company had previously consolidated the entity as the Company was its primary beneficiary.

Prior to the NEPA Gathering System Acquisition (defined in Note 11) and the First NEPA Non-Operated Asset Divestiture (defined in Note 12), the Company recorded its pro rata share of the NEPA Gathering System (defined in Note 11) in the Consolidated Financial Statements. Following these transactions, the Company owns 100% of the NEPA Gathering System.
Segments
Segments. The Company has three reportable segments reflecting its three lines of business consisting of Upstream, 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, effective as of December 31, 2025, the Company renamed its previously reported "Production" segment as the "Upstream" segment.
Use of Estimates
Use of Estimates. The preparation of the Consolidated 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 in the Statements of Consolidated Operations.
Accounts Receivable
Accounts Receivable, Net of Allowance for Credit Losses. The Company's accounts receivable relate primarily to sales of natural gas and natural gas liquids (NGLs), pipeline revenue and amounts due from joint interest partners. See Note 3 for a discussion of amounts due from contracts with customers. Allowances for credit losses are recorded in selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required in assessing the ultimate realization of the Company's accounts receivable. The allowance for credit losses is 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,
 20252024
 (Thousands)
Margin requirements with counterparties (see Note 4)
$36,810 $86,975 
Prepaid expenses and other current assets59,441 52,044 
Total prepaid expenses and other$96,251 $139,019 
Impairment of Property, Plant and Equipment
Impairment of Property, Plant and Equipment

Impairment of Proved Oil and Gas Properties and Related Midstream Assets. The carrying values of the Company's proved oil and gas properties, together with related midstream assets that are operationally and economically interdependent, are reviewed for impairment when events or circumstances indicate that the carrying amount 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 Company's internal planning assumptions, including, among other things, future natural gas and NGLs sales prices; estimated reserve quantities and expected timing of production; projected gathered and processed volumes and transmission throughput; associated fee-based revenues; future operating costs and capital requirements; and discount and inflation assumptions. 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. No indicators of impairment to the Company's material asset groups were identified during 2025, 2024 and 2023.
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, historical experience or changes in market conditions. 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 circumstances indicate that the carrying amount may not be recoverable. No indicators of impairment were identified during 2025, 2024 and 2023.
Investments in Unconsolidated Entities
Investments in Unconsolidated Entities. The Company applies the equity method of accounting to its investments in entities over which 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. The Company's pro-rata share of income or loss from these investments is recorded in income from investments in the Statements of Consolidated Operations.

The Company accounts for investments in entities over which the Company does not have the ability to exercise significant influence as investments in equity securities. Changes in the fair value of these investments are recorded in income from investments, and dividends received on such investments are recorded in other income in the Statements of Consolidated Operations.

See Note 8 for a discussion of the Company's investments in unconsolidated entities.
The Company evaluates its investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. The Company considers expected future cash flows of the investee, the investee's ability to generate cash flows sufficient to recover its carrying value, and market, operational or financial developments. The recognition of an impairment loss is required if the impairment is considered other than temporary. N
Net Intangible Assets and Goodwill
Net Intangible Assets. The following table summarizes the Company's intangible assets.

December 31,
20252024
(Thousands)
Acquired transmission services agreements$200,000 $200,000 
Less: Accumulated amortization19,234 5,901 
Net intangible assets related to acquired transmission services agreements180,766 194,099 
Other intangible assets24,922 24,922 
Less: Accumulated amortization5,202 3,764 
Net other intangible assets19,720 21,158 
Net intangible assets$200,486 $215,257 

The intangible assets related to acquired transmission services agreements are amortized on a straight-line basis over their estimated useful lives, which reflects the pattern in which the Company expects to consume the economic benefits of the assets. During the years ended December 31, 2025 and 2024, the Company recognized amortization expense of $13.3 million and $5.9 million, respectively, related to these acquired transmission services agreement intangible assets. The estimated annual amortization expense for these intangible assets is $13.3 million for each of the next 5 years.

The Company evaluates its intangible assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. Indicators of potential impairment may include changes in market conditions, customer demand or expected utilization of the underlying contracts. No indicators of impairment to the Company's net intangible assets were identified during 2025 and 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 (including, among other things, the Company's market capitalization and stock price as well as relevant market, economic or regulatory developments) to determine whether it is more likely than not (greater than 50%) that the fair value of the Company's 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 that incorporates forecasted cash flows, discount rate assumptions including weighted-average cost of capital, terminal growth rates and relevant industry multiples. 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 Discounts and Issuance Costs. Discounts and costs incurred with the issuance of debt are capitalized as a reduction of debt and amortized into net interest expense over the term of the debt. Costs incurred with the issuance or amendment of revolving credit facilities are capitalized as a noncurrent asset and amortized into net interest expense over the term of the facility.
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 income. 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.

The Midstream Joint Venture and Eureka Holdings 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. The Midstream Joint Venture's and Eureka Holdings' 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 the Midstream Joint Venture and Eureka Holdings, 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 federal and state taxable income forecasts, state apportionment analyses, reversals of temporary differences, tax planning strategies, prior year carrybacks and the expected utilization of tax credits.
 
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 coverage for customary insurable risks, including general liability, workers' compensation, auto liability, environmental liability, property damage, business interruption, fiduciary liability and directors' and officers' liability. These policies are subject to deductibles, self-insured retentions, 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 maintains insurance coverage for such losses arising on or after November 12, 2020.

Certain legacy insurance programs of Equitrans Midstream Corporation (Equitrans Midstream), which the Company acquired in July 2024 (see Note 11), applied to losses arising prior to the transition to the Company's insurance programs. These programs included higher self-insured retentions for certain material losses related to excess liability and environmental liability arising before December 20, 2024 as well as limited co-insurance related to material losses under the property insurance coverage. Losses arising thereafter are included in the Company's insurance programs, which generally do not include high self-insured retentions or co-insurance amounts.

The Company records insurance reserves on an undiscounted basis using analyses of historical claims 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. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims, differ from estimates. There can be no assurance that the insurance policies we maintain to limit our liability for such losses will be adequate to protect the Company from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices or to cover all risks.
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 of the obligation are based on the expected timing of settlement, estimated costs (informed by the Company's historical experience with plugging and abandoning wells and reclaiming or disposing of other assets), the estimated remaining lives of the wells and related assets and the discount rates used to determine the present value of expected future settlement costs.

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 other revenues.
Defined Contribution Plan and Other Postretirement Benefits Plan
Defined Contribution Plan. The Company recognized expense related to its defined contribution plan of $25.1 million, $14.5 million and $9.0 million for the years ended December 31, 2025, 2024 and 2023, respectively.
Recently Issued Accounting Standards
Recently Issued Accounting Standards

In December 2025, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2025-12, Codification Improvements, to clarify guidance, correct technical errors, remove outdated language and improve consistency across various topics in the Accounting Standards Codification. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2026, including interim reporting periods within those annual periods. Early adoption is permitted. The Company is evaluating the impact ASU 2025-12 will have on its financial statements and related disclosures and does not expect adoption of ASU 2025-12 to have a material impact.

In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements, to clarify the scope and presentation requirements for interim GAAP financial statements and to consolidate interim disclosure requirements. Under this ASU, entities must disclose material events or changes occurring after year end that affect interim periods. The amendments in this ASU are effective for interim reporting periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively to any or all prior periods presented in the financial statements. The Company is evaluating the impact ASU 2025-11 will have 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.

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 (i) disclose specific categories in the rate reconciliation and (ii) provide additional information for reconciling items that meet a quantitative threshold. This ASU is effective for annual reporting periods beginning after December 15, 2024. The Company adopted ASU 2023-09 in the fourth quarter of 2025. See Note 6 for 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 fee 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 because 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.
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 redemption, the Convertible Notes. Purchases of treasury shares are calculated using the average share price of EQT common stock during the period. Prior to redemption, the Company used the if-converted method to calculate the impact of the Convertible Notes on diluted income per share.
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.
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.
v3.25.4
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2025
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,
 20252024
 (Thousands)
Margin requirements with counterparties (see Note 4)
$36,810 $86,975 
Prepaid expenses and other current assets59,441 52,044 
Total prepaid expenses and other$96,251 $139,019 
Schedule of Property, Plant and Equipment The following table summarizes the Company's property, plant and equipment.
 December 31,
 20252024
 (Thousands)
Oil and gas producing properties$36,785,910 $33,549,913 
Less: Accumulated depletion14,344,974 12,489,317 
Net oil and gas producing properties22,440,936 21,060,596 
Other upstream assets, at cost less accumulated depreciation
27,073 20,434 
Net upstream assets
22,468,009 21,081,030 
Gathering assets8,677,011 8,067,556 
Less: Accumulated depreciation337,889 131,546 
Net gathering assets8,339,122 7,936,010 
Transmission and storage assets2,751,815 2,667,352 
Less: Accumulated depreciation110,539 30,027 
Net transmission and storage assets2,641,276 2,637,325 
Other property, plant and equipment, at cost less accumulated depreciation109,401 93,453 
Net property, plant and equipment$33,557,808 $31,747,818 
Schedule of Intangible Assets The following table summarizes the Company's intangible assets.
December 31,
20252024
(Thousands)
Acquired transmission services agreements$200,000 $200,000 
Less: Accumulated amortization19,234 5,901 
Net intangible assets related to acquired transmission services agreements180,766 194,099 
Other intangible assets24,922 24,922 
Less: Accumulated amortization5,202 3,764 
Net other intangible assets19,720 21,158 
Net intangible assets$200,486 $215,257 
Summary of Other Current Liabilities The following table summarizes the Company's other current liabilities.
 December 31,
 20252024
 (Thousands)
Accrued taxes other than income$108,626 $114,700 
Accrued incentive compensation90,694 53,138 
Current portion of lease liabilities58,124 41,878 
Current portion of long-term capacity contracts30,903 43,697 
Accrued payroll9,313 12,115 
Deferred revenue6,240 24,187 
Other accrued liabilities31,587 59,702 
Total other current liabilities$335,487 $349,417 
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 asset retirement obligations and other liabilities in the Consolidated Balance Sheets.
 December 31,
 20252024
 (Thousands)
Balance at January 1$1,003,570 $911,057 
Accretion expense76,745 68,501 
Liabilities incurred31,394 21,587 
Liabilities settled(52,210)(66,729)
Liabilities assumed in acquisitions14,923 45,847 
Liabilities removed in divestitures (a)(98,839)(28,701)
Change in estimates (b)43,922 52,008 
Balance at December 31$1,019,505 $1,003,570 

(a)Primarily attributable to the derecognition of asset retirement obligations associated with the Non-Core Asset Divestiture (defined and discussed in Note 12).
(b)During 2025 and 2024, the Company recorded changes in estimates attributable primarily to increased plugging costs.
Schedule of Regulated Operating Revenues, Expenses, Property, Plant and Equipment The Company did not have regulated operations during the year ended December 31, 2023.
Years Ended December 31,
 20252024
 (Thousands)
Operating revenues$572,975 $218,569 
Operating expenses194,576 78,908 
The following table presents Equitrans, L.P.'s regulated property, plant and equipment included in the Company's Consolidated Balance Sheets.
December 31,
 20252024
 (Thousands)
Property, plant and equipment$2,751,815 $2,667,352 
Less: Accumulated depreciation110,539 30,027 
Net property, plant and equipment$2,641,276 $2,637,325 
Schedule of Regulatory Assets The following table summarizes Equitrans, L.P.'s regulated assets and liabilities.
December 31,
20252024
 (Thousands)
Regulated assets:
Deferred taxes (a)$139,221 $142,757 
Other recoverable costs (b)17,938 23,182 
Total regulated assets$157,159 $165,939 
Regulated liabilities:
Deferred taxes (a)$8,136 $8,534 
Ongoing postretirement benefits other than pension and other reimbursable costs (c)23,199 20,158 
Total regulated liabilities$31,335 $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 8.5 years, and costs associated with a legacy postretirement benefits plan, which Equitrans, L.P. expects to continue to recover over the next 6.5 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.
December 31,
20252024
 (Thousands)
Regulated assets:
Deferred taxes (a)$139,221 $142,757 
Other recoverable costs (b)17,938 23,182 
Total regulated assets$157,159 $165,939 
Regulated liabilities:
Deferred taxes (a)$8,136 $8,534 
Ongoing postretirement benefits other than pension and other reimbursable costs (c)23,199 20,158 
Total regulated liabilities$31,335 $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 8.5 years, and costs associated with a legacy postretirement benefits plan, which Equitrans, L.P. expects to continue to recover over the next 6.5 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.
Summary of Other Operating Expenses The following table summarizes the Company's other operating expenses.
Years Ended December 31,
202520242023
(Thousands)
Changes in legal and environmental reserves, including settlements$185,253 $16,271 $9,342 
Transaction costs35,843 309,419 56,263 
Other23,584 24,174 18,438 
Total other operating expenses$244,680 $349,864 $84,043 
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,
202520242023
(Thousands)
Cash paid (received) during the year for:
Interest, net of amount capitalized$455,091 $401,768 $213,141 
Income taxes, net(79,022)7,960 13,350 
Non-cash activity during the period for:
Issuance of EQT common stock as consideration for acquisition (Note 11)$1,471,365 $5,548,608 $2,152,631 
Increase in asset retirement costs and obligations75,390 73,576 106,548 
Increase in right-of-use assets and lease liabilities, net65,323 29,568 45,774 
Capitalization of non-cash equity share-based compensation20,258 10,095 6,287 
Investments in unconsolidated entities17,981 3,428 — 
Issuance of EQT common stock upon Convertible Notes settlement (Note 7)— 285,608 122,830 
First NEPA Non-Operated Asset Divestiture (Note 12)
— 155,318 — 
Accrued transaction costs related to the sale of units of the Midstream Joint Venture (Note 9)— 1,135 — 
Dissolution of consolidated variable interest entity— — 25,227 
The table below summarizes income tax payments, net of refunds.
 Years Ended December 31,
 202520242023
 (Thousands)
Federal$(81,195)$12,149 $12,876 
State:
Mississippi**670 
Pennsylvania*(4,114)*
Other U.S. states2,173 (75)(196)
Total taxes paid, net of refunds$(79,022)$7,960 $13,350 
*Indicates that the amount paid or refunded did not exceed the applicable disclosure threshold for the periods presented and is included in other U.S. states.
v3.25.4
Financial Information by Business Segment (Tables)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Schedule Of Financial Information By Business Segment and Capital Expenditures The following tables present information about segment revenue, segment profit or loss and significant segment expenses and include a reconciliation of total segment amounts to the Company's consolidated totals.
Year Ended December 31, 2025
UpstreamGatheringTransmissionTotal SegmentIntersegment Eliminations and OtherEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$7,726,712 $— $— $7,726,712 $— $7,726,712 
Gain on derivatives290,994 — — 290,994 — 290,994 
Pipeline and other6,351 1,301,434 572,252 1,880,037 (1,253,532)626,505 
Total operating revenues8,024,057 1,301,434 572,252 9,897,743 (1,253,532)8,644,211 
Operating expenses (a):
Transportation and processing2,783,455 — — 2,783,455 (1,251,365)1,532,090 
Production388,696 — — 388,696 — 388,696 
Operating and maintenance— 166,990 58,141 225,131 — 225,131 
Exploration3,601 — — 3,601 — 3,601 
Selling, general and administrative217,803 66,642 37,339 321,784 58,282 380,066 
Depreciation, depletion and amortization2,263,105 212,353 101,718 2,577,176 23,214 2,600,390 
(Gain) loss on sale/exchange of long-lived assets(31,513)(29)349 (31,193)(21)(31,214)
Impairment and expiration of leases50,341 811 — 51,152 — 51,152 
Other operating expenses (b)30,438 18,013 (527)47,924 196,756 244,680 
Total operating expenses5,705,926 464,780 197,020 6,367,726 (973,134)5,394,592 
Operating income (loss)$2,318,131 $836,654 $375,232 $3,530,017 $(280,398)$3,249,619 

(a)The significant expense categories and amounts presented align with information that is regularly provided to the CODM.
(b)Corporate other operating expenses consisted primarily of legal reserves related to the Securities Class Action (defined in Note 13) and transaction costs related to the Olympus Energy Acquisition (defined in Note 11). See Notes 13 and 11 for information on the Securities Class Action and Olympus Energy Acquisition, respectively. See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2024
UpstreamGatheringTransmissionTotal 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 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 CODM.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for the Company's change in reportable segments from one reportable segment to three reportable segments as the necessary information was 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 11. See Note 1 for a summary of the Company's consolidated other operating expenses.
Year Ended December 31, 2023
UpstreamGatheringTotal 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 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 CODM.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for the Company's change in reportable segments from one reportable segment to three reportable segments as the necessary information was 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 11). See Note 1 for a summary of the Company's consolidated other operating expenses.
Reconciliation of total segment operating income to consolidated income before income taxes
Years Ended December 31,
202520242023
(Thousands)
Total segment operating income$3,530,017 $1,075,902 $2,399,042 
Less:
Intersegment eliminations2,303 457 — 
Unallocated amounts:
Unallocated other revenues(136)(34)— 
Corporate selling, general and administrative58,282 36,254 — 
Corporate depreciation and amortization23,214 16,761 9,765 
Corporate gain on sale/exchange of long-lived assets(21)— — 
Corporate other operating expenses (a)196,756 337,168 74,866 
Income from investments (b)(184,444)(76,039)(7,596)
Other income(4,826)(25,983)(1,231)
Loss on debt extinguishment22,652 68,299 80 
Interest expense, net438,695 454,825 219,660 
Income before income taxes$2,977,542 $264,194 $2,103,498 

