ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Table of Contents Item 7.        Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and the notes thereto included in Item 8., "Financial Statements and Supplementary Data." Recent and Significant Events Olympus Energy Acquisition Our results of operation for 2025 reflect our acquisition (the Olympus Energy Acquisition) of certain oil and gas properties and related upstream and midstream assets from Olympus Energy LLC, Hyperion Midstream LLC and Bow & Arrow Land Company LLC (collectively, Olympus Energy), which was completed on July 1, 2025. See Note 11 to the Consolidated Financial Statements for further discussion of the Olympus Energy Acquisition. Midstream Joint Venture Transaction Our results of operation for 2025 reflect the impact of the Midstream Joint Venture Transaction (defined in Note 9 to the Consolidated Financial Statements), where we received $3.5 billion of cash consideration from a third-party investor in exchange for a noncontrolling equity interest in the Midstream Joint Venture. The Midstream Joint Venture Transaction was completed on December 30, 2024. NEPA Non-Operated Asset Divestitures and NEPA Gathering System Acquisition Beginning May 31, 2024, our results of operations reflect (i) our divestiture (the First NEPA Non-Operated Asset Divestiture) of an undivided 40% interest in our non-operated natural gas assets in Northeast Pennsylvania and (ii) our 100% ownership of the NEPA Gathering System (defined in Note 11 to the Consolidated Financial Statements) following our acquisition of additional ownership interests therein in connection with the NEPA Gathering System Acquisition (defined in Note 11 to the Consolidated Financial Statements) and the First NEPA Non-Operated Asset Divestiture. In addition, our results of operations for 2025 reflect our 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 our non-operated natural gas assets in Northeast Pennsylvania, which was completed on December 31, 2024. See Note 12 to the Consolidated Financial Statements for further discussion of the NEPA Non-Operated Asset Divestitures. Equitrans Midstream Merger Beginning July 22, 2024, our results of operations reflect our operation of the assets acquired in the Equitrans Midstream Merger (defined in Note 11 to the Consolidated Financial Statements). Following the Equitrans Midstream Merger, the gathering and transmission services previously provided to us by Equitrans Midstream are provided to our Upstream segment by our Gathering and Transmission segments as affiliate transactions. As a result, our Upstream segment's third-party gathering expense decreased and its affiliate transportation and processing expense increased, and our Gathering and Transmission segments' affiliate revenue increased. As the affiliate expense and revenue are eliminated in consolidation, the net impact is a reduction in our consolidated transportation and processing expense. As a result of the completion of the Equitrans Midstream Merger, our operations expanded from a single operating segment to three discrete operating segments reflecting our three lines of business consisting of Upstream, Gathering and Transmission. See Note 11 to the Consolidated Financial Statements for further discussion of the Equitrans Midstream Merger. Trends and Uncertainties Commodity prices were volatile in 2025, and we expect commodity prices to continue to be volatile in 2026 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical instability and tensions, including in Venezuela, Russia, Ukraine and the Middle East, and potential further imposition of domestic and foreign tariffs. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil. 65 Table of Contents In response to price volatility in the natural gas market and to optimize in-basin pricing, we implement strategic curtailments from time to time to reduce our gross production. During the year ended December 31, 2025, strategic curtailments resulted in decreased sales volumes of approximately 14 Bcfe. Low natural gas prices or volatility in the natural gas market may result in adjustments to our 2026 planned development schedule and/or adjustments to the development schedule of non-operated wells in which we have a working interest. We cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our 2026 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures. On July 4, 2025, President Trump signed the OBBBA into law. See Note 6 to the Consolidated Financial Statements for further discussion of the OBBBA. We expect the enactment of the OBBBA to favorably impact our projected cash income tax obligations over the next five years by deferring the payment of a significant portion of current federal income taxes. President Trump has also executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of natural gas, increase the price of supplies and raw materials that we rely on to conduct our business, and impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures. Consolidated Results of Operations Net income attributable to EQT Corporation for 2025 was $2,039 million, $3.31 per diluted share, compared to $231 million, $0.45 per diluted share, for 2024. The increase was driven predominantly by higher sales of natural gas, reflecting higher average realized natural gas prices. To a lesser extent, net income also benefited from decreased gathering expense, increased pipeline revenues, decreased transaction costs, increased gains on derivatives and increased equity earnings from the MVP Joint Venture. These favorable impacts were partly offset by gains recognized in 2024 on the NEPA Non-Operated Asset Divestitures as well as higher income tax expense, depreciation and depletion expense and net income attributable to noncontrolling interests. See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2024, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2023. See "Average Realized Price Reconciliation" for a discussion and calculation of our average realized price, which is based on our Upstream segment's adjusted operating revenues (Upstream adjusted operating revenues), a non-GAAP supplemental financial measure that has been reconciled to total Upstream operating revenues in "Non-GAAP Financial Measures Reconciliation." See "Business Segment Results of Operations" for a discussion of segment operating revenues and expenses and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures, including by business segment. Average Realized Price Reconciliation The following table presents detailed natural gas and liquids operational information to assist in the understanding of our consolidated operations, including the calculation of our average realized price ($/Mcfe), which is based on Upstream adjusted operating revenues, a non-GAAP supplemental financial measure. Upstream adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Upstream adjusted operating revenues should not be considered as an alternative to total Upstream operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of Upstream adjusted operating revenues to total Upstream operating revenues, the most directly comparable financial measure calculated in accordance with United States generally accepted accounting principles (GAAP). 66 Table of Contents Years Ended December 31, 2025 2024 (Thousands, unless otherwise noted) NATURAL GAS Sales volume (MMcf) 2,238,652  2,086,441 NYMEX price ($/MMBtu) $ 3.42  $ 2.30 Btu uplift 0.19  0.13 Natural gas price ($/Mcf) $ 3.61  $ 2.43 Basis ($/Mcf) (a) $ (0.48) $ (0.41) Cash settled basis swaps ($/Mcf) (0.01) (0.07) Average differential, including cash settled basis swaps ($/Mcf) (0.49) (0.48) Average adjusted price ($/Mcf) 3.12  1.95 Cash settled derivatives ($/Mcf) (0.04) 0.64 Average natural gas price, including cash settled derivatives ($/Mcf) $ 3.08  $ 2.59 Natural gas sales, including cash settled derivatives $ 6,888,420  $ 5,401,642 LIQUIDS NGLs, excluding ethane: Sales volume (MMcfe) (b) 88,478  87,564 Sales volume (Mbbl) 14,746  14,594 NGLs price ($/Bbl) $ 38.04  $ 39.13 Cash settled derivatives ($/Bbl) 0.15  (0.30) Average NGLs price, including cash settled derivatives ($/Bbl) $ 38.19  $ 38.83 NGLs sales, including cash settled derivatives $ 563,150  $ 566,808 Ethane: Sales volume (MMcfe) (b) 44,534  44,586 Sales volume (Mbbl) 7,422  7,431 Ethane price ($/Bbl) $ 8.01  $ 6.03 Ethane sales $ 59,447  $ 44,806 Oil: Sales volume (MMcfe) (b) 10,703  9,568 Sales volume (Mbbl) 1,784  1,595 Oil price ($/Bbl) $ 49.08  $ 58.67 Oil sales $ 87,562  $ 93,551 Total liquids sales volume (MMcfe) (b) 143,715  141,718 Total liquids sales volume (Mbbl) 23,952  23,620 Total liquids sales $ 710,159  $ 705,165 TOTAL Total natural gas and liquids sales, including cash settled derivatives (c) $ 7,598,579  $ 6,106,807 Total sales volume (MMcfe) 2,382,367  2,228,159 Average realized price ($/Mcfe) $ 3.19  $ 2.74 (a) Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with our firm transportation agreements, and the NYMEX natural gas price. (b) NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel. (c) Also referred to in this report as Upstream adjusted operating revenues, a non-GAAP supplemental financial measure. 