(a)For the year ended December 31, 2025, corporate other operating expenses consisted primarily of legal reserves related to the Securities Class Action and transaction costs related to the Olympus Energy Acquisition. For the year ended December 31, 2024, corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger. For the year ended December 31, 2023, corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition.
(b)For the years ended December 31, 2025 and 2024, income from investments included $154.3 million and $78.8 million, respectively, of equity earnings from the Company's investment in the MVP Joint Venture.
The following table presents information about segment capital expenditures.
Years Ended December 31,
202520242023
(Thousands)
Upstream
$1,878,052 $2,003,635 $1,878,417 
Gathering367,697 202,264 31,701 
Transmission51,769 31,446 — 
Total segment capital expenditures2,297,518 2,237,345 1,910,118 
Other corporate items26,119 28,603 15,125 
Total capital expenditures$2,323,637 $2,265,948 $1,925,243 
Schedule of Segment Assets The following table presents information about segment assets. The Company's investment in the MVP Joint Venture is presented in investments in unconsolidated entities in the Consolidated Balance Sheets.
UpstreamGatheringTransmissionTotal Segment
December 31, 2025(Thousands)
Investment in the MVP Joint Venture$— $— $3,514,803 $3,514,803 
Goodwill (a)— — 1,231,783 1,231,783 
Other segment assets24,295,091 8,676,118 2,891,096 35,862,305 
Total assets$24,295,091 $8,676,118 $7,637,682 $40,608,891 
December 31, 2024
Investment in the MVP Joint Venture$— $— $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 

(a)Changes in goodwill during the year ended December 31, 2025 reflect measurement-period adjustments resulting from the finalization of the purchase price allocation for the Equitrans Midstream Merger.
Reconciliation of total segment assets to consolidated total assets
December 31,
202520242023
(Thousands)
Total segment assets$40,608,891 $38,513,727 $25,019,540 
Intersegment eliminations(204,403)(318,835)(47,471)
Unallocated amounts:
Cash and cash equivalents110,795 202,093 80,977 
Income tax receivable27,756 97,378 91,414 
Other property, plant and equipment, at cost less accumulated depreciation109,401 93,453 40,739 
Goodwill (a)830,679 861,739 — 
Regulatory asset from deferred taxes139,221 142,757 — 
Other170,534 237,943 99,899 
Total assets$41,792,874 $39,830,255 $25,285,098 

(a)Represents unallocated goodwill attributable to additional deferred tax liabilities recognized in connection with the Equitrans Midstream Merger. Changes in goodwill during the year ended December 31, 2025 reflect measurement-period adjustments resulting from the finalization of the purchase price allocation for the Equitrans Midstream Merger.
v3.25.4
Revenue from Contracts with Customers (Tables)
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Schedule of Disaggregation of Revenue These contracts are reported in pipeline and other revenues in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
Years Ended December 31,
202520242023
(Thousands)
Revenues from contracts with customers:
Upstream sales
Natural gas$7,018,766 $4,224,882 $4,520,817 
NGLs620,384 615,933 427,760 
Oil87,562 93,551 96,191 
Sales of natural gas, NGLs and oil7,726,712 4,934,366 5,044,768 
Gathering pipeline revenue
Firm reservation fee (a)632,916 313,987 — 
Volumetric-based fee668,518 452,476 161,395 
Total Gathering pipeline revenue1,301,434 766,463 161,395 
Transmission pipeline revenue
Firm reservation fee435,194 183,088 — 
Volumetric-based fee137,058 35,205 — 
Total Transmission pipeline revenue572,252 218,293 — 
Intersegment eliminations and other(1,253,532)(704,517)(148,830)
Total revenues from contracts with customers (b)8,346,866 5,214,605 5,057,333 
Other sources of revenue:
Gain on derivatives290,994 51,117 1,838,941 
Other revenues6,351 7,587 12,649 
Total other sources of revenue297,345 58,704 1,851,590 
Total operating revenues$8,644,211 $5,273,309 $6,908,923 

(a)Firm reservation fee revenue included unbilled revenues supported by MVCs of $18.4 million and $4.2 million for the years ended December 31, 2025 and 2024, respectively.
(b)For contracts with customers in which the Company had satisfied its performance obligations and held an unconditional right to consideration at the balance sheet date, the Company recorded accounts receivable of $1,159.0 million and $939.9 million as of December 31, 2025 and 2024, 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, 2025.
20262027202820292030ThereafterTotal
(Thousands)
Upstream natural gas sales$4,597 $1,978 $— $— $— $— $6,575 
Gathering firm reservation fee revenue:
Third-party100,794 85,998 85,998 85,998 85,998 287,261 732,047 
Affiliate101,792 101,450 97,701 97,701 103,977 1,403,698 1,906,319 
Total202,586 187,448 183,699 183,699 189,975 1,690,959 2,638,366 
Gathering revenue supported by MVCs:
Third-party96,377 89,203 80,536 67,311 56,762 132,254 522,443 
Affiliate397,966 410,621 411,740 410,622 408,322 1,634,128 3,673,399 
Total494,343 499,824 492,276 477,933 465,084 1,766,382 4,195,842 
Transmission firm reservation fee revenue:
Third-party185,328 176,986 171,814 169,198 165,686 660,199 1,529,211 
Affiliate253,089 262,637 260,776 260,445 260,445 1,704,604 3,001,996 
Total438,417 439,623 432,590 429,643 426,131 2,364,803 4,531,207 
Total remaining performance obligations$1,139,943 $1,128,873 $1,108,565 $1,091,275 $1,081,190 $5,822,144 $11,371,990 
v3.25.4
Derivative Instruments (Tables)
 12 Months Ended
Dec. 31, 2025
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, 2025(Thousands)
Asset derivative instruments, at fair value$202,390 $(79,250)$— $123,140 
Liability derivative instruments, at fair value137,299 (79,250)(36,810)21,239 
December 31, 2024
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 
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, 2025(Thousands)
Asset derivative instruments, at fair value$202,390 $(79,250)$— $123,140 
Liability derivative instruments, at fair value137,299 (79,250)(36,810)21,239 
December 31, 2024
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 
v3.25.4
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2025
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, 2025(Thousands)
Asset derivative instruments, at fair value$202,390 $43,200 $159,190 $— 
Liability derivative instruments, at fair value137,299 39,164 98,135 — 
December 31, 2024
Asset derivative instruments, at fair value$143,581 $50,300 $93,281 $— 
Liability derivative instruments, at fair value446,519 81,074 365,445 — 
v3.25.4
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Schedule of Income Tax Expense (Benefit)
The following table summarizes the Company's income tax expense.
 Years Ended December 31,
 202520242023
 (Thousands)
Current:   
Federal$(7,296)$1,222 $(10,894)
State1,344 6,125 (4,818)
Current income tax (benefit) expense(5,952)7,347 (15,712)
Deferred:
Federal551,000 (21,463)450,091 
State106,836 36,195 (65,425)
Deferred income tax expense657,836 14,732 384,666 
Total income tax expense$651,884 $22,079 $368,954 
Schedule of Income Tax Payments 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,
202520242023
(Thousands)
Cash paid (received) during the year for:
Interest, net of amount capitalized$455,091 $401,768 $213,141 
Income taxes, net(79,022)7,960 13,350 
Non-cash activity during the period for:
Issuance of EQT common stock as consideration for acquisition (Note 11)$1,471,365 $5,548,608 $2,152,631 
Increase in asset retirement costs and obligations75,390 73,576 106,548 
Increase in right-of-use assets and lease liabilities, net65,323 29,568 45,774 
Capitalization of non-cash equity share-based compensation20,258 10,095 6,287 
Investments in unconsolidated entities17,981 3,428 — 
Issuance of EQT common stock upon Convertible Notes settlement (Note 7)— 285,608 122,830 
First NEPA Non-Operated Asset Divestiture (Note 12)
— 155,318 — 
Accrued transaction costs related to the sale of units of the Midstream Joint Venture (Note 9)— 1,135 — 
Dissolution of consolidated variable interest entity— — 25,227 
The table below summarizes income tax payments, net of refunds.
 Years Ended December 31,
 202520242023
 (Thousands)
Federal$(81,195)$12,149 $12,876 
State:
Mississippi**670 
Pennsylvania*(4,114)*
Other U.S. states2,173 (75)(196)
Total taxes paid, net of refunds$(79,022)$7,960 $13,350 
*Indicates that the amount paid or refunded did not exceed the applicable disclosure threshold for the periods presented and is included in other U.S. states.
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,
 202520242023
Amount RateAmountRateAmountRate
 (Thousands)(Thousands)(Thousands)
Income before income taxes$2,977,542 $264,194 $2,103,498 
U.S. federal statutory tax rate$625,284 21.0 %$55,481 21.0 %$441,735 21.0 %
State and local income taxes, net of federal benefit (a)95,217 3.2 %35,115 13.3 %(55,993)(2.7)%
Tax credits:
Research and development credits(181)— %(5,779)(2.2)%(4,896)(0.2)%
Other(536)— %(758)(0.3)%180 — %
Changes in valuation allowances:
Capital loss carryforward— — %(52,820)(20.0)%78 — %
Other977 — %818 0.3 %1,301 0.1 %
Nontaxable or nondeductible items:
Transaction costs— — %6,041 2.3 %— — %
Other1,814 0.1 %2,639 1.0 %(2,984)(0.1)%
Changes in unrecognized tax benefits (b)(9,636)(0.3)%(16,977)(6.4)%(7,015)(0.3)%
Other adjustments:
Noncontrolling interests in consolidated subsidiaries(60,156)(2.0)%(2,724)(1.0)%(334)— %
Other(899)— %1,043 0.4 %(3,118)(0.1)%
Total income tax expense and effective tax rate$651,884 21.9 %$22,079 8.4 %$368,954 17.5 %

(a)The majority of the net state and local income tax effect relates to state income taxes in Pennsylvania and West Virginia for all periods presented.
(b)Changes in unrecognized tax benefits are presented on an aggregated basis for all jurisdictions.
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,
 20252024
 (Thousands)
Deferred tax asset:
NOL carryforwards$789,888 $708,518 
Federal tax credits98,813 89,644 
Interest disallowance limitation45,222 106,622 
Incentive compensation and deferred compensation plans26,432 18,032 
State capital loss carryforward22,062 44,496 
Net unrealized losses— 80,723 
Other— 2,433 
Deferred tax asset982,417 1,050,468 
Valuation allowance(254,460)(257,218)
Net deferred tax asset727,957 793,250 
Deferred tax liability:
Property, plant and equipment(2,792,495)(2,516,074)
Investment in partnerships(1,392,717)(1,128,279)
Net unrealized gains(13,070)— 
Other(1,685)— 
Deferred tax liability(4,199,967)(3,644,353)
Net deferred tax liability$(3,472,010)$(2,851,103)
Schedule of Operating Loss Carryforwards
The following table presents the expiration periods of the net operating loss (NOL) carryforward deferred tax assets and associated valuation allowance by jurisdiction.
 December 31,
 20252024
 (Thousands)
NOL carryforwards:
Federal (expires between 2032 and 2037)$14,644 $14,644 
Federal (indefinite expiration)386,846 322,258 
State (expires between 2026 and 2045)354,822 347,279 
State (indefinite expiration)33,576 24,337 
Total NOL carryforwards$789,888 $708,518 
Valuation allowance on NOL carryforwards:
Federal$(13,870)$(14,263)
State(202,472)(187,321)
Total valuation allowance on NOL carryforwards$(216,342)$(201,584)
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.
 202520242023
 (Thousands)
Balance at January 1$72,743 $89,197 $204,035 
Additions for tax positions taken in current year8,291 11,720 11,986 
(Reductions) additions for tax positions taken in prior years(6,131)15,177 (883)
Reductions for tax positions settled with tax authorities— (29,645)(125,941)
Reductions for lapse in statute of limitations(14,574)(13,706)— 
Balance at December 31$60,329 $72,743 $89,197 
Schedule of Uncertain tax Positions
The following table presents specific line items that were included in the reserve for uncertain tax positions.
December 31,
202520242023
(Thousands)
If recognized, effect to the effective tax rate$57,350 $67,105 $83,669 
Reduction of related deferred tax asset for general business credit carryforwards and NOLs50,612 60,415 77,013 
v3.25.4
Debt (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Schedule of Long-Term Debt Instruments
The table below summarizes the Company's outstanding debt.
December 31, 2025December 31, 2024
 Principal ValueCarrying Value (a)Fair Value (b)Principal ValueCarrying Value (a)Fair Value (b)
 (Thousands)
EQT's revolving credit facility maturing July 23, 2030
$75,000 $75,000 $75,000 $150,000 $150,000 $150,000 
Eureka's revolving credit facility maturing November 13, 2027
285,000 285,000 285,000 320,800 320,800 320,800 
Senior notes and debentures:
EQT's 3.125% notes due May 15, 2026
392,915 392,409 391,037 392,915 391,193 382,994 
EQT's 7.75% debentures due July 15, 2026
115,000 114,710 117,315 115,000 114,213 119,590 
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 6.500% notes due July 1, 2027
344,921 346,255 352,902 — — — 
EQT's 3.900% notes due October 1, 2027
936,158 934,640 932,282 1,169,503 1,166,523 1,137,248 
EQT's 5.700% notes due April 1, 2028
500,000 494,905 516,035 500,000 492,640 508,695 
EQM's 5.500% notes due July 15, 2028
— — — 118,683 118,204 117,382 
EQT's 5.500% notes due July 15, 2028
45,225 45,060 46,099 — — — 
EQT's 5.00% notes due January 15, 2029
318,494 316,448 322,902 318,494 315,785 314,357 
EQM's 4.50% notes due January 15, 2029
— — — 742,923 711,754 711,297 
EQT's 4.50% notes due January 15, 2029
734,583 710,802 736,603 — — — 
EQM's 6.375% notes due April 1, 2029
— — — 600,000 608,667 606,774 
EQT's 6.375% notes due April 1, 2029
596,725 602,840 618,076 — — — 
EQT's 7.000% notes due February 1, 2030 (c)
674,800 672,263 733,676 674,800 671,641 718,358 
EQM's 7.500% notes due June 1, 2030
— — — 500,000 535,671 534,950 
EQT's 7.500% notes due June 1, 2030
494,086 522,749 544,162 — — — 
EQM's 4.75% notes due January 15, 2031
— — — 1,100,000 1,045,219 1,039,995 
EQT's 4.75% notes due January 15, 2031
1,090,218 1,044,098 1,098,329 — — — 
EQT's 3.625% notes due May 15, 2031
435,165 431,496 409,651 435,165 430,818 388,111 
EQT's 5.750% notes due February 1, 2034
750,000 743,589 784,500 750,000 742,796 744,743 
EQM's 6.500% notes due July 15, 2048
— — — 80,233 81,338 81,932 
EQT's 6.500% notes due July 15, 2048
67,196 68,064 68,722 — — — 
Total debt7,855,486 7,800,328 8,032,291 9,368,516 9,324,177 9,299,525 
Less: Current portion of debt (d)507,915 507,119 508,352 320,800 320,800 320,800 
Long-term debt$7,347,571 $7,293,209 $7,523,939 $9,047,716 $9,003,377 $8,978,725 
 
(a)For EQT's and Eureka's revolving credit facilities, the principal value represents carrying value. For all other debt, the principal value less unamortized debt issuance costs, debt discounts and fair value adjustments recorded with the Equitrans Midstream Merger purchase price accounting, as applicable, represents carrying value.
(b)For EQT's and Eureka's revolving credit facilities, the carrying value approximates fair value as their interest rates are based on prevailing market rates; therefore, the Company considers the fair value of EQT's and Eureka's revolving credit facilities to be Level 1 fair value measurements. 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. For all other senior notes, interest rates do not fluctuate.
(d)As of December 31, 2025, the current portion of debt included EQT's 3.125% senior notes and 7.75% debentures. As of December 31, 2024, the current portion of debt included borrowings outstanding under Eureka's revolving credit facility.
Schedule of Debt Redeemed or Repurchased The Company repaid, redeemed or repurchased the following debt during the year ended December 31, 2025.
Debt TranchePrincipalPremiums Paid/(Discounts Received)Accrued But Unpaid InterestTotal Cost
(Thousands)
EQM's 6.500% notes due July 1, 2027 (a) (c)
$555,077 $14,590 $6,754 $576,421 
EQT's 3.900% notes due October 1, 2027 (a)
233,345 (2,842)4,070 234,573 
EQM's 5.500% notes due July 15, 2028 (b)
73,456 2,878 1,190 77,524 
EQM's 7.500% notes due June 1, 2027 (c)
4,069 76 51 4,196 
EQM's 4.50% notes due January 15, 2029 (c)
8,338 27 17 8,382 
EQM's 6.375% notes due April 1, 2029 (c)
3,265 135 70 3,470 
EQM's 7.500% notes due June 1, 2030 (c)
5,536 666 69 6,271 
EQM's 4.75% notes due January 15, 2031 (c)
9,616 117 20 9,753 
EQM's 6.500% notes due July 15, 2048 (c)
12,989 1,738 37 14,764 
EQT's 7.500% notes due June 1, 2027 (d)
495,925 9,299 2,996 508,220 
Total$1,401,616 $26,684 $15,274 $1,443,574 

(a)On February 24, 2025, the Company announced the commencement of tender offers (the Tender Offers) to purchase all of EQM's outstanding 6.500% senior notes and a specified amount of EQT's outstanding 3.900% senior notes. On March 12, 2025, the Company settled the Tender Offers and repurchased $506.2 million aggregate principal amount of EQM's 6.500% senior notes and $233.3 million aggregate principal amount of EQT's 3.900% senior notes. In addition to call premiums paid (discounts received), the Company paid $2.7 million in fees to dealer managers and other non-lender parties in connection with the Tender Offers.
(b)On April 16, 2025, EQM issued a notice of full redemption to holders of its outstanding 5.500% senior notes, and, on May 1, 2025, EQM redeemed such notes in full.
(c)On July 16, 2025, EQM issued notices of full redemption to holders of each outstanding series of its senior notes, and, on July 31, 2025, EQM redeemed such notes in full. The redeemed notes had an aggregate principal amount of approximately $92.7 million, and, following these redemptions, EQM has no outstanding senior notes.
(d)On December 19, 2025, EQT issued a notice of full redemption to holders of its outstanding 7.500% senior notes, and, on December 30, 2025, EQT redeemed such notes in full.
v3.25.4
Investments in Unconsolidated Entities (Tables)
 12 Months Ended
Dec. 31, 2025
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, 2025December 31, 2024
Ownership InterestCarrying ValueOwnership InterestCarrying Value
(Thousands)(Thousands)
MVP Joint Venture (a):
MVP A49.3 %$3,097,754 49.3 %$3,469,438 
MVP B
47.2 %42,420 47.2 %65,292 
MVP C
49.3 %374,629 — %— 
Total MVP Joint Venture3,514,803 3,534,730 
Laurel Mountain Midstream, LLC (b)31.0 %47,037 31.0 %28,757 
Other35,724 20,668 
Total$3,597,564 $3,584,155 

(a)Mountain Valley Pipeline, LLC (the MVP Joint Venture) is a Delaware series limited liability company formed as a joint venture for the purpose of constructing and owning natural gas assets. The MVP Joint Venture has three series, as follows (with each term defined below): MVP A, which owns MVP Mainline; MVP B, which owns MVP Southgate; and MVP C, which owns certain assets associated with MVP Boost. A wholly owned subsidiary of the Company serves as the operator for each series of the MVP Joint Venture.
(b)Laurel Mountain Midstream, LLC (LMM) is a midstream company formed as a joint venture among the Company, Williams Companies Inc. and certain other energy companies for the purpose of owning and operating gathering and processing assets.
For the year ended December 31, 2025, the Company's ownership interest in MVP A 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 MVP A.
 Year Ended December 31, 2025July 22, 2024 to
December 31, 2024
(Thousands)
Operating revenues$565,312 $247,360 
Operating income270,095 126,202 
Net income275,419 129,773 
December 31,
20252024
(Thousands)
Current assets$129,883 $204,028 
Noncurrent assets9,419,089 9,535,975 
Total assets$9,548,972 $9,740,003 
Current liabilities$24,218 $69,303 
Noncurrent liabilities4,629 1,514 
Total liabilities28,847 70,817 
Members' equity9,520,125 9,669,186 
Total liabilities and members' equity$9,548,972 $9,740,003 
v3.25.4
Common Stock and Income Per Share (Tables)
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
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,
202520242023
(Thousands, except per share amounts)
Net income attributable to EQT Corporation – Basic income available to shareholders$2,039,247 $230,577 $1,735,232 
Add back: Interest expense on Convertible Notes, net of tax— 86 7,551 
Diluted income available to shareholders$2,039,247 $230,663 $1,742,783 
Weighted average common stock outstanding – Basic611,571 509,597 380,902 
Options, restricted stock, performance awards and stock appreciation rights
4,146 4,625 5,232 
Convertible Notes— 371 27,090 
Weighted average common stock outstanding – Diluted615,717 514,593 413,224 
Income per share of common stock attributable to EQT Corporation:
Basic$3.33 $0.45 $4.56 
Diluted$3.31 $0.45 $4.22 
v3.25.4
Acquisitions (Tables)
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
Business Combination, Recognized Asset Acquired and Liability Assumed The table below summarizes the final purchase price and estimated fair values of the assets acquired and liabilities assumed as of July 1, 2025. No goodwill was recognized for the transaction.
Purchase Price Allocation
(Thousands)
Consideration:
Equity$1,471,365 
Cash473,360 
Total consideration$1,944,725 
Fair value of assets acquired:
Derivative instruments, at fair value$13,188 
Prepaid expenses and other18 
Property, plant and equipment2,019,892 
Amount attributable to assets acquired$2,033,098 
Fair value of liabilities assumed:
Accounts payable$3,082 
Derivative instruments, at fair value66,711 
Other current liabilities3,657 
Asset retirement obligations and other liabilities14,923 
Amount attributable to liabilities assumed$88,373 
Schedule of Allocation of Purchase Price The table below summarizes amounts contributed by the assets acquired in the Olympus Energy Acquisition to the Company's consolidated results of operation subsequent to the completion of the Olympus Energy Acquisition.
July 1, 2025 through December 31, 2025
(Thousands)
Sales of natural gas, natural gas liquids and oil$235,388 
Gain on derivatives31,257 
Pipeline and other4,559 
Total operating revenues$271,204 
Net income attributable to EQT Corporation (a)$108,117 

(a)Net income attributable to EQT Corporation includes $29.1 million of transaction costs related to the Olympus Energy Acquisition recognized during the year ended December 31, 2025.
v3.25.4
Share-Based Compensation Plans (Tables)
 12 Months Ended
Dec. 31, 2025
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,
 202520242023
 (Thousands)
Incentive Performance Share Unit Programs$14,505 $20,919 $23,915 
Restricted stock awards41,310 25,473 20,119 
Stock appreciation rights— — 4,056 
Other programs, including non-employee director awards3,784 3,596 3,110 
Total share-based compensation expense (a)$59,599 $49,988 $51,200 
         
(a)For the years ended December 31, 2025, 2024 and 2023, share-based compensation expense of $2.7 million, $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.
Schedule of Award Types
Incentive PSU Programs – Equity SettledNonvested SharesWeighted Average
Fair Value		Aggregate Fair Value
Outstanding at January 1, 2023
2,861,990 $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 
Granted in Period377,570 74.14 27,993,040 
Granted from Multiplier649,020 75.32 48,884,186 
Vested(1,213,385)75.32 (91,392,158)
Forfeited(66,009)54.23 (3,579,668)
Outstanding at December 31, 2025
1,039,547 $25.93 $26,959,680 
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,
202520242023 (a)20222021 (a)
Risk-free rate4.22%4.35%4.16%1.52%0.18%
Volatility factor43.15%48.82%59.31%65.38%72.50%
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.
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 2025, 2024 and 2023.
 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 
Summary of Restricted Stock Awards Activity
The following table summarizes restricted stock unit equity award activity as of December 31, 2025.
Restricted Stock – Equity SettledNonvested SharesWeighted Average
Fair Value		Aggregate Fair Value
Outstanding at January 1, 2023
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 awards (a)5,175,814 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 
Granted1,720,700 52.80 90,858,021 
Vested(1,458,200)31.22 (45,519,859)
Forfeited(140,937)35.00 (4,933,212)
Outstanding at December 31, 2025
3,545,732 $43.58 $154,509,335 

(a)In conjunction with the Equitrans Midstream Merger, the Company assumed all outstanding and unvested share-based compensation awards of Equitrans Midstream and converted those awards into restricted stock equity awards.
Summary of Option Activity
The following table summarizes option activity as of December 31, 2025.
Non-Qualified Stock OptionsSharesWeighted Average
Exercise Price		Weighted Average
Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 20251,195,336 $12.14 
Exercised(95,874)23.93 
Outstanding and Exercisable at December 31, 20251,099,462 $11.11 1.3 years$46,713,420 
v3.25.4
Leases (Tables)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Schedule of Lease Cost
The following table summarizes the Company's lease costs.
Years Ended December 31,
202520242023
(Thousands)
Operating lease costs$43,002 $41,991 $26,755 
Finance lease costs9,585 5,546 2,414 
Variable and short-term lease costs38,935 33,475 24,151 
Total lease costs (a)$91,522 $81,012 $53,320 

(a)Includes drilling rig lease costs capitalized to property, plant and equipment of $47.9 million, $50.5 million and $40.8 million, respectively, of which $30.8 million, $33.1 million and $24.5 million, respectively, were operating lease costs for the years ended December 31, 2025, 2024 and 2023.

The following table summarizes the cash paid for operating and financing lease liabilities reported in the Statements of Consolidated Cash Flows. Cash paid for operating lease liabilities is presented in other items, net as a cash flow from operating activity, and cash paid for finance lease liabilities is presented in other financing activities as a cash flow from financing activity.
Years Ended December 31,
202520242023
(Thousands)
Operating lease liabilities$21,155 $13,595 $10,078 
Finance lease liabilities6,347 4,232 2,305 
Schedule of Balance Sheet Information The following table summarizes the Company's right-of-use assets and lease liabilities.
December 31,
20252024
(Thousands)
Right-of-Use Assets
Operating$74,111 $60,496 
Finance35,650 34,803 
Total right-of-use assets$109,761 $95,299 
Lease Liabilities
Current lease liabilities
Operating$51,042 $36,275 
Finance7,082 5,603 
Total current lease liabilities58,124 41,878 
Noncurrent lease liabilities
Operating27,369 29,391 
Finance29,973 29,263 
Total noncurrent lease liabilities57,342 58,654 
Total lease liabilities$115,466 $100,532 
Summary of Lease Payment Obligations
The following table summarizes the Company's lease payment obligations as of December 31, 2025.
Operating Lease
Finance Lease
Total Lease
(Thousands)
2026$53,639 $8,722 $62,361 
202710,859 8,355 19,214 
20287,915 7,058 14,973 
20295,972 5,879 11,851 
20304,885 4,697 9,582 
Thereafter350 7,705 8,055 
Total lease payment obligations83,620 42,416 126,036 
Less: Imputed interest5,209 5,361 10,570 
Present value of lease liabilities$78,411 $37,055 $115,466 
v3.25.4
Natural Gas Producing Activities (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2025
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,
 20252024
 (Thousands)
Capitalized costs
Proved properties$35,129,865 $31,986,473 
Unproved properties1,656,045 1,563,440 
Total capitalized costs36,785,910 33,549,913 
Less: Accumulated depreciation and depletion14,344,974 12,489,317 
Net capitalized costs$22,440,936 $21,060,596 
Years Ended December 31,
202520242023
(Thousands)
Costs incurred (a)
Property acquisition:   
Proved properties (b)$1,522,869 $410,805 $4,142,621 
Unproved properties (c)390,103 98,007 575,130 
Exploration3,601 2,735 3,330 
Development1,725,438 1,848,000 1,782,428 

(a)Amounts for all years presented exclude costs related to facilities, information technology and other corporate items. Amounts for 2025 and 2024 exclude costs related to midstream assets, while amounts for 2023 include such costs.
(b)Amounts in 2025 include $1,234.5 million and $288.4 million for wells and leases, respectively, acquired in the Olympus Energy Acquisition. 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. 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.
(c)Amounts in 2025 include $235.5 million for unproved properties acquired in the Olympus Energy Acquisition. Amounts in 2024 include $10.8 million for unproved properties received as consideration for the First NEPA Non-Operated Asset Divestiture. Amounts in 2023 include $523.0 million for unproved properties acquired in the Tug Hill and XcL Midstream Acquisition.
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,
202520242023
(Thousands)
Sales of natural gas, NGLs and oil$7,726,712 $4,934,366 $5,044,768 
Transportation and processing1,532,090 1,915,616 2,157,260 
Production388,696 377,007 254,700 
Operating and maintenance23,013 37,951 — 
Exploration3,601 2,735 3,330 
Depreciation and depletion2,263,105 2,016,670 1,732,142 
(Gain) loss on sale/exchange of long-lived assets(31,513)(764,431)17,445 
Impairment and expiration of leases50,341 97,368 109,421 
Income tax expense851,939 316,377 187,463 
Results of operations from producing activities, excluding corporate overhead$2,645,440 $935,073 $583,007 
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,
 202520242023
 (MMcfe)
Natural gas, NGLs and oil   
Proved developed and undeveloped reserves:   
Balance at January 126,264,669 27,596,694 25,002,589 
Revision of previous estimates(27,073)(1,079,677)(1,402,039)
Purchase of hydrocarbons in place1,768,560 413,040 2,600,667 
Sale of hydrocarbons in place(22,027)(1,562,849)— 
Extensions, discoveries and other additions2,444,717 3,125,620 3,411,750 
Production(2,382,367)(2,228,159)(2,016,273)
Balance at December 3128,046,479 26,264,669 27,596,694 
Proved developed reserves:
Balance at January 118,804,929 19,558,176 17,513,645 
Balance at December 3120,580,992 18,804,929 19,558,176 
Proved undeveloped reserves:
Balance at January 17,459,740 8,038,518 7,488,944 
Balance at December 317,465,487 7,459,740 8,038,518 
 Years Ended December 31,
 202520242023
 (MMcf)
Natural gas   
Proved developed and undeveloped reserves:   
Balance at January 124,545,229 25,795,134 23,824,887 
Revision of previous estimates(15,493)(917,676)(1,461,305)
Purchase of natural gas in place1,768,120 395,423 2,012,159 
Sale of natural gas in place(16,145)(1,562,849)— 
Extensions, discoveries and other additions2,373,231 2,921,638 3,326,736 
Production(2,238,652)(2,086,441)(1,907,343)
Balance at December 3126,416,290 24,545,229 25,795,134 
Proved developed reserves:   
Balance at January 117,440,191 18,186,432 16,541,017 
Balance at December 3119,237,547 17,440,191 18,186,432 
Proved undeveloped reserves:
Balance at January 17,105,038 7,608,702 7,283,870 
Balance at December 317,178,743 7,105,038 7,608,702 

 Years Ended December 31,
202520242023
(Mbbl)
NGLs   
Proved developed and undeveloped reserves:   
Balance at January 1271,908 285,345 186,141 
Revision of previous estimates750 (24,332)11,558 
Purchase of NGLs in place73 2,529 90,604 
Sale of NGLs in place(902)— — 
Extensions, discoveries and other additions10,317 30,391 13,592 
Production(22,168)(22,025)(16,550)
Balance at December 31259,978 271,908 285,345 
Proved developed reserves:  
Balance at January 1217,786 218,523 154,921 
Balance at December 31215,302 217,786 218,523 
Proved undeveloped reserves:
Balance at January 154,122 66,822 31,220 
Balance at December 3144,676 54,122 66,822 
 Years Ended December 31,
 202520242023
 (Mbbl)
Oil   
Proved developed and undeveloped reserves:   
Balance at January 114,664 14,915 10,142 
Revision of previous estimates(2,680)(2,669)(1,680)
Purchase of oil in place— 407 7,481 
Sale of oil in place(78)— — 
Extensions, discoveries and other additions1,598 3,606 577 
Production(1,784)(1,595)(1,605)
Balance at December 3111,720 14,664 14,915 
Proved developed reserves:   
Balance at January 19,669 10,101 7,183 
Balance at December 318,605 9,669 10,101 
Proved undeveloped reserves:
Balance at January 14,995 4,814 2,959 
Balance at December 313,115 4,995 4,814 
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,
 202520242023
 (Thousands)
Future cash inflows (a)$80,216,863 $44,871,509 $52,916,665 
Future production costs (b)(21,496,216)(18,979,056)(24,357,033)
Future development costs(4,456,051)(4,352,890)(4,298,372)
Future income tax expenses(11,001,125)(4,445,354)(5,230,629)
Future net cash flows43,263,471 17,094,209 19,030,631 
10% annual discount for estimated timing of cash flows
(21,953,285)(9,095,069)(9,768,282)
Standardized measure of discounted future net cash flows$21,310,186 $7,999,140 $9,262,349 

(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 differentials. Regional differentials 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,
202520242023
Natural gas for NYMEX ($/MMBtu)$3.387 $2.130 $2.637 
Less: Regional differentials ($/MMBtu)0.786 0.741 1.029 
Natural gas price ($/Mcf)2.749 1.468 1.700 
NGLs price ($/Bbl)26.97 29.28 28.44 
Oil for West Texas Intermediate (WTI) ($/Bbl)66.01 76.32 78.21 
Less: Regional differentials ($/Bbl)15.29 16.87 14.35 
Oil price ($/Bbl)50.72 59.45 63.86 

(b)Includes approximately $2,629 million, $2,553 million and $2,443 million for future plugging and abandonment costs as of December 31, 2025, 2024 and 2023, respectively.
Schedule of Changes in The Standardized Measure of Discounted Net Cash Flows From Natural Gas and Oil Reserves
The following table summarizes the changes in the standardized measure of discounted future net cash flows.
Years Ended December 31,
 202520242023
 (Thousands)
Net sales and transfers of natural gas and oil produced$(5,782,913)$(2,603,792)$(2,632,808)
Net changes in prices, production and development costs16,980,282 (1,237,271)(48,739,248)
Extensions, discoveries and improved recovery, net of related costs292,028 464,496 6,347,387 
Development costs incurred1,281,816 1,432,315 1,296,380 
Net purchase of minerals in place1,874,429 269,453 2,131,567 
Net sale of minerals in place(3,053)(692,019)— 
Revision of previous estimates135,348 (263,191)(2,768,922)
Accretion of discount799,914 926,235 4,006,452 
Net change in income taxes(2,438,815)411,999 9,190,460 
Timing and other172,010 28,566 366,557 
Net increase (decrease)13,311,046 (1,263,209)(30,802,175)
Balance at January 17,999,140 9,262,349 40,064,524 
Balance at December 31$21,310,186 $7,999,140 $9,262,349 