67 Table of Contents Non-GAAP Financial Measures Reconciliation The table below reconciles Upstream adjusted operating revenues, a non-GAAP supplemental financial measure, to total Upstream operating revenues, the most comparable financial measure calculated in accordance with GAAP. See Note 2 to the Consolidated Financial Statements for a reconciliation of total Upstream operating revenues to EQT Corporation operating revenues as reported in the Statements of Consolidated Operations. Upstream adjusted operating revenues (also referred to in this report as total natural gas and liquids sales, including cash settled derivatives) is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Upstream adjusted operating revenues is defined as total Upstream operating revenues, less the revenue impact of changes in the fair value of derivative instruments prior to settlement and Upstream other revenues. We believe that Upstream adjusted operating revenues provides useful information to investors regarding our financial condition and results of operations because it helps facilitate comparisons of operating performance and earnings trends across periods. Upstream adjusted operating revenues reflects only the impact of settled derivative contracts; thus, the measure excludes the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement. The measure also excludes Upstream other revenues, which consists of costs of, and recoveries on, pipeline capacity releases and other revenues. Years Ended December 31, 2025 2024 (Thousands, unless otherwise noted) Total Upstream operating revenues $ 8,024,057  $ 5,009,833 (Deduct) add: Upstream gain on derivatives (290,994) (67,880) Net cash settlements (paid) received on derivatives (a) (83,381) 1,217,895 Premiums paid for derivatives that settled during the period (44,752) (45,454) Upstream other revenues (6,351) (7,587) Upstream adjusted operating revenues, a non-GAAP financial measure $ 7,598,579  $ 6,106,807 Total sales volume (MMcfe) 2,382,367  2,228,159 Average sales price ($/Mcfe) $ 3.24  $ 2.21 Average realized price ($/Mcfe) $ 3.19  $ 2.74 (a) Net cash settlements (paid) received on derivatives are included in average realized price but may not be included in operating revenues. For the year ended December 31, 2025, net cash settlements paid on derivatives consisted of net cash settlements paid on NYMEX natural gas hedge positions of approximately $42 million and net cash settlements paid on basis and liquids hedge positions of approximately $41 million. For the year ended December 31, 2024, net cash settlements received on derivatives consisted of net cash settlements received on NYMEX natural gas hedge positions of approximately $1,374 million, partly offset by net cash settlements paid on basis and liquids hedge positions of approximately $157 million. Business Segment Results of Operations The following sections present operating income and key operational measures for our three reportable segments of Upstream, Gathering and Transmission. We believe this information provides useful information to investors regarding our financial condition, results of operations and trends and uncertainties. See Note 2 to the Consolidated Financial Statements for financial information by business segment. Items that are managed on a consolidated basis, including cash and cash equivalents, debt, income taxes and amounts related to our corporate function, and items related to our energy transition initiatives have not been allocated to our reportable segments. These items are discussed under "Other Income Statement Items." Effective as of December 31, 2025, we renamed our previously reported "Production" segment as the "Upstream" segment to better align with the nature of our operations and our internal reporting framework. This change had no impact on the structure of our internal organization, including the composition of our reportable segments. 68 Table of Contents Upstream Results of Operations Years Ended December 31, 2025 2024 Change % Change (Thousands, unless otherwise noted) Total sales volume (MMcfe) 2,382,367  2,228,159  154,208  6.9 Average daily sales volume (MMcfe/d) 6,527  6,088  439  7.2 Average sales price ($/Mcfe) $ 3.24  $ 2.21  $ 1.03  46.6 Operating revenues: Sales of natural gas, NGLs and oil $ 7,726,712  $ 4,934,366  $ 2,792,346  56.6 Gain on derivatives 290,994  67,880  223,114  328.7 Other revenues 6,351  7,587  (1,236) (16.3) Total operating revenues 8,024,057  5,009,833  3,014,224  60.2 Operating expenses: Transportation and processing: Gathering 196,594  775,114  (578,520) (74.6) Transmission 1,008,438  846,563  161,875  19.1 Processing 327,058  293,939  33,119  11.3 Transportation and processing to affiliate (a) 1,251,365  704,094  547,271  77.7 Total transportation and processing 2,783,455  2,619,710  163,745  6.3 LOE 216,198  196,771  19,427  9.9 Production taxes 172,498  180,236  (7,738) (4.3) Exploration 3,601  2,735  866  31.7 Selling, general and administrative (b) 217,803  244,450  (26,647) (10.9) Production depletion 2,258,540  2,013,120  245,420  12.2 Other depreciation and depletion 4,565  3,550  1,015  28.6 Gain on sale/exchange of long-lived assets (31,513) (764,431) 732,918  (95.9) Impairment and expiration of leases 50,341  97,368  (47,027) (48.3) Other operating expenses 30,438  12,696  17,742  139.7 Total operating expenses 5,705,926  4,606,205  1,099,721  23.9 Operating income $ 2,318,131  $ 403,628  $ 1,914,503  474.3 Per Unit ($/Mcfe): Gathering $ 0.08  $ 0.35  $ (0.27) (77.1) Transmission 0.42  0.38  0.04  10.5 Processing 0.14  0.13  0.01  7.7 Transportation and processing to affiliate (a) 0.53  0.32  0.21  65.6 LOE 0.09  0.09  —  — Production taxes 0.07  0.08  (0.01) (12.5) Selling, general and administrative (b) 0.09  0.11  (0.02) (18.2) Production depletion 0.95  0.90  0.05  5.6 (a) Transportation and processing to affiliate represents intercompany transactions with our Gathering and Transmission segments, which are eliminated in consolidation. (b) Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for our 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. 69 Table of Contents Sales of Natural Gas, NGLs and Oil. Sales of natural gas, NGLs and oil increased by approximately $2,792 million for 2025 compared to 2024, reflecting an increase of approximately $2,451 million from higher average sales price and approximately $341 million from increased sales volumes. Average sales price increased for 2025 compared to 2024 due primarily to a higher NYMEX price, partly offset by lower NGLs price and an unfavorable basis differential. Sales volume increased for 2025 compared to 2024 primarily as a result of production curtailments in 2024 of 107 Bcfe (compared to production curtailments in 2025 of 14 Bcfe), wells turned-in-line since 2024, sales volume increases of 92 Bcfe from the assets acquired in the Olympus Energy Acquisition and sales volume increases of 26 Bcfe from the assets received as consideration for (net of assets divested in) the First NEPA Non-Operated Asset Divestiture. Increases in sales volume were partly offset by sales volume decreases of 155 Bcfe from the assets divested in the Second NEPA Non-Operated Asset Divestiture. The increase in sales volume had a favorable impact on per unit costs for 2025 compared to 2024. Gain on Derivatives . For 2025, we recognized a gain on derivatives of approximately $291 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $291 million due to decreases in NYMEX forward prices and increases in the fair market value of our basis and liquids swaps of approximately $45 million, partly offset by premiums paid for derivative settlements of $45 million. For 2024, we recognized a gain on derivatives of approximately $68 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $422 million due to decreases in NYMEX forward prices, partly offset by decreases in the fair market value of our basis and liquids swaps of approximately $309 million and premiums paid for derivative settlements of $45 million. Gathering Expense. Gathering expense decreased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and First NEPA Non-Operated Asset Divestiture. In addition, gathering expense decreased due to our divestiture of assets in the NEPA Non-Operated Asset Divestitures. Transmission Expense. Transmission expense increased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to capacity charges of approximately $193 million on the MVP Mainline, which entered into service in June 2024, and additional contracted capacity on the Transco pipeline of approximately $33 million, partly offset by capacity released in connection with the NEPA Non-Operated Asset Divestitures of approximately $57 million. Processing Expense. Processing expense increased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to increased production of gas requiring processing from wells turned-in-line since 2024. Transportation and Processing Expense to Affiliate. Affiliate transportation and processing expense increased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger and the Olympus Energy Acquisition, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and First NEPA Non-Operated Asset Divestiture. Production Taxes. Production tax expense decreased on an absolute and per Mcfe basis for 2025 compared to 2024 due to decreased property tax expense of approximately $53 million from lower property tax value based on prior year pricing, partly offset by increased severance tax expense of approximately $35 million from increased sales volume and higher sales prices. Selling, General and Administrative Expense . Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for our change in reportable segments; upon the Equitrans Midstream Merger closing date, we adjusted our basis for selling, general and administrative expense allocation for multi-segment reporting. On a consolidated basis, selling, general and administrative expense increased for 2025 compared to 2024 due primarily to higher labor costs driven by increased headcount as well as higher long-term incentive compensation costs as a result of increases in awards outstanding and changes in the fair value of awards. 70 Table of Contents Production Depletion Expense. Production depletion expense increased on a per Mcfe basis for 2025 compared to 2024 due to higher annual depletion rate. In addition, production depletion expense increased on an absolute basis due to higher sales volumes. Gain on Sale/Exchange of Long-Lived Assets. During 2025, we recognized a net gain on sale/exchange of long-lived assets of approximately $36 million related to acreage trade transactions. During 2024, we recognized a gain on the First NEPA Non-Operated Asset Divestiture of approximately $299 million and a gain on the Second NEPA Non-Operated Asset Divestiture of approximately $463 million. See Note 12 to the Consolidated Financial Statements. Impairment and Expiration of Leases. During 2025 and 2024, we recognized impairment and expiration of leases of approximately $50 million and $97 million, respectively, related to leases that we no longer expect to extend or develop prior to their expiration based on our development plan. Other Operating Expenses. Other operating expenses increased for 2025 compared to 2024 due primarily to proceeds received in 2024 from business interruption insurance claim recoveries and increased expense from changes in legal and environmental reserves, including settlements. See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses. Gathering Results of Operations Years Ended December 31, 2025 2024 Change % Change (Thousands, unless otherwise noted) Gathered volume (BBtu/d): Firm capacity (a) 5,407  5,277  130  2 Volumetric-based services (a) 4,788  4,234  554  13 Total gathered volume 10,195  9,511  684  7 Operating revenues: Loss on derivatives $ —  $ (16,763) $ 16,763  (100) Firm reservation fee revenue (b) 632,916  313,987  318,929  102 Volumetric-based fee revenue 668,518  452,476  216,042  48 Total operating revenues 1,301,434  749,700  551,734  74 Operating expenses: Operating and maintenance 166,990  89,897  77,093  86 Selling, general and administrative (c) 66,642  38,837  27,805  72 Depreciation 212,353  89,513  122,840  137 Gain on sale/exchange of long-lived assets (29) (22) (7) 32 Impairment and expiration of leases 811  —  811  100 Other operating expenses 18,013  —  18,013  100 Total operating expenses 464,780  218,225  246,555  113 Operating income $ 836,654  $ 531,475  $ 305,179  57 (a) For agreements structured with MVCs, firm capacity includes volumes up to the contractual MVC and volumetric-based services includes volumes in excess of the contractual MVC. (b) Firm reservation fee revenue included unbilled revenues supported by MVCs of approximately $18.4 million and $4.2 million for the year ended December 31, 2025 and 2024, respectively. (c) Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for our 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. 71 Table of Contents Firm Reservation Fee Revenue. Firm reservation fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger, which contributed approximately $377 million of additional firm reservation fee revenue in 2025, partly offset by lower revenue of approximately $66 million from the declining rate structures under the gas gathering agreement with our Upstream segment. Volumetric-Based Fee Revenue. Volumetric-based fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger, which contributed approximately $157 million of additional volumetric-based fee revenue in 2025, the gathering assets acquired in the Olympus Energy Acquisition, which contributed approximately $43 million of additional volumetric-based fee revenue in 2025, and increased ownership of the NEPA Gathering System as a result of the NEPA Gathering System Acquisition and the First NEPA Non-Operated Asset Divestiture. Operating Expenses. Gathering operating expenses increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger. In addition, during 2025, Gathering recognized other operating expenses related to environmental reserves. Transmission Results of Operations Years Ended December 31, 2025 2024 Change % Change (Thousands, unless otherwise noted) Transmission pipeline throughput (BBtu/d): Firm capacity (a) 4,426  3,695  731  20 Interruptible capacity 39  24  15  63 Total transmission pipeline throughput 4,465  3,719  746  20 Average contracted firm transmission reservation commitments (BBtu/d) 5,025  4,779  246  5 Operating revenues: Firm reservation fee revenue $ 435,194  $ 183,088  $ 252,106  138 Volumetric-based fee revenue 137,058  35,205  101,853  289 Total operating revenues 572,252  218,293  353,959  162 Operating expenses: Operating and maintenance 58,141  20,496  37,645  184 Selling, general and administrative 37,339  17,183  20,156  117 Depreciation 88,385  33,505  54,880  164 Amortization of intangible assets 13,333  5,901  7,432  126 Loss on sale/exchange of long-lived assets 349  409  (60) (15) Other operating expenses (527) —  (527) 100 Total operating expenses 197,020  77,494  119,526  154 Operating income $ 375,232  $ 140,799  $ 234,433  167 (a) Includes all volumes associated with firm capacity contracts, including volumes in excess of firm capacity. Firm Reservation Fee Revenue. Firm reservation fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger. Volumetric-Based Fee Revenue. Volumetric-based fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger as well as increased throughput. Operating Expenses. Transmission operating expenses increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger. 72 Table of Contents Other Income Statement Items Other Operating Expenses. Corporate other operating expenses decreased for 2025 compared to 2024 due primarily to decreased acquisition-related transaction costs. During 2025, we recognized approximately $29 million of transaction costs related to the Olympus Energy Acquisition compared to approximately $305 million of transaction costs related to the Equitrans Midstream Merger in 2024. In addition, during 2025 and 2024, we recognized net expense of approximately $134 million and $18 million, respectively, for loss contingencies related to the Securities Class Action (defined in Note 13 to the Consolidated Financial Statements). See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses. Income from Investments . Income from investments increased for 2025 compared to 2024 due primarily to higher equity earnings from our investments in the MVP Joint Venture and Laurel Mountain Midstream, LLC of approximately $76 million and $32 million, respectively. Other Income. During 2024, we received proceeds from insurance claim recoveries of approximately $19 million related to the assets acquired in the Tug Hill and XcL Midstream Acquisition (defined in Note 11 to the Consolidated Financial Statements). Loss on Debt Extinguishment. Loss on debt extinguishment decreased for 2025 compared to 2024 due to the derecognition of unamortized fair value adjustments and deferred financing costs associated with debt redemptions, which resulted in a gain of approximately $17 million in 2025 compared to a loss of approximately $16 million in 2024. In addition, net cash call premiums paid were approximately $18 million lower in 2025 compared to 2024. Interest Expense, Net. Net interest expense decreased for 2025 compared to 2024 due primarily to lower interest expense resulting from the repayment of borrowings under EQT's revolving credit facility and the prepayment of term loans outstanding under EQT's unsecured term loan facility, which was prepaid in full and terminated in December 2024. These decreases were partly offset by higher interest expense on