Following the completion of the Equitrans Midstream Merger as described in Note 11, 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 9, 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.
v3.25.4
Summary of Significant Accounting Policies - Narrative (Details)
 5 Months Ended 7 Months Ended 12 Months Ended
Dec. 31, 2024
USD ($)
segment
Jul. 21, 2024
segment
Dec. 31, 2025
USD ($)
$ / MBoe
segment
business
well
Dec. 31, 2024
USD ($)
$ / MBoe
well
Dec. 31, 2023
USD ($)
$ / MBoe
well
May 31, 2024
Property, Plant and Equipment [Line Items]            
Number of segments | segment 3 1 3      
Number of operating segments | segment   1 3      
Number of lines of business | business     3      
Internal costs $ 69,000,000   $ 82,000,000 $ 69,000,000 $ 57,000,000  
Interest costs capitalized     $ 32,000,000 $ 54,000,000 $ 41,000,000  
Overall average rate of depletion (in dollars per Mcfe) | $ / MBoe     0.95 0.90 0.84  
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   $ 36,785,910,000 $ 33,549,913,000    
Depreciation rate percentage     2.80% 3.10%    
Impairment and expiration of leases     $ 51,152,000 $ 97,368,000 109,421,000  
Property, plant and equipment 44,505,504,000   48,472,497,000 44,505,504,000    
Amortization of intangible assets     13,300,000 5,900,000    
2026     13,300,000      
2027     13,300,000      
2028     13,300,000      
2029     13,300,000      
2030     13,300,000      
Impairment of intangible assets     $ 0 0    
Largest amount of benefit threshold, percentage (no greater than)     50.00%      
Expense recognized related to defined contribution plan     $ 25,100,000 14,500,000 $ 9,000,000.0  
Gathering            
Property, Plant and Equipment [Line Items]            
Interest costs capitalized     8,000,000 3,000,000    
Oil and gas producing properties 25,000,000   35,000,000 25,000,000    
Transmission            
Property, Plant and Equipment [Line Items]            
Oil and gas producing properties 4,000,000   15,000,000 4,000,000    
Unproved Property            
Property, Plant and Equipment [Line Items]            
Property, plant and equipment $ 1,563,000,000   $ 1,656,000,000 $ 1,563,000,000    
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%      
v3.25.4
Summary of Significant Accounting Policies - Summary of Prepaid Expenses and Other Current Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Accounting Policies [Abstract]    
Margin requirements with counterparties (see Note $4) $ 36,810 $ 86,975
Prepaid expenses and other current assets 59,441 52,044
Total prepaid expenses and other $ 96,251 $ 139,019
v3.25.4
Summary of Significant Accounting Policies - Schedule of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Property, Plant and Equipment [Line Items]    
Oil and gas producing properties $ 36,785,910 $ 33,549,913
Less: Accumulated depletion 14,344,974 12,489,317
Net oil and gas producing properties 22,440,936 21,060,596
Net property, plant and equipment 33,557,808 31,747,818
Property, plant and equipment 48,472,497 44,505,504
Less: Accumulated depreciation and depletion 14,914,689 12,757,686
Gathering    
Property, Plant and Equipment [Line Items]    
Oil and gas producing properties 35,000 25,000
Transmission    
Property, Plant and Equipment [Line Items]    
Oil and gas producing properties 15,000 4,000
Operating Segments | Upstream    
Property, Plant and Equipment [Line Items]    
Oil and gas producing properties 36,785,910 33,549,913
Less: Accumulated depletion 14,344,974 12,489,317
Net oil and gas producing properties 22,440,936 21,060,596
Other property, plant and equipment, at cost less accumulated depreciation 27,073 20,434
Net property, plant and equipment 22,468,009 21,081,030
Operating Segments | Gathering    
Property, Plant and Equipment [Line Items]    
Net property, plant and equipment 8,339,122 7,936,010
Property, plant and equipment 8,677,011 8,067,556
Less: Accumulated depreciation and depletion 337,889 131,546
Operating Segments | Transmission    
Property, Plant and Equipment [Line Items]    
Net property, plant and equipment 2,641,276 2,637,325
Property, plant and equipment 2,751,815 2,667,352
Less: Accumulated depreciation and depletion 110,539 30,027
Intersegment Eliminations and Other    
Property, Plant and Equipment [Line Items]    
Other property, plant and equipment, at cost less accumulated depreciation $ 109,401 $ 93,453
v3.25.4
Summary of Significant Accounting Policies - Schedule of Intangible Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Finite-Lived Intangible Assets [Line Items]    
Net intangible assets related to acquired transmission services agreements $ 200,486 $ 215,257
Acquired transmission services agreements    
Finite-Lived Intangible Assets [Line Items]    
Acquired transmission services agreements 200,000 200,000
Less: Accumulated amortization 19,234 5,901
Net intangible assets related to acquired transmission services agreements 180,766 194,099
Other intangible assets    
Finite-Lived Intangible Assets [Line Items]    
Acquired transmission services agreements 24,922 24,922
Less: Accumulated amortization 5,202 3,764
Net intangible assets related to acquired transmission services agreements $ 19,720 $ 21,158
v3.25.4
Summary of Significant Accounting Policies - Other Current Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Other Current Liabilities:    
Accrued taxes other than income $ 108,626 $ 114,700
Accrued incentive compensation 90,694 53,138
Total current lease liabilities 58,124 41,878
Current portion of long-term capacity contracts 30,903 43,697
Accrued payroll 9,313 12,115
Deferred revenue 6,240 24,187
Other accrued liabilities 31,587 59,702
Total other current liabilities $ 335,487 $ 349,417
v3.25.4
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Asset retirement obligations    
Asset retirement obligation as of beginning of period $ 1,003,570 $ 911,057
Accretion expense 76,745 68,501
Liabilities incurred 31,394 21,587
Liabilities settled (52,210) (66,729)
Liabilities assumed in acquisitions 14,923 45,847
Liabilities removed in divestitures (98,839) (28,701)
Change in estimates 43,922 52,008
Asset retirement obligation as of end of period $ 1,019,505 $ 1,003,570
v3.25.4
Summary of Significant Accounting Policies - Schedule of Regulated Operating Revenues, Expenses, Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
New Accounting Pronouncements or Change in Accounting Principle [Line Items]    
Property, plant and equipment $ 48,472,497 $ 44,505,504
Less: Accumulated depreciation and depletion 14,914,689 12,757,686
Net property, plant and equipment 33,557,808 31,747,818
Equitrans LP    
New Accounting Pronouncements or Change in Accounting Principle [Line Items]    
Operating revenues 572,975 218,569
Operating expenses 194,576 78,908
Property, plant and equipment 2,751,815 2,667,352
Less: Accumulated depreciation and depletion 110,539 30,027
Net property, plant and equipment $ 2,641,276 $ 2,637,325
v3.25.4
Summary of Significant Accounting Policies - Schedule of Regulatory Assets and Liabilities (Details) - Equitrans LP - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Regulated assets:    
Total regulated assets $ 157,159 $ 165,939
Regulated liabilities:    
Total regulated liabilities 31,335 28,692
Deferred taxes    
Regulated liabilities:    
Total regulated liabilities 8,136 8,534
On-going post-retirement benefits other than pension and other reimbursable costs    
Regulated liabilities:    
Total regulated liabilities 23,199 20,158
Deferred taxes    
Regulated assets:    
Total regulated assets 139,221 142,757
Other recoverable costs    
Regulated assets:    
Total regulated assets $ 17,938 $ 23,182
Asset retirement obligations    
Regulated liabilities:    
Remaining recovery period 8 years 6 months  
On-going post-retirement benefits other than pension and other reimbursable costs    
Regulated liabilities:    
Remaining recovery period 6 years 6 months  
v3.25.4
Summary of Significant Accounting Policies - Other Operating Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Accounting Policies [Abstract]      
Changes in legal and environmental reserves, including settlements $ 185,253 $ 16,271 $ 9,342
Transaction costs 35,843 309,419 56,263
Other 23,584 24,174 18,438
Total other operating expenses $ 244,680 $ 349,864 $ 84,043
v3.25.4
Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash paid (received) during the year for:      
Interest, net of amount capitalized $ 455,091 $ 401,768 $ 213,141
Income taxes, net (79,022) 7,960 13,350
Non-cash activity during the period for:      
Issuance of EQT common stock as consideration for acquisition (Note 11) 1,471,365 5,548,608 2,152,631
Increase in asset retirement costs and obligations 75,390 73,576 106,548
Increase in right-of-use assets and lease liabilities, net 65,323 29,568 45,774
Capitalization of non-cash equity share-based compensation 20,258 10,095 6,287
Investments in unconsolidated entities 17,981 3,428 0
Issuance of EQT common stock upon Convertible Notes settlement (Note 7) 0 285,608 122,830
First NEPA Non-Operated Asset Divestiture (Note 12) 0 155,318 0
Accrued transaction costs related to the sale of units of the Midstream Joint Venture (Note 9) 0 1,135 0
Dissolution of consolidated variable interest entity $ 0 $ 0 $ 25,227
v3.25.4
Financial Information by Business Segment - Narrative (Details) - segment
 5 Months Ended 7 Months Ended 12 Months Ended
Dec. 31, 2024
Jul. 21, 2024
Dec. 31, 2025
Segment Reporting [Abstract]      
Number of segments 3 1 3
Number of operating segments   1 3
v3.25.4
Financial Information by Business Segment - Schedule Of Financial Information By Business Segment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating revenues:      
Gain (loss) on derivatives $ 290,994 $ 51,117 $ 1,838,941
Total operating revenues 8,644,211 5,273,309 6,908,923
Operating expenses:      
Transportation and processing 1,532,090 1,915,616 2,157,260
Production 388,696 377,007 239,001
Operating and maintenance 225,131 110,393 15,699
Exploration 3,601 2,735 3,330
Selling, general and administrative 380,066 336,724 236,171
Depreciation, depletion and amortization 2,600,390 2,162,350 1,732,142
(Gain) loss on sale/exchange of long-lived assets (31,214) (764,044) 17,445
Impairment and expiration of leases 51,152 97,368 109,421
Other operating expenses 244,680 349,864 84,043
Total operating expenses 5,394,592 4,588,013 4,594,512
Operating income 3,249,619 685,296 2,314,411
Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
Pipeline and other      
Operating revenues:      
Pipeline and other 626,505 287,826 25,214
Operating Segments      
Operating revenues:      
Gain (loss) on derivatives 290,994 51,117 1,838,941
Total operating revenues 9,897,743 5,977,826 7,057,753
Operating expenses:      
Transportation and processing 2,783,455 2,619,710 2,306,090
Production 388,696 377,007 239,001
Operating and maintenance 225,131 110,393 15,699
Exploration 3,601 2,735 3,330
Selling, general and administrative 321,784 300,470 236,171
Depreciation, depletion and amortization 2,577,176 2,145,589 1,722,377
(Gain) loss on sale/exchange of long-lived assets (31,193) (764,044) 17,445
Impairment and expiration of leases 51,152 97,368 109,421
Other operating expenses 47,924 12,696 9,177
Total operating expenses 6,367,726 4,901,924 4,658,711
Operating income 3,530,017 1,075,902 2,399,042
Operating Segments | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
Operating Segments | Pipeline and other      
Operating revenues:      
Pipeline and other 1,880,037 992,343 174,044
Intersegment Eliminations and Other      
Operating revenues:      
Gain (loss) on derivatives 0 0 0
Total operating revenues (1,253,532) (704,517) (148,830)
Operating expenses:      
Transportation and processing (1,251,365) (704,094) (148,830)
Production 0 0 0
Operating and maintenance 0 0 0
Exploration 0 0 0
Selling, general and administrative 58,282 36,254 0
Depreciation, depletion and amortization 23,214 16,761 9,765
(Gain) loss on sale/exchange of long-lived assets (21) 0 0
Impairment and expiration of leases 0 0 0
Other operating expenses 196,756 337,168 74,866
Total operating expenses (973,134) (313,911) (64,199)
Operating income (280,398) (390,606) (84,631)
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 and other      
Operating revenues:      
Pipeline and other (1,253,532) (704,517) (148,830)
Upstream | Operating Segments      
Operating revenues:      
Gain (loss) on derivatives 290,994 67,880 1,838,941
Total operating revenues 8,024,057 5,009,833 6,896,358
Operating expenses:      
Transportation and processing 2,783,455 2,619,710 2,306,090
Production 388,696 377,007 239,001
Operating and maintenance 0 0 0
Exploration 3,601 2,735 3,330
Selling, general and administrative 217,803 244,450 236,171
Depreciation, depletion and amortization 2,263,105 2,016,670 1,705,311
(Gain) loss on sale/exchange of long-lived assets (31,513) (764,431) 17,445
Impairment and expiration of leases 50,341 97,368 109,421
Other operating expenses 30,438 12,696 9,177
Total operating expenses 5,705,926 4,606,205 4,625,946
Operating income 2,318,131 403,628 2,270,412
Upstream | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
Upstream | Operating Segments | Pipeline and other      
Operating revenues:      
Pipeline and other 6,351 7,587 12,649
Gathering | Operating Segments      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 1,301,434 766,463 161,395
Gain (loss) on derivatives 0 (16,763) 0
Total operating revenues 1,301,434 749,700 161,395
Operating expenses:      
Transportation and processing 0 0 0
Production 0 0 0
Operating and maintenance 166,990 89,897 15,699
Exploration 0 0 0
Selling, general and administrative 66,642 38,837 0
Depreciation, depletion and amortization 212,353 89,513 17,066
(Gain) loss on sale/exchange of long-lived assets (29) (22) 0
Impairment and expiration of leases 811 0 0
Other operating expenses 18,013 0 0
Total operating expenses 464,780 218,225 32,765
Operating income 836,654 531,475 128,630
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 and other      
Operating revenues:      
Pipeline and other 1,301,434 766,463 161,395
Transmission | Operating Segments      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 572,252 218,293 $ 0
Gain (loss) on derivatives 0 0  
Total operating revenues 572,252 218,293  
Operating expenses:      
Transportation and processing 0 0  
Production 0 0  
Operating and maintenance 58,141 20,496  
Exploration 0 0  
Selling, general and administrative 37,339 17,183  
Depreciation, depletion and amortization 101,718 39,406  
(Gain) loss on sale/exchange of long-lived assets 349 409  
Impairment and expiration of leases 0 0  
Other operating expenses (527) 0  
Total operating expenses 197,020 77,494  
Operating income 375,232 140,799  
Transmission | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Operating revenues:      
Sales of natural gas, natural gas liquids and oil 0 0  
Transmission | Operating Segments | Pipeline and other      
Operating revenues:      
Pipeline and other $ 572,252 $ 218,293  
v3.25.4
Financial Information by Business Segment - Schedule of Segment Operating Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Total segment operating income $ 3,249,619 $ 685,296 $ 2,314,411
Unallocated amounts:      
Corporate selling, general and administrative 380,066 336,724 236,171
(Gain) loss on sale/exchange of long-lived assets (31,214) (764,044) 17,445
Corporate other operating expenses 244,680 349,864 84,043
Income from investments (184,444) (76,039) (7,596)
Other income (4,826) (25,983) (1,231)
Loss on debt extinguishment 22,652 68,299 80
Interest expense, net 438,695 454,825 219,660
Income before income taxes 2,977,542 264,194 2,103,498
MVP Joint Venture | Transmission      
Unallocated amounts:      
Total investments 154,300 78,800  
Operating Segments      
Segment Reporting Information [Line Items]      
Total segment operating income 3,530,017 1,075,902 2,399,042
Unallocated amounts:      
Corporate selling, general and administrative 321,784 300,470 236,171
(Gain) loss on sale/exchange of long-lived assets (31,193) (764,044) 17,445
Corporate other operating expenses 47,924 12,696 9,177
Operating Segments | Transmission      
Segment Reporting Information [Line Items]      
Total segment operating income 375,232 140,799  
Unallocated amounts:      
Corporate selling, general and administrative 37,339 17,183  
(Gain) loss on sale/exchange of long-lived assets 349 409  
Corporate other operating expenses (527) 0  
Intersegment eliminations      
Segment Reporting Information [Line Items]      
Total segment operating income 2,303 457 0
Unallocated amounts      
Segment Reporting Information [Line Items]      
Total segment operating income (280,398) (390,606) (84,631)
Unallocated amounts:      
Unallocated other revenues (136) (34) 0
Corporate selling, general and administrative 58,282 36,254 0
Corporate depreciation and amortization 23,214 16,761 9,765
(Gain) loss on sale/exchange of long-lived assets (21) 0 0
Corporate other operating expenses 196,756 337,168 74,866
Income from investments (184,444) (76,039) (7,596)
Other income (4,826) (25,983) (1,231)
Loss on debt extinguishment 22,652 68,299 80
Interest expense, net $ 438,695 $ 454,825 $ 219,660
v3.25.4
Financial Information by Business Segment - Schedule of Segment Assets (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment assets:      
Investments in unconsolidated entities $ 3,630,577 $ 3,617,397  
Goodwill 2,062,462 2,079,481  
Total assets 41,792,874 39,830,255 $ 25,285,098
Gain (loss) on derivatives 290,994 51,117 1,838,941
Operating revenues 8,644,211 5,273,309 6,908,923
Transportation and processing 1,532,090 1,915,616 2,157,260
Production 388,696 377,007 239,001
Operating and maintenance 225,131 110,393 15,699
Exploration 3,601 2,735 3,330
Selling, general and administrative 380,066 336,724 236,171
Depreciation, depletion and amortization 2,600,390 2,162,350 1,732,142
(Gain) loss on sale/exchange of long-lived assets (31,214) (764,044) 17,445
Impairment and expiration of leases 51,152 97,368 109,421
Other operating expenses 244,680 349,864 84,043
Total operating expenses 5,394,592 4,588,013 4,594,512
Total segment operating income 3,249,619 685,296 2,314,411
Pipeline and other      
Segment assets:      
Pipeline and other 626,505 287,826 25,214
Sales of natural gas, natural gas liquids and oil      
Segment assets:      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
Operating Segments      
Segment assets:      
Investments in unconsolidated entities 3,514,803 3,534,730  
Goodwill 1,231,783 1,217,742  
Other segment assets 35,862,305 33,761,255  
Total assets 40,608,891 38,513,727 25,019,540
Gain (loss) on derivatives 290,994 51,117 1,838,941
Operating revenues 9,897,743 5,977,826 7,057,753
Transportation and processing 2,783,455 2,619,710 2,306,090
Production 388,696 377,007 239,001
Operating and maintenance 225,131 110,393 15,699
Exploration 3,601 2,735 3,330
Selling, general and administrative 321,784 300,470 236,171
Depreciation, depletion and amortization 2,577,176 2,145,589 1,722,377
(Gain) loss on sale/exchange of long-lived assets (31,193) (764,044) 17,445
Impairment and expiration of leases 51,152 97,368 109,421
Other operating expenses 47,924 12,696 9,177
Total operating expenses 6,367,726 4,901,924 4,658,711
Total segment operating income 3,530,017 1,075,902 2,399,042
Operating Segments | Pipeline and other      
Segment assets:      
Pipeline and other 1,880,037 992,343 174,044
Operating Segments | Sales of natural gas, natural gas liquids and oil      
Segment assets:      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
Upstream | Operating Segments      
Segment assets:      
Investments in unconsolidated entities 0 0  
Goodwill 0 0  
Other segment assets 24,295,091 22,546,098  
Total assets 24,295,091 22,546,098 23,803,913
Gain (loss) on derivatives 290,994 67,880 1,838,941
Operating revenues 8,024,057 5,009,833 6,896,358
Transportation and processing 2,783,455 2,619,710 2,306,090
Production 388,696 377,007 239,001
Operating and maintenance 0 0 0
Exploration 3,601 2,735 3,330
Selling, general and administrative 217,803 244,450 236,171
Depreciation, depletion and amortization 2,263,105 2,016,670 1,705,311
(Gain) loss on sale/exchange of long-lived assets (31,513) (764,431) 17,445
Impairment and expiration of leases 50,341 97,368 109,421
Other operating expenses 30,438 12,696 9,177
Total operating expenses 5,705,926 4,606,205 4,625,946
Total segment operating income 2,318,131 403,628 2,270,412
Upstream | Operating Segments | Pipeline and other      
Segment assets:      
Pipeline and other 6,351 7,587 12,649
Upstream | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Segment assets:      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
Gathering | Operating Segments      
Segment assets:      
Investments in unconsolidated entities 0 0  
Goodwill 0 0  
Other segment assets 8,676,118 8,295,625  
Total assets 8,676,118 8,295,625 1,215,627
Sales of natural gas, natural gas liquids and oil 1,301,434 766,463 161,395
Gain (loss) on derivatives 0 (16,763) 0
Operating revenues 1,301,434 749,700 161,395
Transportation and processing 0 0 0
Production 0 0 0
Operating and maintenance 166,990 89,897 15,699
Exploration 0 0 0
Selling, general and administrative 66,642 38,837 0
Depreciation, depletion and amortization 212,353 89,513 17,066
(Gain) loss on sale/exchange of long-lived assets (29) (22) 0
Impairment and expiration of leases 811 0 0
Other operating expenses 18,013 0 0
Total operating expenses 464,780 218,225 32,765
Total segment operating income 836,654 531,475 128,630
Gathering | Operating Segments | Pipeline and other      
Segment assets:      
Pipeline and other 1,301,434 766,463 161,395
Gathering | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Segment assets:      
Sales of natural gas, natural gas liquids and oil 0 0 0
Transmission | Operating Segments      
Segment assets:      
Investments in unconsolidated entities 3,514,803 3,534,730  
Goodwill 1,231,783 1,217,742  
Other segment assets 2,891,096 2,919,532  
Total assets 7,637,682 7,672,004 0
Sales of natural gas, natural gas liquids and oil 572,252 218,293 $ 0
Gain (loss) on derivatives 0 0  
Operating revenues 572,252 218,293  
Transportation and processing 0 0  
Production 0 0  
Operating and maintenance 58,141 20,496  
Exploration 0 0  
Selling, general and administrative 37,339 17,183  
Depreciation, depletion and amortization 101,718 39,406  
(Gain) loss on sale/exchange of long-lived assets 349 409  
Impairment and expiration of leases 0 0  
Other operating expenses (527) 0  
Total operating expenses 197,020 77,494  
Total segment operating income 375,232 140,799  
Transmission | Operating Segments | Pipeline and other      
Segment assets:      
Pipeline and other 572,252 218,293  
Transmission | Operating Segments | Sales of natural gas, natural gas liquids and oil      
Segment assets:      
Sales of natural gas, natural gas liquids and oil $ 0 $ 0  
v3.25.4
Financial Information by Business Segment - Schedule of Segment Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Total assets $ 41,792,874 $ 39,830,255 $ 25,285,098
Cash and cash equivalents 110,795 202,093  
Income tax receivable 27,756 97,378  
Goodwill 2,062,462 2,079,481  
Other assets 446,390 455,623  
Operating Segments      
Segment Reporting Information [Line Items]      
Total assets 40,608,891 38,513,727 25,019,540
Goodwill 1,231,783 1,217,742  
Intersegment eliminations      
Segment Reporting Information [Line Items]      
Total assets (204,403) (318,835) (47,471)
Intersegment Eliminations and Other      
Segment Reporting Information [Line Items]      
Cash and cash equivalents 110,795 202,093 80,977
Income tax receivable 27,756 97,378 91,414
Other property, plant and equipment, at cost less accumulated depreciation 109,401 93,453 40,739
Goodwill 830,679 861,739 0
Regulatory asset from deferred taxes 139,221 142,757 0
Other assets $ 170,534 $ 237,943 $ 99,899
v3.25.4
Financial Information by Business Segment - Schedule of Capital Expenditures By Segment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Expenditures for segment assets:      
Total capital expenditures $ 2,323,637 $ 2,265,948 $ 1,925,243
Operating Segments      
Expenditures for segment assets:      
Total capital expenditures 2,297,518 2,237,345 1,910,118
Operating Segments | Upstream      
Expenditures for segment assets:      
Total capital expenditures 1,878,052 2,003,635 1,878,417
Operating Segments | Gathering      
Expenditures for segment assets:      
Total capital expenditures 367,697 202,264 31,701
Operating Segments | Transmission      
Expenditures for segment assets:      
Total capital expenditures 51,769 31,446 0
Other corporate items      
Expenditures for segment assets:      
Total capital expenditures $ 26,119 $ 28,603 $ 15,125
v3.25.4
Revenue from Contracts with Customers - Narrative (Details)
 12 Months Ended
Dec. 31, 2025
Gathering | Third-party  
Disaggregation of Revenue [Line Items]  
Weighted average remaining term 10 years
Gathering | Affiliate  
Disaggregation of Revenue [Line Items]  
Weighted average remaining term 13 years
Transmission | Third-party  
Disaggregation of Revenue [Line Items]  
Weighted average remaining term 10 years
Transmission | Affiliate  
Disaggregation of Revenue [Line Items]  
Weighted average remaining term 13 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
v3.25.4
Revenue from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]      
Gain (loss) on derivatives $ 290,994 $ 51,117 $ 1,838,941
Total operating revenues 8,644,211 5,273,309 6,908,923
Amounts due from contracts with customers 1,159,000 939,900  
Operating Segments      
Disaggregation of Revenue [Line Items]      
Gain (loss) on derivatives 290,994 51,117 1,838,941
Total operating revenues 9,897,743 5,977,826 7,057,753
Intersegment eliminations      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil (1,253,532) (704,517) (148,830)
Upstream sales | Operating Segments      
Disaggregation of Revenue [Line Items]      
Gain (loss) on derivatives 290,994 67,880 1,838,941
Total operating revenues 8,024,057 5,009,833 6,896,358
Gathering | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 1,301,434 766,463 161,395
Gain (loss) on derivatives 0 (16,763) 0
Total operating revenues 1,301,434 749,700 161,395
Transmission | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 572,252 218,293 0
Gain (loss) on derivatives 0 0  
Total operating revenues 572,252 218,293  
Sales of natural gas, natural gas liquids and oil      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
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 7,726,712 4,934,366 5,044,768
Sales of natural gas, natural gas liquids and oil | Upstream sales | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 7,726,712 4,934,366 5,044,768
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 0  
Natural gas | Upstream sales | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 7,018,766 4,224,882 4,520,817
NGLs | Upstream sales | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 620,384 615,933 427,760
Oil | Upstream sales | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 87,562 93,551 96,191
Revenues From Contract With Customers      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 8,346,866 5,214,605 5,057,333
Other revenues      
Disaggregation of Revenue [Line Items]      
Other revenues 6,351 7,587 12,649
Total other sources of revenue      
Disaggregation of Revenue [Line Items]      
Total other sources of revenue 297,345 58,704 1,851,590
Firm reservation fee revenues | Gathering | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 632,916 313,987 0
Firm reservation fee revenues | Transmission | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 435,194 183,088 0
Firm reservation fee revenues | Gathering revenues supported by MVCs: | Gathering      
Disaggregation of Revenue [Line Items]      
Unbilled revenues 18,400 4,200  
Volumetric-based fee revenues | Gathering | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil 668,518 452,476 161,395
Volumetric-based fee revenues | Transmission | Operating Segments      
Disaggregation of Revenue [Line Items]      
Sales of natural gas, natural gas liquids and oil $ 137,058 $ 35,205 $ 0
v3.25.4
Revenue from Contracts with Customers - Schedule of Remaining Performance Obligations (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 11,371,990
Upstream  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 6,575
Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 2,638,366
Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 4,195,842
Gathering | Third-party  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 732,047
Gathering | Third-party | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 522,443
Gathering | Affiliate  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 1,906,319
Gathering | Affiliate | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 3,673,399
Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 4,531,207
Transmission | Third-party  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 1,529,211
Transmission | Affiliate  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations 3,001,996
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 1,139,943
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Natural gas  
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 | Upstream  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 4,597
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]  
Total remaining performance obligations $ 202,586
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]  
Total remaining performance obligations $ 494,343
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 100,794
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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 96,377
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 101,792
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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 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 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 438,417
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 185,328
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 253,089
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]  
Total remaining performance obligations $ 1,128,873
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Natural gas  
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 | Upstream  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 1,978
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]  
Total remaining performance obligations $ 187,448
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]  
Total remaining performance obligations $ 499,824
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 85,998
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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 89,203
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 101,450
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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 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 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 439,623
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 176,986
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 262,637
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]  
Total remaining performance obligations $ 1,108,565
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Natural gas  
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 | Upstream  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 0
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]  
Total remaining performance obligations $ 183,699
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]  
Total remaining performance obligations $ 492,276
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 85,998
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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 80,536
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 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 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 432,590
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 171,814
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 260,776
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]  
Total remaining performance obligations $ 1,091,275
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Natural gas  
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 | Upstream  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 0
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]  
Total remaining performance obligations $ 183,699
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]  
Total remaining performance obligations $ 477,933
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 85,998
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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 67,311
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 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 | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 410,622
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 429,643
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 169,198
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  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 260,445
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]  
Total remaining performance obligations $ 1,081,190
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Natural gas  
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 | Upstream  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 0
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]  
Total remaining performance obligations $ 189,975
Remaining performance obligation, expected timing of satisfaction, period 1 year
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]  
Total remaining performance obligations $ 465,084
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Third-party  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 85,998
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Third-party | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 56,762
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Affiliate  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 103,977
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Gathering | Affiliate | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 408,322
Remaining performance obligation, expected timing of satisfaction, period 1 year
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]  
Total remaining performance obligations $ 426,131
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Transmission | Third-party  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 165,686
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Transmission | Affiliate  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 260,445
Remaining performance obligation, expected timing of satisfaction, period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 5,822,144
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Natural gas  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Upstream  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Gathering  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 1,690,959
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Gathering | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 1,766,382
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Gathering | Third-party  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 287,261
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Gathering | Third-party | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 132,254
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Gathering | Affiliate  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 1,403,698
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Gathering | Affiliate | Gathering revenues supported by MVCs:  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 1,634,128
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Transmission  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 2,364,803
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Transmission | Third-party  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 660,199
Remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01 | Transmission | Affiliate  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Total remaining performance obligations $ 1,704,604
Remaining performance obligation, expected timing of satisfaction, period
v3.25.4
Derivative Instruments - Narrative (Details)
 12 Months Ended
Dec. 31, 2025
USD ($)
Bcf
Dec. 31, 2024
USD ($)
MBbls
Derivative Instruments, Gain (Loss) [Line Items]    
Maximum additional collateral as percentage of derivative liability (in percent) 100.00%  
Aggregate fair value of derivative instruments with credit-risk related contingencies $ 4,400,000 $ 61,900,000
Collateral posted 0 0
Over-the-Counter    
Derivative Instruments, Gain (Loss) [Line Items]    
Aggregate fair value of derivative instruments with credit-risk related contingencies 0 0
Exchange Traded Natural Gas Contracts    
Derivative Instruments, Gain (Loss) [Line Items]    
Collateral posted $ 36,800,000 $ 87,000,000
Cash Flow Hedging | Natural Gas | Natural Gas    
Derivative Instruments, Gain (Loss) [Line Items]    
Volume of derivative instruments (in Bcf, Mbbls) 945 2,189
Cash Flow Hedging | Natural Gas | Natural Gas Liquids (NGL)    
Derivative Instruments, Gain (Loss) [Line Items]    
Volume of derivative instruments (in Bcf, Mbbls) 4,022 2,562
v3.25.4
Derivative Instruments - Schedule of Impact of Netting Agreements and Margin Deposits on Gross Derivative Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Asset derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet $ 202,390 $ 143,581
Liability derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet 137,299 446,519
Commodity Contract    
Asset derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet 202,390 143,581
Derivative instruments subject to master netting agreements (79,250) (117,350)
Margin requirements with counterparties 0 0
Net derivative instruments 123,140 26,231
Liability derivative instruments, at fair value    
Gross derivative instruments recorded in the Consolidated Balance Sheet 137,299 446,519
Derivative instruments subject to master netting agreements (79,250) (117,350)
Margin requirements with counterparties (36,810) (86,975)
Liability derivative instruments, at fair value $ 21,239 $ 242,194
v3.25.4
Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset derivative instruments, at fair value $ 202,390 $ 143,581
Derivative instruments, at fair value 137,299 446,519
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 43,200 50,300
Derivative instruments, at fair value 39,164 81,074
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 159,190 93,281
Derivative instruments, at fair value 98,135 365,445
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 | Fair value    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset derivative instruments, at fair value 202,390 143,581
Derivative instruments, at fair value $ 137,299 $ 446,519
v3.25.4
Fair Value Measurements - Narrative (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt $ 8,032,291 $ 9,299,525
Senior notes | Carrying value    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt 7,400,000 8,900,000
Senior notes | Significant other observable inputs (Level 2) | Fair value    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt $ 7,700,000 $ 8,800,000
v3.25.4
Income Taxes - Schedule of Income Tax (Benefit) Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Current:      
Federal $ (7,296) $ 1,222 $ (10,894)
State 1,344 6,125 (4,818)
Current income tax (benefit) expense (5,952) 7,347 (15,712)
Deferred:      
Federal 551,000 (21,463) 450,091
State 106,836 36,195 (65,425)
Deferred income tax expense 657,836 14,732 384,666
Total income tax expense $ 651,884 $ 22,079 $ 368,954
v3.25.4
Income Taxes - Schedule of Income Tax Payments (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating Loss Carryforwards [Line Items]      
Federal $ (81,195) $ 12,149 $ 12,876
Total taxes paid, net of refunds (79,022) 7,960 13,350
Mississippi      
Operating Loss Carryforwards [Line Items]      
State:     670
Pennsylvania      
Operating Loss Carryforwards [Line Items]      
State:   (4,114)  
Other U.S. states      
Operating Loss Carryforwards [Line Items]      
State: $ 2,173 $ (75) $ (196)
v3.25.4
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, 2025
Dec. 31, 2024
Dec. 31, 2023
Amount      
Income before income taxes $ 2,977,542 $ 264,194 $ 2,103,498
U.S. federal statutory tax rate 625,284 55,481 441,735
State and local income taxes, net of federal benefit (a) 95,217 35,115 (55,993)
Research and development credits (181) (5,779) (4,896)
Other (536) (758) 180
Capital loss carryforward 0 (52,820) 78
Other 977 818 1,301
Transaction costs 0 6,041 0
Other 1,814 2,639 (2,984)