the senior notes assumed in connection with the Equitrans Midstream Merger as well as higher capitalized interest associated with the assets acquired in the Equitrans Midstream Merger. Income Tax Expense. See Note 6 to the Consolidated Financial Statements. Net Income Attributable to Noncontrolling Interests. Net income attributable to noncontrolling interests in the Midstream Joint Venture increased approximately $263 million for 2025 compared to 2024 as a result of the Midstream Joint Venture Transaction, which was completed in December 2024. In addition, net income attributable to noncontrolling interests in Eureka Holdings increased approximately $11 million due primarily to the timing of the completion of the Equitrans Midstream Merger. Capital Resources and Liquidity Although we cannot provide any assurance, we believe cash flows from operating activities and availability under EQT's revolving credit facility should be sufficient to meet our cash requirements, including, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long term. Planned Capital Expenditures, Capital Contributions and Sales Volume In 2026, we expect to spend approximately $2,650 million to $2,850 million on total capital expenditures. We expect to fund our capital expenditures with cash generated from operations and, if required, borrowings under EQT's revolving credit facility. Because we are the operator of a high percentage of our developed acreage, the amount and timing of certain of our capital expenditures is largely discretionary. We could choose to defer a portion of our planned 2026 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; and drilling, completion and acquisition costs. In 2026, we expect to make approximately $70 million to $80 million of capital contributions to our equity method investments, including to the MVP Joint Venture. In 2026, we expect our sales volume to be 2,275 Bcfe to 2,375 Bcfe. 73 Table of Contents Material Cash Requirements We have 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. In addition, we have commitments to pay for services related to our operations, including electric hydraulic fracturing services and purchase equipment, materials and sand. See Note 13 to the Consolidated Financial Statements for a summary of aggregated future payments for these commitments. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 7 to the Consolidated Financial Statements for a summary of such contractual commitments, including maturity dates. Through our controlling interest in the Midstream Joint Venture, we are required to distribute available cash flow to the holder of the Midstream Joint Venture's Class B units (Class B Unitholder). See "Financing Activities" below and Note 9 to the Consolidated Financial Statements for further discussion. In addition, in January 2026, we exercised our preferential buy-out right in accordance with the MVP Joint Venture's limited liability company agreement (the MVP LLC Agreement) to acquire additional equity interests in MVP A and MVP C from an affiliate of Con Edison Gas Pipeline and Storage, LLC. Total consideration for our acquisition of the equity interests in MVP A is approximately $200.7 million, of which $98.4 million is expected to be funded by the BXCI Affiliate, subject to purchase price adjustment. Total consideration for our acquisition of the 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. Sources and Uses of Cash Operating Activities. Net cash provided by operating activities was approximately $5,126 million and $2,827 million for 2025 and 2024, respectively. The increase was due primarily to higher cash operating revenues, lower net cash operating expenses and higher distributions received from our investment in MVP A of approximately $189 million, partly offset by net cash settlements paid on derivatives in 2025 compared to net cash settlements received in 2024. Our cash flows from operating activities, including changes in working capital, are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. For a discussion of potential commodity market risks, refer to Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position." Investing Activities. Net cash used in investing activities was approximately $2,845 million and $1,580 million for 2025 and 2024, respectively. The change is attributable primarily to cash proceeds received in 2024 from the NEPA Non-Operated Asset Divestitures. This impact was partly offset by lower cash paid in 2025 for the Olympus Energy Acquisition compared to cash paid in 2024 for the purchase and redemption of the Equitrans Midstream preferred stock (defined in Note 11 to the Consolidated Financial Statements) and for the NEPA Gathering System Acquisition. 74 Table of Contents The following table summarizes our capital expenditures by segment. Years Ended December 31, 2025 2024 (Millions) Upstream: Reserve development $ 1,537  $ 1,653 Land and lease 153  156 Other upstream infrastructure 70  71 Capitalized overhead, capitalized interest and other 118  124 Total Upstream 1,878  2,004 Gathering 368  202 Transmission 52  31 Other corporate items 26  29 Total capital expenditures 2,324  2,266 Deduct: Non-cash items (a) (36) (12) Total cash capital expenditures $ 2,288  $ 2,254 (a) Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures, transfers to or from inventory as assets are completed or assigned to a project and capitalized share-based compensation costs. The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual. Financing Activities . Net cash used in financing activities was approximately $2,372 million and $1,126 million for 2025 and 2024, respectively. For 2025, the primary uses of financing cash flows were the repayment and retirement of debt, payment of dividends, distributions to the Midstream Joint Venture's Class B Unitholder (see below) and net repayments of revolving credit facility borrowings. For 2024, the primary uses of financing cash flows were the repayment and retirement of debt, repayment of borrowings under the revolving credit facility of our wholly owned subsidiary, EQM Midstream Partners LP, and payment of dividends. In addition, for 2024, the primary sources of financing cash flows were net proceeds from the sale of units of the Midstream Joint Venture, proceeds from the issuance of EQT's 5.750% senior notes and net borrowings under EQT's revolving credit facility. We, through our controlling ownership interest in the Midstream Joint Venture, expect to make available cash flow distributions to the Midstream Joint Venture Class B Unitholder at least quarterly. During 2025, the Midstream Joint Venture made distributions of approximately $355 million to its Class B Unitholder. As of December 31, 2025, the remaining amount required to achieve the Base Return (defined and discussed in Note 9 to the Consolidated Financial Statements) was approximately $3.41 billion. See Note 9 to the Consolidated Financial Statements. On February 5, 2026, our Board of Directors declared a quarterly cash dividend of $0.165 per share of EQT common stock, payable on March 2, 2026, to shareholders of record at the close of business on February 17, 2026. Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to redeem or repurchase our outstanding debt or equity securities through tender offers or other cash purchases in the open market or privately negotiated transactions. The amounts involved in any such transactions may be material. See Note 7 to the Consolidated Financial Statements for discussion of redemptions and repurchases of debt and Note 10 to the Consolidated Financial Statements for discussion of repurchases of EQT common stock. Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under EQT's and Eureka's revolving credit facilities, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. EQT's revolving credit facility contains financial covenants that require us to have a total debt to total capitalization ratio no greater than 65%. As of December 31, 2025, we were in compliance with all provisions and covenants under our debt agreements. See Note 7 to the Consolidated Financial Statements for a discussion of borrowings under EQT's and Eureka's revolving credit facilities. 