Changes in unrecognized tax benefits (b) (9,636) (16,977) (7,015)
Noncontrolling interests in consolidated subsidiaries (60,156) (2,724) (334)
Other adjustments: (899) 1,043 (3,118)
Total income tax expense $ 651,884 $ 22,079 $ 368,954
Rate      
U.S. federal statutory tax rate 21.00% 21.00% 21.00%
State and local income taxes, net of federal benefit (a) 3.20% 13.30% (2.70%)
Research and development credits 0.00% (2.20%) (0.20%)
Other 0.00% (0.30%) 0.00%
Capital loss carryforward 0.00% (20.00%) 0.00%
Other 0.00% 0.30% 0.10%
Changes in unrecognized tax benefits (b) 0.00% 2.30% 0.00%
Other 0.10% 1.00% (0.10%)
Changes in unrecognized tax benefits (b) (0.30%) (6.40%) (0.30%)
Noncontrolling interests in consolidated subsidiaries (2.00%) (1.00%) 0.00%
Other adjustments: 0.00% 0.40% (0.10%)
Total income tax expense and effective tax rate 21.90% 8.40% 17.50%
v3.25.4
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, 2025
Dec. 31, 2024
Deferred tax asset:    
NOL carryforwards $ 789,888 $ 708,518
Federal tax credits 98,813 89,644
Interest disallowance limitation 45,222 106,622
Incentive compensation and deferred compensation plans 26,432 18,032
State capital loss carryforward 22,062 44,496
Net unrealized losses 0 80,723
Other 0 2,433
Deferred tax asset 982,417 1,050,468
Valuation allowance (254,460) (257,218)
Net deferred tax asset 727,957 793,250
Deferred tax liability:    
Property, plant and equipment (2,792,495) (2,516,074)
Investment in partnerships (1,392,717) (1,128,279)
Net unrealized gains (13,070) 0
Other (1,685) 0
Deferred tax liability (4,199,967) (3,644,353)
Net deferred tax liability $ (3,472,010) $ (2,851,103)
v3.25.4
Income Taxes - Narrative (Details) - USD ($)
$ in Thousands
 1 Months Ended 12 Months Ended
Oct. 31, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Sep. 30, 2024
Operating Loss Carryforwards [Line Items]          
Increase in deferred tax liability   $ 620,900      
Total NOL carryforwards   789,888 $ 708,518    
Interest disallowance limitation   45,222 106,622    
Valuation allowance   254,460 257,218    
Interest expense   200 600 $ (19,800)  
Interests and penalties   3,100 2,900 2,300  
Reductions for lapse in statute of limitations $ 900 14,574 13,706 $ 0  
Increase in the net operating loss $ 10,900        
R&D tax credits          
Operating Loss Carryforwards [Line Items]          
Settlement resulting in reduction of liabilities and deferred tax assets         $ 29,600
Domestic Tax Jurisdiction          
Operating Loss Carryforwards [Line Items]          
Total NOL carryforwards     52,800    
Domestic Tax Jurisdiction | Capital Loss Carryforward          
Operating Loss Carryforwards [Line Items]          
Valuation allowance   22,100 44,500    
State and Local Jurisdiction          
Operating Loss Carryforwards [Line Items]          
Total NOL carryforwards     2,300    
State and Local Jurisdiction | Interest Expense Limitation          
Operating Loss Carryforwards [Line Items]          
Valuation allowance   $ 10,500 $ 10,400    
v3.25.4
Income Taxes - Schedule of Operating Loss Carryforwards (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards $ 789,888 $ 708,518
Total valuation allowance on NOL carryforwards (216,342) (201,584)
Federal NOL DTA    
Operating Loss Carryforwards [Line Items]    
Total valuation allowance on NOL carryforwards (13,870) (14,263)
Federal NOL DTA | Expires between 2032 to 2037    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards 14,644 14,644
Federal NOL DTA | Indefinite expiration    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards 386,846 322,258
State NOL DTA    
Operating Loss Carryforwards [Line Items]    
Total valuation allowance on NOL carryforwards (202,472) (187,321)
State NOL DTA | Indefinite expiration    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards 33,576 24,337
State NOL DTA | Expires between 2026 to 2045    
Operating Loss Carryforwards [Line Items]    
Total NOL carryforwards $ 354,822 $ 347,279
v3.25.4
Income Taxes - Schedule of Reconciliation of the Beginning and Ending Amount of Reserve (Details) - USD ($)
$ in Thousands
 1 Months Ended 12 Months Ended
Oct. 31, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Unrecognized Tax Benefits [Roll Forward]        
Balance at January 1   $ 72,743 $ 89,197 $ 204,035
Additions for tax positions taken in current year   8,291 11,720 11,986
(Reductions) additions for tax positions taken in prior years   (6,131)   (883)
Additions for tax positions taken in prior years     15,177  
Reductions for tax positions settled with tax authorities   0 (29,645) (125,941)
Reductions for lapse in statute of limitations $ (900) (14,574) (13,706) 0
Balance at December 31   $ 60,329 $ 72,743 $ 89,197
v3.25.4
Income Taxes - Schedule of Uncertain Tax Positions (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax Disclosure [Abstract]      
If recognized, effect to the effective tax rate $ 57,350 $ 67,105 $ 83,669
Reduction of related deferred tax asset for general business credit carryforwards and NOLs $ 50,612 $ 60,415 $ 77,013
v3.25.4
Debt - Schedule of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Jan. 19, 2024
Debt Instrument [Line Items]      
Principal Value $ 7,855,486 $ 9,368,516  
Carrying Value 7,800,328 9,324,177  
Long-term debt 8,032,291 9,299,525  
Less: Current portion of debt, principal value 507,915 320,800  
Current portion of debt 507,119 320,800  
Less: Current portion of debt 508,352 320,800  
Total long-term debt, principal value 7,347,571 9,047,716  
Total long-term debt, carrying value 7,293,209 9,003,377  
Total long-term debt, fair value 7,523,939 8,978,725  
EQT's revolving credit facility maturing July 23, 2030 | Credit facility      
Debt Instrument [Line Items]      
Principal Value 75,000 150,000  
Carrying Value 75,000 150,000  
Long-term debt 75,000 150,000  
Eureka's revolving credit facility maturing November 13, 2027 | Credit facility      
Debt Instrument [Line Items]      
Principal Value 285,000 320,800  
Carrying Value 285,000 320,800  
Long-term debt $ 285,000 $ 320,800  
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 392,409 391,193  
Long-term debt $ 391,037 $ 382,994  
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 114,710 114,213  
Long-term debt $ 117,315 $ 119,590  
EQM's 7.500% notes due June 1, 2027 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 7.50% 7.50%  
Principal Value $ 0 $ 500,000  
Carrying Value 0 511,377  
Long-term debt $ 0 $ 510,140  
EQM's 6.500% notes due July 1, 2027 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 6.50% 6.50%  
Principal Value $ 0 $ 900,000  
Carrying Value 0 915,538  
Long-term debt $ 0 $ 912,159  
EQT's 6.500% notes due July 1, 2027 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 6.50% 6.50%  
Principal Value $ 344,921 $ 0  
Carrying Value 346,255 0  
Long-term debt $ 352,902 $ 0  
EQT's 3.900% notes due October 1, 2027 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 3.90% 3.90%  
Principal Value $ 936,158 $ 1,169,503  
Carrying Value 934,640 1,166,523  
Long-term debt $ 932,282 $ 1,137,248  
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 494,905 492,640  
Long-term debt $ 516,035 $ 508,695  
EQM's 5.500% notes due July 15, 2028 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 5.50% 5.50%  
Principal Value $ 0 $ 118,683  
Carrying Value 0 118,204  
Long-term debt $ 0 $ 117,382  
EQT's 5.500% notes due July 15, 2028 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 5.50% 5.50%  
Principal Value $ 45,225 $ 0  
Carrying Value 45,060 0  
Long-term debt $ 46,099 $ 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 316,448 315,785  
Long-term debt $ 322,902 $ 314,357  
EQM's 4.50% notes due January 15, 2029 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 4.50% 4.50%  
Principal Value $ 0 $ 742,923  
Carrying Value 0 711,754  
Long-term debt $ 0 $ 711,297  
EQT's 4.50% notes due January 15, 2029 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 4.50% 4.50%  
Principal Value $ 734,583 $ 0  
Carrying Value 710,802 0  
Long-term debt $ 736,603 $ 0  
EQM's 6.375% notes due April 1, 2029 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 6.375% 6.375%  
Principal Value $ 0 $ 600,000  
Carrying Value 0 608,667  
Long-term debt $ 0 $ 606,774  
EQT's 6.375% notes due April 1, 2029 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 6.375% 6.375%  
Principal Value $ 596,725 $ 0  
Carrying Value 602,840 0  
Long-term debt $ 618,076 $ 0  
EQT's 7.000% notes due February 1, 2030 (c) | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 7.00% 7.00%  
Principal Value $ 674,800 $ 674,800  
Carrying Value 672,263 671,641  
Long-term debt $ 733,676 $ 718,358  
EQM's 7.500% notes due June 1, 2030 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 7.50% 7.50%  
Principal Value $ 0 $ 500,000  
Carrying Value 0 535,671  
Long-term debt $ 0 $ 534,950  
EQT's 7.500% notes due June 1, 2030 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 7.50% 7.50%  
Principal Value $ 494,086 $ 0  
Carrying Value 522,749 0  
Long-term debt $ 544,162 $ 0  
EQM's 4.75% notes due January 15, 2031 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 4.75% 4.75%  
Principal Value $ 0 $ 1,100,000  
Carrying Value 0 1,045,219  
Long-term debt $ 0 $ 1,039,995  
EQT's 4.75% notes due January 15, 2031 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 4.75% 4.75%  
Principal Value $ 1,090,218 $ 0  
Carrying Value 1,044,098 0  
Long-term debt $ 1,098,329 $ 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 431,496 430,818  
Long-term debt $ 409,651 $ 388,111  
EQT's 5.750% notes due February 1, 2034 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 5.75% 5.75% 5.75%
Principal Value $ 750,000 $ 750,000  
Carrying Value 743,589 742,796  
Long-term debt $ 784,500 $ 744,743  
EQM's 6.500% notes due July 15, 2048 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 6.50% 6.50%  
Principal Value $ 0 $ 80,233  
Carrying Value 0 81,338  
Long-term debt $ 0 $ 81,932  
EQT's 6.500% notes due July 15, 2048 | Senior notes      
Debt Instrument [Line Items]      
Interest rate (percent) 6.50% 6.50%  
Principal Value $ 67,196 $ 0  
Carrying Value 68,064 0  
Long-term debt $ 68,722 $ 0  
v3.25.4
Debt - Debt Instrument Redemption (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 19, 2025
Jul. 31, 2025
Mar. 12, 2025
Dec. 31, 2024
Debt Instrument [Line Items]          
Outstanding borrowings $ 7,800,328       $ 9,324,177
Senior notes          
Debt Instrument [Line Items]          
Principal 1,401,616        
Premiums Paid/(Discounts Received) 26,684        
Accrued But Unpaid Interest 15,274        
Total Cost 1,443,574        
Third party costs $ 2,700        
EQM's 7.500% notes due June 1, 2027 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 7.50%       7.50%
Principal $ 4,069        
Premiums Paid/(Discounts Received) 76        
Accrued But Unpaid Interest 51        
Total Cost 4,196        
Outstanding borrowings $ 0       $ 511,377
EQM's 6.500% notes due July 1, 2027 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 6.50%       6.50%
Principal $ 555,077        
Premiums Paid/(Discounts Received) 14,590        
Accrued But Unpaid Interest 6,754        
Total Cost 576,421     $ 506,200  
Outstanding borrowings $ 0       $ 915,538
EQT's 3.900% notes due October 1, 2027 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 3.90%       3.90%
Principal $ 233,345        
Premiums Paid/(Discounts Received) (2,842)        
Accrued But Unpaid Interest 4,070        
Total Cost 234,573     $ 233,300  
Outstanding borrowings $ 934,640       $ 1,166,523
EQM's 5.500% notes due July 15, 2028 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 5.50%       5.50%
Principal $ 73,456        
Premiums Paid/(Discounts Received) 2,878        
Accrued But Unpaid Interest 1,190        
Total Cost 77,524        
Outstanding borrowings $ 0       $ 118,204
EQM's 4.50% notes due January 15, 2029 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 4.50%       4.50%
Principal $ 8,338        
Premiums Paid/(Discounts Received) 27        
Accrued But Unpaid Interest 17        
Total Cost 8,382        
Outstanding borrowings $ 0       $ 711,754
EQM's 6.375% notes due April 1, 2029 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 6.375%       6.375%
Principal $ 3,265        
Premiums Paid/(Discounts Received) 135        
Accrued But Unpaid Interest 70        
Total Cost 3,470        
Outstanding borrowings $ 0       $ 608,667
EQM's 7.500% notes due June 1, 2030 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 7.50%       7.50%
Principal $ 5,536        
Premiums Paid/(Discounts Received) 666        
Accrued But Unpaid Interest 69        
Total Cost 6,271        
Outstanding borrowings $ 0       $ 535,671
EQM's 4.75% notes due January 15, 2031 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 4.75%       4.75%
Principal $ 9,616        
Premiums Paid/(Discounts Received) 117        
Accrued But Unpaid Interest 20        
Total Cost 9,753        
Outstanding borrowings $ 0       $ 1,045,219
EQM's 6.500% notes due July 15, 2048 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 6.50%       6.50%
Principal $ 12,989        
Premiums Paid/(Discounts Received) 1,738        
Accrued But Unpaid Interest 37        
Total Cost 14,764        
Outstanding borrowings $ 0       $ 81,338
EQT's 7.500% notes due June 1, 2027 | Senior notes          
Debt Instrument [Line Items]          
Interest rate (percent) 7.50% 7.50%     7.50%
Principal $ 495,925        
Premiums Paid/(Discounts Received) 9,299        
Accrued But Unpaid Interest 2,996        
Total Cost 508,220        
Previously Existing EQM Notes | Senior notes          
Debt Instrument [Line Items]          
Principal     $ 92,700    
Outstanding borrowings $ 0        
v3.25.4
Debt - Narrative (Details)
$ in Thousands
 5 Months Ended 12 Months Ended
Jun. 30, 2025
Jun. 29, 2025
Apr. 02, 2025
USD ($)
Feb. 24, 2025
USD ($)
Jul. 22, 2024
extension
Jan. 22, 2024
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Mar. 12, 2025
USD ($)
Jan. 19, 2024
Apr. 30, 2020
USD ($)
Debt Instrument [Line Items]                          
Debt instrument, face amount             $ 9,368,516 $ 7,855,486 $ 9,368,516        
Loss on debt extinguishment               22,652 68,299 $ 80      
Proceeds from net settlement of Capped Call Transactions (Note 7)               0 93,290 0      
Capped call                          
Debt Instrument [Line Items]                          
Proceeds from net settlement of Capped Call Transactions (Note 7)           $ 93,300              
Senior notes                          
Debt Instrument [Line Items]                          
Total Cost               1,443,574          
Aggregate maturities in 2025               508,000          
Aggregate maturities in 2026               1,281,000          
Aggregate maturities in 2027               545,000          
Aggregate maturities in 2028               1,650,000          
Aggregate maturities in 2029               1,169,000          
Aggregate maturities thereafter               2,343,000          
EQM's 6.500% notes due July 15, 2048 | Senior notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount             $ 80,233 0 $ 80,233        
Total Cost               $ 14,764          
Interest rate (percent)             6.50% 6.50% 6.50%        
EQM's 5.500% notes due July 15, 2028 | Senior notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount             $ 118,683 $ 0 $ 118,683        
Total Cost               $ 77,524          
Interest rate (percent)             5.50% 5.50% 5.50%        
EQM's 4.50% notes due January 15, 2029 | Senior notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount             $ 742,923 $ 0 $ 742,923        
Total Cost               $ 8,382          
Interest rate (percent)             4.50% 4.50% 4.50%        
EQM's 7.500% notes due June 1, 2030 | Senior notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount             $ 500,000 $ 0 $ 500,000        
Total Cost               $ 6,271          
Interest rate (percent)             7.50% 7.50% 7.50%        
EQM's 6.500% notes due July 1, 2027 | Senior notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount             $ 900,000 $ 0 $ 900,000        
Total Cost               $ 576,421     $ 506,200    
Interest rate (percent)             6.50% 6.50% 6.50%        
New EQT Notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount       $ 4,541,800                  
Debt conversion, converted instrument, amount     $ 3,868,900                    
New EQT Notes | Conversion Period One                          
Debt Instrument [Line Items]                          
Conversion ratio       0.001                  
New EQT Notes | Conversion Period Two                          
Debt Instrument [Line Items]                          
Conversion ratio       0.950                  
Previously Existing EQM Notes | Senior notes                          
Debt Instrument [Line Items]                          
Debt conversion, original debt, amount     3,869,500                    
Payments of restructuring costs     3,900                    
Debt instrument, unamortized discount     $ 600                    
Loss on debt extinguishment               $ 9,600          
EQT's 5.750% notes due February 1, 2034 | Senior notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount             $ 750,000 $ 750,000 $ 750,000        
Interest rate (percent)             5.75% 5.75% 5.75%     5.75%  
1.75% convertible notes due May 1, 2026 | Senior notes                          
Debt Instrument [Line Items]                          
Interest rate (percent)                         1.75%
1.75% convertible notes due May 1, 2026 | Senior notes                          
Debt Instrument [Line Items]                          
Debt instrument, face amount                         $ 500,000
Interest rate (percent)                         1.75%
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          
Number of extensions | extension         2                
Extension term         1 year                
Financial commitments under facility percentage               65.00%          
Letters of credit outstanding             $ 1,000 $ 2,000 $ 1,000        
Maximum amount of outstanding borrowings               566,000 2,357,000 269,000      
Average daily balance of loans outstanding               $ 98,000 $ 936,000 $ 40,000      
Weighted average interest rates               5.90% 6.60% 6.90%      
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          
Letters of credit outstanding             0 0 $ 0        
Maximum amount of outstanding borrowings             330,000 321,000          
Average daily balance of loans outstanding             $ 328,000 $ 288,000          
Weighted average interest rates             7.80% 7.00%          
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                          
Debt Instrument [Line Items]                          
Unused commitment fee paid to maintain credit facility 0.325% 0.375%           0.325%          
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                          
Debt Instrument [Line Items]                          
Unused commitment fee paid to maintain credit facility 0.45% 0.50%           0.50%          
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%          
v3.25.4
Investments in Unconsolidated Entities - Schedule of Equity Method Investments (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Schedule of Equity Method Investments [Line Items]    
Carrying Value $ 3,597,564 $ 3,584,155
MVP Joint Venture    
Schedule of Equity Method Investments [Line Items]    
Carrying Value $ 3,514,803 $ 3,534,730
MVP A    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 49.30% 49.30%
Carrying Value $ 3,097,754 $ 3,469,438
MVP B    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 47.20% 47.20%
Carrying Value $ 42,420 $ 65,292
MVP C    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 49.30% 0.00%
Carrying Value $ 374,629 $ 0
Laurel Mountain Midstream, LLC    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest 31.00% 31.00%
Carrying Value $ 47,037 $ 28,757
Nonconsolidated Investees, Other    
Schedule of Equity Method Investments [Line Items]    
Ownership Interest
Carrying Value $ 35,724 $ 20,668
v3.25.4
Investments in Unconsolidated Entities - Narrative (Details)
$ in Thousands
 1 Months Ended 12 Months Ended
Jan. 16, 2026
USD ($)
Dec. 31, 2023
Bcf / d
mi
in
Dec. 31, 2025
USD ($)
Bcf / d
mi
in
Jan. 20, 2026
Nov. 30, 2025
USD ($)
Nov. 24, 2025
Jul. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Schedule of Equity Method Investments [Line Items]                
Accretion, net     $ 1,400,000          
Carrying Value     $ 3,597,564         $ 3,584,155
MVP Mainline | MVP C                
Schedule of Equity Method Investments [Line Items]                
Annual minimum volume (in Bcf per day) | Bcf / d     0.6          
Laurel Mountain Midstream, LLC                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest     31.00%         31.00%
Carrying Value     $ 47,037         $ 28,757
MVP Joint Venture                
Schedule of Equity Method Investments [Line Items]                
Carrying Value     $ 3,514,803         $ 3,534,730
MVP Joint Venture | MVP C                
Schedule of Equity Method Investments [Line Items]                
Decrease of initial guarantee         $ 14,800      
MVP Joint Venture | Mountain Valley Pipeline                
Schedule of Equity Method Investments [Line Items]                
Natural gas interstate pipeline (in miles) | mi     303          
Pipeline diameter (in inches) | in     42          
Annual minimum volume (in Bcf per day) | Bcf / d     2.0          
MVP Joint Venture | MVP B                
Schedule of Equity Method Investments [Line Items]                
Pipeline diameter (in inches) | in   30            
Annual minimum volume (in Bcf per day) | Bcf / d   0.55            
Decrease of initial guarantee             $ 14,200  
Remaining capital obligation (as a percent)     33.00%          
MVP Joint Venture | MVP B | Pittsylvania                
Schedule of Equity Method Investments [Line Items]                
Natural gas interstate pipeline (in miles) | mi   31 75          
MVP Joint Venture | MVP B | Rockingham County, North Carolina                
Schedule of Equity Method Investments [Line Items]                
Pipeline diameter (in inches) | in     24          
MVP Joint Venture | MVP B | Alamance County, North Carolina                
Schedule of Equity Method Investments [Line Items]                
Pipeline diameter (in inches) | in     16          
MVP Southgate | Minimum                
Schedule of Equity Method Investments [Line Items]                
Estimated cost     $ 370,000          
MVP Southgate | Maximum                
Schedule of Equity Method Investments [Line Items]                
Estimated cost     430,000          
MVP C | Minimum                
Schedule of Equity Method Investments [Line Items]                
Estimated cost     400,000          
MVP C | Maximum                
Schedule of Equity Method Investments [Line Items]                
Estimated cost     $ 540,000          
MVP A                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest     49.30%         49.30%
Carrying Value     $ 3,097,754         $ 3,469,438
MVP A | ConEd                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest           6.60%    
MVP A | ConEd | Subsequent Event                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest 3.94%              
MVP A | ConEd | Subsequent Event | Series of Individually Immaterial Asset Acquisitions                
Schedule of Equity Method Investments [Line Items]                
Equity issued as consideration for acquisition $ 200,700              
MVP A | ConEd | Subsequent Event | Series of Individually Immaterial Asset Acquisitions | BXCI Affiliate                
Schedule of Equity Method Investments [Line Items]                
Equity issued as consideration for acquisition $ 98,400              
MVP C                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest     49.30%         0.00%
Carrying Value     $ 374,629         $ 0
MVP C | ConEd                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest           6.60%    
MVP C | ConEd | Subsequent Event                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest 3.94%              
MVP C | ConEd | Subsequent Event | Series of Individually Immaterial Asset Acquisitions                
Schedule of Equity Method Investments [Line Items]                
Equity issued as consideration for acquisition $ 12,500              
MVP LLC Agreement | Subsequent Event | Series of Individually Immaterial Asset Acquisitions                
Schedule of Equity Method Investments [Line Items]                
Ownership Interest       2.66%        
the Investment Fund                
Schedule of Equity Method Investments [Line Items]                
Investment owned     $ 33,000         $ 33,000
v3.25.4
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, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]          
Operating revenues   $ 8,644,211 $ 5,273,309 $ 6,908,923  
Net income   2,325,658 242,115 1,734,544  
Current assets $ 1,714,679 1,895,151 1,714,679    
Total assets 39,830,255 41,792,874 39,830,255 25,285,098  
Current liabilities 2,461,549 2,484,841 2,461,549    
Total liabilities 15,552,119 14,432,726 15,552,119    
Members' equity 24,278,136 27,360,148 24,278,136 $ 14,780,817 $ 11,213,328
Total liabilities and equity 39,830,255 41,792,874 39,830,255    
MVP A          
Schedule of Equity Method Investments [Line Items]          
Operating revenues 247,360 565,312      
Operating income 126,202 270,095      
Net income 129,773 275,419      
Current assets 204,028 129,883 204,028    
Noncurrent assets 9,535,975 9,419,089 9,535,975    
Total assets 9,740,003 9,548,972 9,740,003    
Current liabilities 69,303 24,218 69,303    
Noncurrent liabilities 1,514 4,629 1,514    
Total liabilities 70,817 28,847 70,817    
Members' equity 9,669,186 9,520,125 9,669,186    
Total liabilities and equity $ 9,740,003 $ 9,548,972 $ 9,740,003    
v3.25.4
The Midstream Joint Venture - Narrative (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 30, 2024
Dec. 31, 2025
Jan. 16, 2026
Nov. 24, 2025
Dec. 31, 2024
MVP A          
Schedule of Equity Method Investments [Line Items]          
Ownership Interest   49.30%     49.30%
MVP A | ConEd          
Schedule of Equity Method Investments [Line Items]          
Ownership Interest       6.60%  
MVP A | Subsequent Event | ConEd          
Schedule of Equity Method Investments [Line Items]          
Ownership Interest     3.94%    
MVP C          
Schedule of Equity Method Investments [Line Items]          
Ownership Interest   49.30%     0.00%
MVP C | ConEd          
Schedule of Equity Method Investments [Line Items]          
Ownership Interest       6.60%  
MVP C | Subsequent Event | ConEd          
Schedule of Equity Method Investments [Line Items]          
Ownership Interest     3.94%    
BXCI Affiliate | Midstream Joint Venture          
Schedule of Equity Method Investments [Line Items]          
Cash consideration $ 3,500.0        
Distribution paid   $ 354.9      
BXCI Affiliate | Midstream Joint Venture | until the Base Return | Capital Unit, Class A          
Schedule of Equity Method Investments [Line Items]          
Distribution allocation (percent) 40.00%        
BXCI Affiliate | Midstream Joint Venture | until the Base Return | Capital Unit, Class B          
Schedule of Equity Method Investments [Line Items]          
Distribution allocation (percent) 60.00%        
BXCI Affiliate | Midstream Joint Venture | after the Base Return | Capital Unit, Class A          
Schedule of Equity Method Investments [Line Items]          
Distribution allocation (percent) 100.00%        
BXCI Affiliate | Midstream Joint Venture | from the 8th anniversary of December 30, 2024 and thereafter | Capital Unit, Class A          
Schedule of Equity Method Investments [Line Items]          
Distribution allocation (percent) 95.00%        
BXCI Affiliate | Midstream Joint Venture | from the 8th anniversary of December 30, 2024 and thereafter | Capital Unit, Class B          
Schedule of Equity Method Investments [Line Items]          
Distribution allocation (percent) 5.00%        
v3.25.4
Common Stock and Income Per Share - Narrative (Details) - USD ($)
$ / shares in Units, $ in Millions
 1 Months Ended 12 Months Ended 49 Months Ended
Jul. 01, 2025
Jul. 22, 2024
Aug. 22, 2023
Jul. 31, 2025
Jul. 31, 2024
Aug. 31, 2023
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2025
Dec. 18, 2024
Class of Stock [Line Items]                      
Stock repurchased (in shares)             0 0      
Olympus Energy Acquisition                      
Class of Stock [Line Items]                      
Number of shares issued in business combination (in shares) 25,229,166     25,229,166              
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     $ 2,000.0  
Extension                     2 years
Shares repurchased since inception                   $ 622.1  
Shares of EQT corporation common stock repurchased (in shares)                 5,906,159    
Aggregate purchase price                 $ 200.0    
Average cost (in dollars per share)                 $ 33.86    
Stock compensation plans                      
Class of Stock [Line Items]                      
Common stock authorized and unissued (in shares)             16,300,000     16,300,000  
v3.25.4
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, 2025
Dec. 31, 2024
Dec. 31, 2023
Equity [Abstract]      
Net income attributable to EQT Corporation – Basic income available to shareholders $ 2,039,247 $ 230,577 $ 1,735,232
Add back: Interest expense on Convertible Notes, net of tax 0 86 7,551
Diluted income available to shareholders $ 2,039,247 $ 230,663 $ 1,742,783
Weighted average common stock outstanding - Basic (in shares) 611,571 509,597 380,902
Options, restricted stock, performance awards and stock appreciation rights (in shares) 4,146 4,625 5,232
Convertible Notes (in shares) 0 371 27,090
Weighted average common stock outstanding - diluted (in shares) 615,717 514,593 413,224
Net income attributable to EQT Corporation - Basic (in dollars per share) $ 3.33 $ 0.45 $ 4.56
Net income attributable to EQT Corporation - Diluted (in dollars per share) $ 3.31 $ 0.45 $ 4.22
v3.25.4
Acquisitions - Narrative (Details)
 1 Months Ended
Jul. 01, 2025
USD ($)
a
MMcf
$ / shares
shares
Jul. 22, 2024
USD ($)
shares
Apr. 11, 2024
USD ($)
Aug. 22, 2023
USD ($)
shares
Jul. 31, 2025
shares
Jul. 31, 2024
shares
Aug. 31, 2023
shares
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2021
Business Combination [Line Items]                    
Goodwill               $ 2,062,462,000 $ 2,079,481,000  
Olympus Energy Acquisition                    
Business Combination [Line Items]                    
Area of Land | a 90,000                  
Annual minimum volume (in Bcf per day) | MMcf 500                  
Number of shares issued in business combination (in shares) | shares 25,229,166       25,229,166          
Equity interest subjected to purchase price adjustments $ 1,471,365,000                  
Share price (in dollars per share) | $ / shares $ 58.32                  
Cash payments to acquire business $ 473,360,000                  
Goodwill 0                  
Purchase price $ 1,944,725,000                  
Equitrans Midstream Merger                    
Business Combination [Line Items]                    
Number of shares issued in business combination (in shares) | shares   152,427,848       152,427,848        
Equity interest subjected to purchase price adjustments   $ 5,500,000,000                
Purchase and redemption price   685,300,000                
Equitrans Midstream Merger | Employees Of Equitrans Midstream                    
Business Combination [Line Items]                    
Equity interest subjected to purchase price adjustments   $ 79,500,000                
NEPA Gathering System Acquisition                    
Business Combination [Line Items]                    
Ownership interest acquired (percent)     33.75%             50.00%
Purchase price     $ 205,000,000              
Tug Hill and XcL Midstream                    
Business Combination [Line Items]                    
Number of shares issued in business combination (in shares) | shares       49,599,796     49,599,796      
Cash payments to acquire business       $ 2,400,000,000            
v3.25.4
Acquisitions - Schedule of Purchase Price Allocation (Details)
$ in Thousands
Jul. 01, 2025
USD ($)
Business Combination, Recognized Liability Assumed, Liability [Abstract]  
Accounts payable $ 3,082
Olympus Energy Acquisition  
Business Combination, Consideration Transferred [Abstract]  
Equity 1,471,365
Cash 473,360
Total consideration 1,944,725
Business Combination, Recognized Asset Acquired, Asset [Abstract]  
Derivative instruments, at fair value 13,188
Prepaid expenses and other 18
Property, plant and equipment 2,019,892
Amount attributable to assets acquired 2,033,098
Business Combination, Recognized Liability Assumed, Liability [Abstract]  
Derivative instruments, at fair value 66,711
Other current liabilities 3,657
Asset retirement obligations and other liabilities 14,923
Amount attributable to liabilities assumed $ 88,373
v3.25.4
Acquisitions - Schedule of Post-Acquisition Operating Results (Details) - USD ($)
$ in Thousands
 6 Months Ended 12 Months Ended
Dec. 31, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Business Combination [Line Items]        
Transaction costs   $ 35,843 $ 309,419 $ 56,263
Olympus Energy Acquisition        
Business Combination [Line Items]        
Total operating revenues $ 271,204      
Net income attributable to EQT Corporation 108,117      
Transaction costs   $ 29,100    
Sales of natural gas, natural gas liquids and oil | Olympus Energy Acquisition        
Business Combination [Line Items]        
Total operating revenues 235,388      
Gain on derivatives | Olympus Energy Acquisition        
Business Combination [Line Items]        
Total operating revenues 31,257      
Pipeline and other | Olympus Energy Acquisition        
Business Combination [Line Items]        
Total operating revenues $ 4,559      
v3.25.4
Divestitures - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
May 31, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Gain (loss) on sale of long-lived assets     $ 31,214 $ 764,044 $ (17,445)
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Non-Core Asset Divestiture          
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]          
Divestitures consideration     600    
Asset retirement obligations of disposal group including discontinued operation     $ 97,000    
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 value of divested assets   $ 523,000      
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  
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%     60.00%  
Carrying value of divested assets $ 772,000     $ 772,000  
Proceeds from sale of oil and gas property and equipment $ 1,250,000        
Gain (loss) on sale of long-lived assets       $ 463,000  
v3.25.4
Commitment and Contingencies (Details) - USD ($)
$ in Millions
 3 Months Ended
May 12, 2025
Jun. 30, 2025
Dec. 31, 2025
Sep. 30, 2025
Jun. 30, 2024
Asset retirement obligations          
Long-Term Purchase Commitment [Line Items]          
Received insurance recoveries     $ 4.0    
Environmental loss contingency, statement of financial position [Extensible Enumeration]     Asset retirement obligations and other liabilities    
Securities Class Action Litigation          
Long-Term Purchase Commitment [Line Items]          
Loss contingency accrual   $ 167.5     $ 17.5
Reserve on provision $ 167.5        
Accrual for estimated loss contingencies   $ 150.0      
Received insurance recoveries       $ 16.0  
Demand Charge Payments | Pipeline Demand Charges          
Long-Term Purchase Commitment [Line Items]          
2026     $ 1,100.0    
2027     1,100.0    
2028     1,000.0    
2029     900.0    
2030     900.0    
Thereafter     8,200.0    
Total     13,200.0    
Services and Materials Payment Commitment | Frac Sand and Equipment          
Long-Term Purchase Commitment [Line Items]          
2026     230.5    
2027     116.6    
2028     41.1    
2029     0.6    
2030     0.4    
Thereafter     0.1    
Total     $ 389.3    
v3.25.4
Share-Based Compensation Plans - Schedule of Share-Based Compensation Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense $ 59,599 $ 49,988 $ 51,200
Other operating expense      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 2,700 105,400 3,600
Restricted stock awards      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 41,310 25,473 20,119
Stock appreciation rights      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 0 0 4,056
Other programs, including non-employee director awards      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense 3,784 3,596 3,110
Incentive Performance Share Unit Programs      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Share-based compensation expense $ 14,505 $ 20,919 $ 23,915
v3.25.4
Share-Based Compensation Plans - Narrative (Details) - USD ($)
 1 Months Ended 12 Months Ended
Jan. 18, 2026
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
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   $ 0 $ 5,100,000 $ 0  
Income tax benefit by the exercise of nonqualified employee stock options and vesting of restricted share awards   12,300,000 7,700,000 16,500,000  
Cash paid for taxes related to net settlement of share-based incentive awards   54,175,000 102,872,000 41,780,000  
Capitalized compensation cost   20,258,000 10,095,000 6,287,000  
Incentive PSU Program          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Capitalized compensation cost   $ 900,000 $ 500,000 $ 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 | 2024 Incentive Performance Share Unit Program          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Unrecognized compensation costs on non-vested awards   $ 4,600,000      
Performance Shares | 2025 Incentive Performance Share Unit Program          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Unrecognized compensation costs on non-vested awards   $ 18,000,000.0      
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)   377,570 371,500 404,790  
Weighted average fair value, granted in period (in dollars per share)   $ 74.14 $ 40.08 $ 38.79  
Value   $ 91,392,158 $ 31,920,023 $ 11,637,401  
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 | Minimum | 2025 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 | 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 Shares | Maximum | 2025 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 | Subsequent Event | 2026 Incentive Performance Share Unit Program          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Non-vested shares, granted in period (in shares) 505,000        
Performance Share, Equity Awards | Minimum | Subsequent Event | 2026 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 Share, Equity Awards | Maximum | Subsequent Event | 2026 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%        
Restricted stock awards          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Capitalized compensation cost   $ 19,400,000 9,600,000 5,700,000  
Unrecognized compensation costs on non-vested awards   66,200,000      
Value   $ 45,500,000 $ 155,500,000 $ 23,500,000  
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)   1,720,700 982,990 953,270  
Period after which the shares granted will be fully vested   3 years      
Weighted average fair value, granted in period (in dollars per share)   $ 52.80 $ 34.54 $ 31.88  
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)   1,720,700 982,990 953,270  
Weighted average fair value, granted in period (in dollars per share)   $ 52.80 $ 34.54 $ 31.88  
Aggregate fair value, conversion     $ 185,708,206    
Value   $ 45,519,859 $ 155,480,899 $ 23,482,927  
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) 1,170,000        
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   $ 2,700,000 $ 700,000 $ 1,400,000  
Other programs, including non-employee director awards          
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Shares outstanding (in shares)   305,556      
Shares granted (in shares)   36,630 70,930 66,300  
Weighted average fair value, granted (in dollars per share)   $ 50.74 $ 36.14 $ 33.31  
v3.25.4
Share-Based Compensation Plans - Schedule of Executive Performance Incentive Programs (Details) - Performance Shares - Incentive PSU Programs – Equity Settled - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Non- Vested Shares      
Non-vested shares, outstanding, beginning balance (in shares) 1,292,351 1,831,553 2,861,990
Non-vested shares, granted in period (in shares) 377,570 371,500 404,790
Non-vested shares, granted from multiplier (in shares) 649,020 451,805 409,383