75 Table of Contents Security Ratings Our credit ratings and rating outlooks are subject to revision or withdrawal at any time by the assigning rating agency, and each rating should be evaluated independently from any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in the rating agency's judgment, circumstances so warrant. See Note 4 to the Consolidated Financial Statements for a description of what is deemed investment grade. The table below reflects the credit ratings and rating outlooks assigned to EQT's debt instruments as of February 11, 2026. Rating agency Senior notes Outlook Moody's Investors Service, Inc. (Moody's) Baa3 Stable S&P Global Ratings (S&P) BBB– Stable Fitch Ratings Service (Fitch) BBB– Stable Changes in our credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our revolving credit facilities, the interest rate on our senior notes with adjustable rates, the rates available on new debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties. Commodity Risk Management The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of February 11, 2026. The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled. Q1 2026 (a) Q2 2026 Q3 2026 Q4 2026 Q1 2027 Hedged Volume (MMDth) 228  127  125  108  9 Hedged Volume (MMDth/d) 2.5  1.4  1.4  1.2  0.1 Calls – Short Volume (MMDth) 228  127  125  108  9 Avg. Strike ($/Dth) $ 6.29  $ 4.94  $ 4.94  $ 5.13  $ 4.25 Puts – Long Volume (MMDth) 228  127  125  108  9 Avg. Strike ($/Dth) $ 4.25  $ 3.50  $ 3.50  $ 3.72  $ 3.30 (a) January 1 through March 31. We have also entered into derivative instruments to hedge basis. We may use other contractual agreements to implement our commodity hedging strategy from time to time. See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 4 to the Consolidated Financial Statements for further discussion of our hedging program. Off-Balance Sheet Arrangements As of December 31, 2025, we did not have any material off-balance sheet arrangements other than the commitments described in Note 13 to the Consolidated Financial Statements and the MVP B and MVP C guarantees discussed in Note 8 to the Consolidated Financial Statements. 76 Table of Contents Commitments and Contingencies See Note 13 to the Consolidated Financial Statements for a discussion of our commitments and contingencies. Recently Issued Accounting Standards See Note 1 to the Consolidated Financial Statements for a description of recently issued accounting standards. Critical Accounting Estimates Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements. Management's discussion and analysis of the Consolidated Financial Statements and results of operations are based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of the Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported therein. The following critical accounting estimates, which were reviewed by the Audit Committee of our Board of Directors, relate to our more significant estimates and assumptions used in the preparation of the Consolidated Financial Statements. Actual results could differ from those estimates. Oil and Gas Reserves Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation. Our proved reserve estimates rely on several significant assumptions, including those listed as follows: • future rates of production and estimated ultimate recoveries of developed and undeveloped reserves; • our five-year development plan, including the amount and timing of expected development expenditures; • future liquids recovery in wet-gas areas; and • commodity prices, production costs and income taxes. Proved reserve estimates are reassessed annually using geological, reservoir and production performance data. Estimates are prepared by internal engineers and audited by independent engineers. Management evaluates significant changes in development plans, cost structure and operating conditions that could affect reserve quantities. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions or governmental restrictions. For example, decreases in prices may reduce certain proved reserves by accelerating the timing at which economic limits are reached. Material changes in proved reserve quantities could affect our depletion rates and, therefore, the Consolidated Financial Statements. We estimate future net cash flows from proved reserves based on selling prices using the prescribed twelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period and, as such, is subject to change in subsequent periods. Future production and development costs are based on current costs with no escalation. Income taxes are based on currently enacted statutory tax rates and available tax deductions and credits. Estimate changes during 2025 primarily reflected proved reserves acquired as part of the Olympus Energy Acquisition and development schedule refinements. See Note 17 to the Consolidated Financial Statements for additional information on changes to our proved reserve estimates. We believe oil and gas reserves is a "critical accounting estimate" because changes in proved reserve estimates and the significant assumptions underlying those estimates could materially affect our results of operations or financial position. Based on proved reserves as of December 31, 2025, we estimate that a 1% change in proved reserves would decrease or increase 2026 depletion expense by approximately $11 million and $21 million, respectively, based on current production estimates for 2026. 77 Table of Contents See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position. " Income Taxes We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Consolidated Financial Statements or tax returns. See Notes 1 and 6 to the Consolidated Financial Statements for additional information on our accounting policies for income taxes and the composition of deferred tax assets, valuation allowances and uncertain tax positions. We believe income taxes is a "critical accounting estimate" because we rely on significant assumptions regarding the likelihood, including whether it is more likely than not, that our deferred tax assets will be recovered from future taxable income and the assessment of the amount of financial statement benefit recorded for uncertain tax positions. We evaluate deferred tax assets and valuation allowances using 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. We evaluate uncertain tax positions based on the technical merits of each position and the probability of realization. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid. Changes in our assumptions are sensitive to numerous factors; however, based on income before taxes for the years ended December 31, 2025, 2024 and 2023, we estimate that a 1% change in our effective tax rate would increase or decrease income tax expense by approximately $30 million, $3 million and $21 million, respectively. Derivative Instruments We use derivative commodity instruments primarily to reduce exposure to commodity price risk associated with future sales of natural gas production. See Note 4 t o the Consolidated Financial Statements for a description of our derivative instruments and Note 5 to the Consolidated Financial Statements for a description of the fair value hierarchy. The values reported in the Consolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, many of which are beyond our control, change. We believe derivative instruments is a "critical accounting estimate" because changes in the market value of our derivative instruments resulting from the volatility of both NYMEX natural gas prices and basis can materially affect our results of operations or financial position. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. The sensitivity of our derivative fair value measurements to changes in natural gas prices is quantified through the hypothetical 10% price change analysis disclosed in Item 7A., "Quantitative and Qualitative Disclosures about Market Risk," which is calculated using a valuation methodology consistent with our derivative fair value measurements. Contingencies and Asset Retirement Obligations We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies when a loss is probable and the amount can be reasonably estimated. Our contingency estimates rely on assumptions about the likelihood of loss and the ability to reasonably estimate a range of potential outcomes. We evaluate contingencies on an ongoing basis in consultation with legal counsel, considering developments in each matter and the potential range of outcomes. See Note 13 to the Consolidated Financial Statements for information on our contingencies. We also accrue a liability for asset retirement obligations based on the estimated timing and cost of settlement. For oil and gas wells, the fair value of plugging and abandonment obligations is recorded when the obligation is incurred, which is typically at the time the well is spud. Our asset retirement obligation estimates are based on methodologies and assumptions described in Note 1 to the Consolidated Financial Statements, including assessments of the expected timing and cost of settlement and the discount rates applied to determine the present value of future obligations. Estimate changes during 2025 primarily reflected routine updates to plugging cost inputs. There were no material changes to our estimation methodologies. 78 Table of Contents We believe contingencies and asset retirement obligations is a "critical accounting estimate" because changes in these estimates and the significant assumptions underlying them could materially affect our results of operations or financial position. Actual losses related to contingencies could differ from our estimates, which may require additional cash expenditures. Changes in the expected timing or amount of asset retirement obligations may require adjustments to the carrying value of our liabilities. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved. Business Combinations In a business combination, the identifiable assets acquired and liabilities assumed are recorded at fair value as of the acquisition date. Goodwill results when the cost of an acquisition exceeds the fair value of the net assets acquired. During 2025, we completed the Olympus Energy Acquisition. The significant assumptions used to estimate the fair value of assets acquired and liabilities assumed in the Olympus Energy Acquisition are discussed in Note 11 to the Consolidated Financial Statements. We believe business combinations is a "critical accounting estimate" because the valuation of acquired assets and assumed liabilities requires significant judgment about future events and may rely on inputs that are not observable in the market. Changes in these assumptions could materially affect our results of operations or financial position. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved. Long-Lived Assets (Including Property, Plant and Equipment and Intangible Assets) See Note 1 to the Consolidated Financial Statements for a discussion of our fair value measurements and impairment evaluations for oil and gas properties, midstream assets, other property, plant and equipment (including our assessment of the recoverability of capitalized costs of unproved oil and gas properties) and intangible assets. Our impairment evaluations for long-lived assets rely on the following significant assumptions, as applicable: • future natural gas and NGLs sales prices; • estimated reserve quantities and expected timing of production; • future operating costs and capital requirements; • discount rates and inflation assumptions used in estimating the present value of expected future cash flows; and • operating levels, utilization and other asset-specific performance expectations (e.g., projected gathered and processed volumes and transmission throughput for midstream assets; expected contract utilization for intangible assets related to acquired transmission service agreements). We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying amounts may not be recoverable. We consider indicators such as changes in commodity prices, well performance, expected development activity, operating cost trends, asset utilization levels and asset-specific market conditions. When indicators are present, we estimate recoverable value using income-based and, when appropriate, market-based valuation techniques. There were no indicators of impairment to our material asset groups identified during 2025, 2024 and 2023. We believe long-lived asset impairment is a "critical accounting estimate" because these evaluations require significant judgment about future events. Changes in these assumptions could materially affect our results of operations or financial position, including the timing or amount of impairment charges. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved. See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods. " Investments in Unconsolidated Entities See Notes 1 and 8 to the Consolidated Financial Statements for a discussion of our accounting policies for investments in unconsolidated entities and the carrying value of our investments. 79 Table of Contents Our impairment evaluations for investments in unconsolidated entities rely on the following significant assumptions, as applicable: • expected future cash flows of the investee, including assumptions regarding commodity prices, operating costs and capital requirements; • the investee’s ability to generate cash flows sufficient to recover our carrying value; and • market, operational or financial developments that may affect the recoverability of the investment. We evaluate investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the carrying amounts may not be recoverable. We consider indicators such as changes in the investee's financial condition, operating performance, forecasted cash flows or market environment. When indicators are present, we estimate recoverable value using expected future cash flows or other relevant valuation information. There were no indicators of impairment to our investments in unconsolidated entities identified during 2025, 2024 and 2023. We believe the impairment of investments in unconsolidated entities is a "critical accounting estimate" because these evaluations require significant judgment regarding the investee's ability to recover its carrying value. Changes in assumptions about the investee’s operating performance, cash flows or market environment could materially affect our results of operations or financial position. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved. Goodwill Goodwill is tested for impairment annually as of October 1 or when events or changes in circumstances indicate the carrying value of a reporting unit may not be recoverable. Indicators of potential impairment may include adverse changes in market conditions, declining operating performance or negative developments in equity or credit markets. When performed, a quantitative impairment analysis requires judgment in estimating future cash flows, long-term commodity prices, development and operating costs and discount rates used in determining fair value. For 2025, we performed a qualitative assessment and concluded that it was more likely than not that the fair values of our reporting units exceeded their carrying amounts. Because a quantitative test was not performed, no fair value assumptions were developed. See Note 1 to the Consolidated Financial Statements for a discussion of our goodwill impairment assessment process. We believe goodwill impairment is a "critical accounting estimate" because these evaluations require significant judgment about future events. Although we performed a qualitative assessment for 2025, the determination of fair value in a quantitative test would be sensitive to assumptions related to forecasted cash flows, market conditions, industry factors and discount rates. Changes in these assumptions could materially affect the estimated fair values of our reporting units and the resulting conclusion on impairment. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved. Item 7A.    Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk and Derivative Instruments Our primary market risk exposure is the volatility of future prices for natural gas and NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Prolonged low, or significant, extended declines in, natural gas and NGLs prices could adversely affect, among other things, our development plans, which would decrease the pace of development and the level of our proved reserves and, similarly, could adversely affect timing of development of additional reserves and production that is accessible by our pipeline and storage assets and limit growth in, or may reduce the demand for, and usage of, our gathering or transmission and storage services. Price declines and sustained periods of low natural gas and NGLs prices could also have an adverse effect on the creditworthiness of our gathering, transmission and storage customers and related ability to pay firm reservation fees under long-term contracts. Increases in natural gas and NGLs prices may be accompanied by, or result in, increased well drilling costs, increased production taxes, increased LOE, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. In addition, to the extent we have hedged our production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas, and, depending on our then-current credit ratings and the terms of our hedging contracts, we may be required to post additional margin with our hedging counterparties. 