Non-vested shares, vested (in shares) (1,213,385) (1,355,415) (1,773,994)
Non-vested shares, forfeited (in shares) (66,009) (7,092) (70,616)
Non-vested shares, outstanding, ending balance (in shares) 1,039,547 1,292,351 1,831,553
Weighted Average Fair Value      
Weighted average fair value, outstanding, beginning balance (in dollars per share) $ 34.86 $ 28.27 $ 16.66
Weighted average fair value, granted in period (in dollars per share) 74.14 40.08 38.79
Weighted average fair value, granted from multiplier (in dollars per share) 75.32 23.55 6.56
Weighted average fair value, vested (in dollars per share) 75.32 23.55 6.56
Weighted average fair value, forfeited (in dollars per share) 54.23 45.94 37.59
Weighted average fair value, outstanding, ending balance (in dollars per share) $ 25.93 $ 34.86 $ 28.27
Aggregate Fair Value      
Aggregate fair value, beginning balance $ 45,054,280 $ 51,770,381 $ 47,674,881
Aggregate fair value, granted in period 27,993,040 14,889,720 15,701,804
Aggregate fair value, granted from multiplier 48,884,186 10,640,008 2,685,552
Aggregate fair value, vested (91,392,158) (31,920,023) (11,637,401)
Aggregate fair value, forfeited (3,579,668) (325,806) (2,654,455)
Aggregate fair value, ending balance $ 26,959,680 $ 45,054,280 $ 51,770,381
v3.25.4
Share-Based Compensation Plans - Summary of Monte Carlo Simulation Valuation Method (Details) - PSU incentives - grant_date
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]          
Risk-free interest rate 4.22% 4.35% 4.16% 1.52% 0.18%
Volatility factor 43.15% 48.82% 59.31% 65.38% 72.50%
Expected term (in years) 3 years 3 years 3 years 3 years 3 years
Number of grant dates     2   2
v3.25.4
Share-Based Compensation Plans - Summary of Restricted Stock Activity (Details) - Restricted Stock - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Aggregate Fair Value      
Aggregate fair value, vested $ (45,500,000) $ (155,500,000) $ (23,500,000)
Incentive PSU Programs – Equity Settled      
Non- Vested Shares      
Non-vested shares, outstanding, beginning balance (in shares) 3,424,169 2,217,802 2,926,945
Non-vested shares, granted in period (in shares) 1,720,700 982,990 953,270
Non-vested shares, vested (in shares) (1,458,200) (4,861,796) (1,544,968)
Non-vested shares, conversion (in shares)   5,175,814  
Non-vested shares, forfeited (in shares) (140,937) (90,641) (117,445)
Non-vested shares, outstanding, ending balance (in shares) 3,545,732 3,424,169 2,217,802
Weighted Average Fair Value      
Weighted average fair value, outstanding, beginning balance (in dollars per share) $ 33.32 $ 23.82 $ 16.67
Weighted average fair value, granted in period (in dollars per share) 52.80 34.54 31.88
Weighted average fair value, vested (in dollars per share) 31.22 31.98 15.20
Weighted average fair value, conversion (in dollars per share)   35.88  
Weighted average fair value, forfeited (in dollars per share) 35.00 31.92 24.52
Weighted average fair value, outstanding, ending balance (in dollars per share) $ 43.58 $ 33.32 $ 23.82
Aggregate Fair Value      
Aggregate fair value, outstanding, beginning balance $ 114,104,385 $ 52,819,850 $ 48,792,574
Aggregate fair value, granted 90,858,021 33,950,507 30,389,954
Aggregate fair value, vested (45,519,859) (155,480,899) (23,482,927)
Aggregate fair value, conversion   185,708,206  
Aggregate fair value, forfeited (4,933,212) (2,893,279) (2,879,751)
Aggregate fair value, outstanding, ending balance $ 154,509,335 $ 114,104,385 $ 52,819,850
v3.25.4
Share-Based Compensation Plans - Schedule of Valuation Assumptions for Non-Qualified Stock Options (Details) - Non-qualified Stock Options - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
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 (in years)       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
v3.25.4
Share-Based Compensation Plans - Summary of Non-qualified Option Activity (Details) - Non-Qualified Stock Options
 12 Months Ended
Dec. 31, 2025
USD ($)
$ / shares
shares
Shares  
Outstanding, beginning balance (in shares) | shares 1,195,336
Exercised (in shares) | shares (95,874)
Outstanding, ending balance (in shares) | shares 1,099,462
Weighted Average Exercise Price  
Weighted average exercise price, outstanding, beginning balance (in dollars per share) | $ / shares $ 12.14
Weighted average exercise price, outstanding, Exercised (in dollars per share) | $ / shares 23.93
Weighted average exercise price, outstanding, ending balance (in dollars per share) | $ / shares $ 11.11
Weighted Average Remaining Contractual Term  
Weighted average remaining contractual term, outstanding 1 year 3 months 18 days
Aggregate Intrinsic Value  
Aggregate intrinsic value, outstanding, end of period | $ $ 46,713,420
v3.25.4
Leases - Lease Cost (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Lessee, Lease, Description [Line Items]      
Operating lease costs $ 43,002 $ 41,991 $ 26,755
Finance lease costs 9,585 5,546 2,414
Variable and short-term lease costs 38,935 33,475 24,151
Total lease costs 91,522 81,012 53,320
Property, Plant and Equipment      
Lessee, Lease, Description [Line Items]      
Operating lease costs 30,800 33,100 24,500
Total lease costs $ 47,900 $ 50,500 $ 40,800
v3.25.4
Leases - Schedule of Operating and Finance Lease Liabilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Leases [Abstract]      
Operating lease liabilities $ 21,155 $ 13,595 $ 10,078
Finance lease liabilities $ 6,347 $ 4,232 $ 2,305
v3.25.4
Leases - Narrative (Details)
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Leases [Abstract]      
Operating lease, weighted average remaining lease term 2 years 4 months 24 days 3 years 4 months 24 days 1 year 7 months 6 days
Operating lease, discount rate 5.10% 5.30% 4.70%
Finance lease, weighted average remaining lease term 5 years 7 months 6 days 6 years 9 months 18 days 3 years 9 months 18 days
Finance lease, discount rate 5.10% 5.10% 4.80%
v3.25.4
Leases - Schedule of Balance Sheet Information (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Right-of-Use Assets    
Operating $ 74,111 $ 60,496
Finance lease, right-of-use asset, statement of financial position [Extensible Enumeration] Other assets Other assets
Finance $ 35,650 $ 34,803
Total right-of-use assets $ 109,761 $ 95,299
Lease Liabilities    
Operating lease, liability, current, statement of financial position [Extensible List] Other current liabilities Other current liabilities
Current portion of lease liabilities $ 51,042 $ 36,275
Finance lease, liability, current, statement of financial position [Extensible Enumeration] Other current liabilities Other current liabilities
Finance $ 7,082 $ 5,603
Total current lease liabilities 58,124 41,878
Operating $ 27,369 $ 29,391
Finance lease, liability, noncurrent, statement of financial position [Extensible Enumeration] Asset retirement obligations and other liabilities Asset retirement obligations and other liabilities
Finance $ 29,973 $ 29,263
Total noncurrent lease liabilities 57,342 58,654
Total lease liabilities $ 115,466 $ 100,532
Operating lease, liability, noncurrent, statement of financial position [Extensible Enumeration] Asset retirement obligations and other liabilities Asset retirement obligations and other liabilities
Operating lease, right-of-use asset, statement of financial position [Extensible List] Other assets Other assets
v3.25.4
Leases - Lease Maturity (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Operating Lease  
2026 $ 53,639
2027 10,859
2028 7,915
2029 5,972
2030 4,885
Thereafter 350
Total lease payment obligations 83,620
Less: Imputed interest 5,209
Present value of lease liabilities 78,411
Finance Lease  
2026 8,722
2027 8,355
2028 7,058
2029 5,879
2030 4,697
Thereafter 7,705
Total lease payment obligations 42,416
Less: Imputed interest 5,361
Present value of lease liabilities 37,055
Total Lease  
2026 62,361
2027 19,214
2028 14,973
2029 11,851
2030 9,582
Thereafter 8,055
Total lease payment obligations 126,036
Less: Imputed interest 10,570
Present value of lease liabilities $ 115,466
v3.25.4
Concentrations of Credit Risk (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
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 94.00% 96.00%
v3.25.4
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, 2025
Dec. 31, 2024
Dec. 31, 2023
Capitalized costs      
Proved properties $ 35,129,865 $ 31,986,473  
Unproved properties 1,656,045 1,563,440  
Total capitalized costs 36,785,910 33,549,913  
Less: Accumulated depletion 14,344,974 12,489,317  
Net oil and gas producing properties 22,440,936 21,060,596  
Property acquisition:      
Proved properties 1,522,869 410,805 $ 4,142,621
Unproved properties 390,103 98,007 575,130
Exploration 3,601 2,735 3,330
Development 1,725,438 1,848,000 1,782,428
Olympus Energy Acquisition      
Property acquisition:      
Unproved properties 235,500    
NEPA Non Operated Asset Divestiture      
Property acquisition:      
Unproved properties   10,800  
Marcellus leases | Olympus Energy Acquisition      
Property acquisition:      
Proved properties 288,400    
Marcellus leases | NEPA Non Operated Asset Divestiture      
Property acquisition:      
Proved properties   74,700  
Marcellus wells | Olympus Energy Acquisition      
Property acquisition:      
Proved properties $ 1,234,500    
Marcellus wells | NEPA Non Operated Asset Divestiture      
Property acquisition:      
Proved properties   $ 267,700  
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
v3.25.4
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, 2025
Dec. 31, 2024
Dec. 31, 2023
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Transportation and processing $ 1,532,090 $ 1,915,616 $ 2,157,260
Production 388,696 377,007 239,001
Operating and maintenance 23,013 37,951 0
Exploration 3,601 2,735 3,330
Depreciation and depletion 2,263,105 2,016,670 1,732,142
(Gain) loss on sale/exchange of long-lived assets (31,513) (764,431) 17,445
Impairment and expiration of leases 50,341 97,368 109,421
Income tax expense 851,939 316,377 187,463
Results of operations from producing activities, excluding corporate overhead 2,645,440 935,073 583,007
un-recast      
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Production     254,700
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 $ 7,726,712 $ 4,934,366 $ 5,044,768
v3.25.4
Natural Gas Producing Activities (Unaudited) - Narrative (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2025
Dec. 31, 2025
MMcfe
Dec. 31, 2025
Bcfe
Dec. 31, 2025
$ / MBoe
Dec. 31, 2025
$ / Dekatherm
Dec. 31, 2025
$ / bbl
Dec. 31, 2025
USD ($)
Dec. 31, 2024
Dec. 31, 2024
MMcfe
Dec. 31, 2024
Bcfe
Dec. 31, 2024
$ / MBoe
Dec. 31, 2023
Dec. 31, 2023
MMcfe
Dec. 31, 2023
Bcfe
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                              
Engineer experience (in years) 23 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)       (2,380,000)             2,637       2,561
Extensions, discoveries and other additions (in Bcfe)       2,445,000             3,126       3,412
Production (in Bcfe)     2,382,367 2,382,000           2,228,159 2,228     2,016,273 2,016
Reserve development converting previously unproved acreage to proved reserves (Energy)       1,605,000             2,414       1,670
Development plan, term 5 years               5 years       5 years    
Increased reserves (in Bcfe)     2,444,717 133,000           3,125,620 157     3,411,750 92
Inclusion in drilling plan (in Bcfe)       393,000             498       1,341
Converting unproved reserves to proved developed reserves (in Bcfe)       314,000             57       309
Negative revisions from proved undeveloped locations (in Bcfe)       560,000             (925)       (755)
Revision of curves (in bcfe)                             367
Changes in ownership interests (in Bcfe)       291,000 42,000           189 (87)     290
Negative curve revisions at proved developed locations (in Bcfe)       (165,000)             65       208
Removal of locations, economic and lack of development (in Bcfe)       449,000             (192)       (362)
Purchase of minerals in place (in Bcfe) | MMcfe     1,768,560             413,040       2,600,667  
Sale of natural gas in place (in Bcfe) | MMcfe     (22,027)             (1,562,849)       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% 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 | $               $ 1,265              
Change in discounted future cash flows for assumed natural gas liquids price change | $               1,104              
Change in discounted future cash flows for assumed oil price change | $               $ 61              
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)        
Olympus Energy Acquisition                              
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                              
Purchase of minerals in place (in Bcfe)       1,768,000                      
Non-Core Asset Divestiture                              
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]                              
Sale of natural gas in place (in Bcfe)       (22,000)                      
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
v3.25.4
Natural Gas Producing Activities (Unaudited) - Schedule of the Entity's Proved and Unproved Reserves (Details)
 12 Months Ended
Dec. 31, 2025
MMcf
Dec. 31, 2025
MMcfe
Dec. 31, 2025
MBbls
Dec. 31, 2025
Bcfe
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
Proved developed and undeveloped reserves:                        
Balance at January 1 | MMcfe   26,264,669       27,596,694       25,002,589    
Revision of previous estimates | MMcfe   (27,073)       (1,079,677)       (1,402,039)    
Purchase of hydrocarbons in place | MMcfe   1,768,560       413,040       2,600,667    
Sale of hydrocarbons in place | MMcfe   (22,027)       (1,562,849)       0    
Extensions, discoveries and other additions   2,444,717   133,000   3,125,620   157   3,411,750   92
Production   (2,382,367)   (2,382,000)   (2,228,159)   (2,228)   (2,016,273)   (2,016)
Balance at December 31 | MMcfe   28,046,479       26,264,669       27,596,694    
Proved developed reserves:                        
Balance at January 1 | MMcfe   18,804,929       19,558,176       17,513,645    
Balance at December 31 | MMcfe   20,580,992       18,804,929       19,558,176    
Proved undeveloped reserves:                        
Balance at January 1 | MMcfe   7,459,740       8,038,518       7,488,944    
Balance at December 31 | MMcfe   7,465,487       7,459,740       8,038,518    
Natural Gas                        
Proved developed and undeveloped reserves:                        
Balance at January 1 | MMcf 24,545,229       25,795,134       23,824,887      
Revision of previous estimates | MMcf (15,493)       (917,676)       (1,461,305)      
Purchase of hydrocarbons in place | MMcf 1,768,120       395,423       2,012,159      
Sale of hydrocarbons in place | MMcf (16,145)       (1,562,849)       0      
Extensions, discoveries and other additions | MMcf 2,373,231       2,921,638       3,326,736      
Production | MMcf (2,238,652)       (2,086,441)       (1,907,343)      
Balance at December 31 | MMcf 26,416,290       24,545,229       25,795,134      
Proved developed reserves:                        
Balance at January 1 | MMcf 17,440,191       18,186,432       16,541,017      
Balance at December 31 | MMcf 19,237,547       17,440,191       18,186,432      
Proved undeveloped reserves:                        
Balance at January 1 | MMcf 7,105,038       7,608,702       7,283,870      
Balance at December 31 | MMcf 7,178,743       7,105,038       7,608,702      
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     271,908       285,345       186,141  
Revision of previous estimates     750       (24,332)       11,558  
Purchase of hydrocarbons in place     73       2,529       90,604  
Sale of hydrocarbons in place     (902)       0       0  
Extensions, discoveries and other additions     10,317       30,391       13,592  
Production     (22,168)       (22,025)       (16,550)  
Balance at December 31     259,978       271,908       285,345  
Proved developed reserves:                        
Balance at January 1     217,786       218,523       154,921  
Balance at December 31     215,302       217,786       218,523  
Proved undeveloped reserves:                        
Balance at January 1     54,122       66,822       31,220  
Balance at December 31     44,676       54,122       66,822  
Crude Oil, Condensate, and 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     14,664       14,915       10,142  
Revision of previous estimates     (2,680)       (2,669)       (1,680)  
Purchase of hydrocarbons in place     0       407       7,481  
Sale of hydrocarbons in place     (78)       0       0  
Extensions, discoveries and other additions     1,598       3,606       577  
Production     (1,784)       (1,595)       (1,605)  
Balance at December 31     11,720       14,664       14,915  
Proved developed reserves:                        
Balance at January 1     9,669       10,101       7,183  
Balance at December 31     8,605       9,669       10,101  
Proved undeveloped reserves:                        
Balance at January 1     4,995       4,814       2,959  
Balance at December 31     3,115       4,995       4,814  
v3.25.4
Natural Gas Producing Activities (Unaudited) - Estimated Future Net Cash Flows from Natural Gas and Oil Reserves (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
$ / bbl
$ / MMBTU
uSDollarsPerThousandCubicFeet
Dec. 31, 2024
USD ($)
$ / bbl
$ / MMBTU
uSDollarsPerThousandCubicFeet
Dec. 31, 2023
USD ($)
$ / bbl
$ / MMBTU
uSDollarsPerThousandCubicFeet
Dec. 31, 2022
USD ($)
Extractive Industries [Abstract]        
Future cash inflows $ 80,216,863 $ 44,871,509 $ 52,916,665  
Future production costs (21,496,216) (18,979,056) (24,357,033)  
Future development costs (4,456,051) (4,352,890) (4,298,372)  
Future income tax expenses (11,001,125) (4,445,354) (5,230,629)  
Future net cash flows $ 43,263,471 $ 17,094,209 $ 19,030,631  
Discount for estimated timing of cash flows (percent) 10.00% 10.00% 10.00%  
annual discount for estimated timing of cash flows $ (21,953,285) $ (9,095,069) $ (9,768,282)  
Standardized measure of discounted future net cash flows $ 21,310,186 $ 7,999,140 $ 9,262,349 $ 40,064,524
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]        
Price used in computation of reserves | $ / bbl 26.97 29.28 28.44  
Future abandonment costs $ 2,629,000 $ 2,553,000 $ 2,443,000  
NYMEX        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]        
Price used in computation of reserves, gross | $ / MMBTU 3.387 2.130 2.637  
Price used in computation of reserves, adjustments | $ / MMBTU 0.786 0.741 1.029  
Price used in computation of reserves | uSDollarsPerThousandCubicFeet 2.749 1.468 1.700  
West Texas Intermediate        
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development [Line Items]        
Price used in computation of reserves, gross | $ / bbl 66.01 76.32 78.21  
Price used in computation of reserves, adjustments | $ / bbl 15.29 16.87 14.35  
Price used in computation of reserves | $ / bbl 50.72 59.45 63.86  
v3.25.4
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, 2025
Dec. 31, 2024
Dec. 31, 2023
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Roll Forward]      
Net sales and transfers of natural gas and oil produced $ (5,782,913) $ (2,603,792) $ (2,632,808)
Net changes in prices, production and development costs 16,980,282 (1,237,271) (48,739,248)
Extensions, discoveries and improved recovery, net of related costs 292,028 464,496 6,347,387
Development costs incurred 1,281,816 1,432,315 1,296,380
Net purchase of minerals in place 1,874,429 269,453 2,131,567
Net sale of minerals in place (3,053) (692,019) 0
Revision of previous estimates 135,348 (263,191) (2,768,922)
Accretion of discount 799,914 926,235 4,006,452
Net change in income taxes (2,438,815) 411,999 9,190,460
Timing and other 172,010 28,566 366,557
Net increase (decrease) 13,311,046 (1,263,209) (30,802,175)
Balance at January 1 7,999,140 9,262,349 40,064,524
Balance at December 31 $ 21,310,186 $ 7,999,140 $ 9,262,349
v3.25.4
Schedule II - Valuation and Qualifying Accounts and Reserves (Details) - Deferred Tax Assets - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Beginning of Period $ 257,218 $ 290,812 $ 365,140
Additions Charged to Costs and Expenses 31,798 21,564 12,549
Deductions Charged to Other Accounts 0 0 0
Deductions (34,556) (55,158) (86,877)
Balance at End of Period $ 254,460 $ 257,218 $ 290,812