80 Table of Contents The overall objective of our hedging program is to protect our cash flows from undue exposure to the risk of changing commodity prices. Our use of derivatives is further described in Note 4 to the Consolidated Financial Statements and "Commodity Risk Management" under "Capital Resources and Liquidity" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." Our OTC derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of those institutions is regularly monitored. We primarily enter into derivative instruments to hedge forecasted sales of production. We also enter into derivative instruments to hedge basis. Our use of derivative instruments is implemented under a set of policies approved by our management-level Hedge and Financial Risk Committee and is reviewed by our Board of Directors. For derivative commodity instruments used to hedge our forecasted sales of production, which are at, for the most part, NYMEX natural gas prices, we set policy limits relative to the expected production and sales levels that are exposed to price risk. We have an insignificant amount of financial natural gas derivative commodity instruments for trading purposes. The derivative commodity instruments we use are primarily swap, collar and option agreements. These agreements may require payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. We use these agreements to hedge our NYMEX and basis exposure. We may also use other contractual agreements when executing our commodity hedging strategy. We monitor price and production levels on a continuous basis and adjust quantities hedged as warranted. A hypothetical decrease of 10% in the NYMEX natural gas price on December 31, 2025 and 2024 would increase the fair value of our natural gas derivative commodity instruments by approximately $100 million and $283 million, respectively. A hypothetical increase of 10% in the NYMEX natural gas price on December 31, 2025 and 2024 would decrease the fair value of our natural gas derivative commodity instruments by approximately $93 million and $340 million, respectively. For purposes of this analysis, we applied the 10% change in the NYMEX natural gas price on December 31, 2025 and 2024 to our natural gas derivative commodity instruments as of December 31, 2025 and 2024 to calculate the hypothetical change in fair value. The change in fair value was determined using a method similar to our normal process for determining derivative commodity instrument fair value described in Note 5 to the Consolidated Financial Statements. The above analysis of our derivative commodity instruments does not include the offsetting impact that the same hypothetical price movement may have on our physical sales of natural gas. The portfolio of derivative commodity instruments held to hedge our forecasted produced natural gas approximates a portion of our expected physical sales of natural gas; therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held to hedge our forecasted production associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on our physical sales of natural gas, assuming that the derivative commodity instruments are not closed in advance of their expected term and the derivative commodity instruments continue to function effectively as hedges of the underlying risk. If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first. Interest Rate Risk Changes in market interest rates affect the amount of interest we earn on cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under EQT's and Eureka's revolving credit facilities. In addition, changes in Eureka's consolidated leverage ratio as a result of Eureka's liquidity needs, operating results or distributions to its members affect the interest rate Eureka pays on borrowings under its revolving credit facility. None of the interest we pay on EQT's senior notes fluctuates based on changes to market interest rates. A 1% increase in interest rates for the borrowings under EQT's revolving credit facility and Eureka's revolving credit facility during 2025 would have increased interest expense attributable to EQT by approximately $3 million. 81 Table of Contents Interest rates for EQT's revolving credit facility and 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. Interest rates for EQT's other outstanding senior notes do not fluctuate based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. For a discussion of credit rating downgrade risk, see Item 1A., "Risk Factors – Our operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms ." Changes in interest rates affect the fair value of our fixed rate debt. See Note 7 to the Consolidated Financial Statements for further discussion of our debt and Note 5 to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value measurement of our debt. Other Market Risks We are exposed to credit loss in the event of nonperformance by counterparties to our derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. Our 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. We use various processes and analyses to monitor and evaluate our 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, we enter into transactions primarily with financial counterparties that are of investment grade, enter into netting agreements whenever possible and may obtain collateral or other security. Approximately 62%, or $159 million, of our OTC derivative contracts outstanding at December 31, 2025 had a positive fair value. Approximately 20%, or $93 million, of our OTC derivative contracts outstanding at December 31, 2024 had a positive fair value. As of December 31, 2025, we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts. During 2025, we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure. We monitor market conditions that may impact the fair value of our derivative contracts. We are exposed to the risk of nonperformance by credit customers on physical sales of natural gas, NGLs and oil. Revenues and related accounts receivable from our operations are generated primarily from the sale of our produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States and Canada. We also contract with certain processors to market a portion of our NGLs on our behalf. As of December 31, 2025, no single lender in the syndicates for EQT's and Eureka's revolving credit facilities held more than 10% and 11%, respectively, of the financial commitments under each facility. The large syndicate group and relatively low percentage of participation by each lender are expected to limit our exposure to disruption or consolidation in the banking industry. 82 Table of Contents Item 8.        Financial Statements and Supplementary Data Page Reference Reports of Independent Registered Public Accounting Firm (PCAOB ID: 42 ) 84 Statements of Consolidated Operations 88 Statements of Consolidated Comprehensive Income 89 Consolidated Balance Sheets 90 Statements of Consolidated Cash Flows 91 Statements of Consolidated Equity 92 Notes to the Consolidated Financial Statements 93 83 Table of Contents Report of Independent Registered Public Accounting Firm To the Shareholders and the Board of Directors of EQT Corporation Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, 2025 and 2024, the related statements of consolidated operations, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 18, 2026 expressed an unqualified opinion thereon. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission (SEC) and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 84 Table of Contents Depreciation, depletion and amortization ('DD&A') of proved oil and natural gas properties Description of the Matter At December 31, 2025, the net book value of the Company's proved oil and natural gas properties was $20,785 million, and depreciation and depletion (DD&A) expense of the Company's Upstream segment was $2,263 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the Company's internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the Company's engineers, are used to calculate depletion on property acquisitions. Significant judgment is required by the Company's engineers in estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including commodity price assumptions and future operating and capital costs assumptions, among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the Company's internal engineers as of December 31, 2025. Auditing the Company's DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of management's determination of the inputs described above used by those engineers in estimating proved natural gas, NGLs and oil reserves. How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company's controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the internal and independent engineers for use in estimating the proved natural gas, NGLs and oil reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent engineers used to audit the estimates. In addition, we evaluated the completeness and accuracy of the financial data and inputs described above used by the internal and external engineers in estimating proved natural gas, NGLs and oil reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management's development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company's drill plan and the availability of capital relative to the drill plan. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved natural gas, NGLs, and oil reserves amounts used to the Company's reserve report. 85 Table of Contents Valuation of Acquired Natural Gas and Oil Properties Description of the Matter As described in Note 11 to the consolidated financial statements, on July 1, 2025, the Company completed the Olympus Energy Acquisition of certain natural gas and oil properties and related midstream assets. EQT accounted for the Olympus Energy Acquisition as a business combination under the acquisition method. The Company's accounting for the Olympus Energy Acquisition included determining the fair value of the acquired natural gas and oil properties. The determination of fair value of the acquired natural gas and oil properties included significant judgment and assumptions by management, including future commodity prices, anticipated production volumes, and a weighted average cost of capital (WACC). Auditing the Company's valuation of acquired natural gas and oil properties involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above which include future market and economic conditions. How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate fair value for the acquired natural gas and oil properties. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions that are inputs to the fair value calculation and management’s review of the valuation model. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff, the independent engineers used to audit the estimates, and the external valuation advisors used to assist with the determination of the fair value of certain natural gas and oil properties. Our testing of the Company’s estimate of fair value of the acquired natural gas and oil properties included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit procedures involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions (future commodity prices and WACC rates) used to develop the fair value estimate. We assessed the reasonableness of management's assumptions by comparing the significant market-related assumptions used in the cash flow model to external market and third-party data and anticipated production volumes to the reserve estimates audited by the independent engineers. /s/ Ernst & Young LLP We have served as the Company's auditor since 1950. Pittsburgh, Pennsylvania February 18, 2026 86 Table of Contents Report of Independent Registered Public Accounting Firm To the Shareholders and the Board of Directors of EQT Corporation Opinion on Internal Control Over Financial Reporting We have audited EQT Corporation and subsidiaries' internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related statements of consolidated operations, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedule listed in the Index at Item 15(a), and our report dated February 18, 2026 expressed an unqualified opinion thereon. Basis for Opinion The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ Ernst & Young LLP Pittsburgh, Pennsylvania February 18, 2026 87 Table of Contents EQT CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED OPERATIONS YEARS ENDED DECEMBER 31, 2025 2024 2023 (Thousands, except per share amounts) Operating revenues: Sales of natural gas, natural gas liquids and oil $ 7,726,712   $ 4,934,366   $ 5,044,768 Gain on derivatives 290,994   51,117   1,838,941 Pipeline and other 626,505   287,826   25,214 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: Basic: Weighted average common stock outstanding 611,571   509,597   380,902 Net income attributable to EQT Corporation $ 3.33   $ 0.45   $ 4.56 Diluted (Note 10): Weighted average common stock outstanding 615,717   514,593   413,224 Net income attributable to EQT Corporation $ 3.31   $ 0.45   $ 4.22 The accompanying notes are an integral part of these Consolidated Financial Statements. 88 Table of Contents EQT CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME YEARS ENDED DECEMBER 31, 2025 2024 2023 (Thousands) 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 The accompanying notes are an integral part of these Consolidated Financial Statements. 89 Table of Contents EQT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2025 2024 (Thousands) ASSETS 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 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 LIABILITIES AND EQUITY 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 The accompanying notes are an integral part of these Consolidated Financial Statements. 90 Table of Contents EQT CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS YEARS ENDED DECEMBER 31, 2025 2024 2023 (Thousands) 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 —   750,000   1,250,000 Proceeds from net settlement of Capped Call Transactions (Note 7) —   93,290   — 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 —   —   ( 201,029 ) Net proceeds from the sale of units of the Midstream Joint Venture (Note 9) ( 1,135 ) 3,410,392   — 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 The accompanying notes are an integral part of these Consolidated Financial Statements. See Note 1 for supplemental cash flow information. 91 Table of Contents EQT CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED EQUITY YEARS ENDED DECEMBER 31, 2025, 2024 AND 2023 Common Stock Retained Earnings Accumulated Other Comprehensive Loss (a) Noncontrolling Interest in Consolidated Subsidiaries Shares Amount Total Equity (Thousands, except per share amounts) Balance at December 31, 2022 365,363   $ 9,891,890   $ 1,283,578   $ ( 2,994 ) $ 40,854   $ 11,213,328 Comprehensive income, net of tax: Net income (loss) 1,735,232   ( 688 ) 1,734,544 Other postretirement benefits liability adjustment, net of tax: $ 59 310   310 Dividends ($ 0.61 per share) ( 228,339 ) ( 228,339 ) Share-based compensation plans 2,274   18,180   18,180 Convertible Notes settlements (Note 7) 8,565   122,830   122,830 Repurchase and retirement of common stock ( 5,906 ) ( 91,545 ) ( 109,484 ) ( 201,029 ) Tug Hill and XcL Midstream Acquisition (Note 11) 49,600   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 Balance at December 31, 2023 419,896   12,093,986   2,681,898   ( 2,684 ) 7,617   14,780,817 Comprehensive income, net of tax: Net income 230,577   11,538   242,115 Other postretirement benefits liability adjustment, net of tax: $ 252 363   363 Dividends ($ 0.63 per share) ( 327,237 ) ( 327,237 ) Share-based compensation plans 4,554   70,688   70,688 Convertible Notes settlements (Note 7) 19,992   285,608   285,608 Net settlement of Capped Call Transactions (Note 7) 93,290   93,290 Equitrans Midstream Merger (Note 11) 152,428   5,548,608   162,993   5,711,601 Change in ownership of consolidated subsidiary, net (Note 9) ( 77,469 ) 3,500,000   3,422,531 Distributions to noncontrolling interest ( 1,640 ) ( 1,640 ) Balance at December 31, 2024 596,870   18,014,711   2,585,238   ( 2,321 ) 3,680,508   24,278,136 Comprehensive income, net of tax: Net income 2,039,247   286,411   2,325,658 Other postretirement benefits liability adjustment, net of tax: $ 137 148   148 Dividends ($ 0.6375 per share) ( 387,396 ) ( 387,396 ) Share-based compensation plans 1,977   26,863   26,863 Olympus Energy Acquisition (Note 11) 25,229   1,471,365   1,471,365 Equitrans Midstream Merger (Note 11) 248   248 Change in ownership of consolidated subsidiary, net (Note 9) 4,822   4,822 Distributions to noncontrolling interest ( 359,696 ) ( 359,696 ) Balance at December 31, 2025 624,076   $ 19,517,761   $ 4,237,089   $ ( 2,173 ) $ 3,607,471   $ 27,360,148 For all periods presented, there were 3  million preferred shares authorized and no preferred shares issued or outstanding. (a) 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. The accompanying notes are an integral part of these Consolidated Financial Statements. 92 Table of Contents EQT CORPORATION AND SUBSIDIARIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2025 1.     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. 93 Table of Contents 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, 2025 2024 (Thousands) 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 Property, Plant and Equipment. The following table summarizes the Company's property, plant and equipment. December 31, 2025 2024 (Thousands) 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 upstream assets, at cost less accumulated depreciation 27,073   20,434 Net upstream assets 22,468,009   21,081,030 Gathering assets 8,677,011   8,067,556 Less: Accumulated depreciation 337,889   131,546 Net gathering assets 8,339,122   7,936,010 Transmission and storage assets 2,751,815   2,667,352 Less: Accumulated depreciation 110,539   30,027 Net transmission and storage assets 2,641,276   2,637,325 Other property, plant and equipment, at cost less accumulated depreciation 109,401   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. 94 Table of Contents 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. 95 Table of Contents 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 o 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, 2025 2024 (Thousands) 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 24,922   24,922 Less: Accumulated amortization 5,202   3,764 Net other intangible assets 19,720   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). 96 Table of Contents Other Current Liabilities. The following table summarizes the Company's other current liabilities. December 31, 2025 2024 (Thousands) Accrued taxes other than income $ 108,626   $ 114,700 Accrued incentive compensation 90,694   53,138 Current portion of 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 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. 97 Table of Contents 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. 98 Table of Contents 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, 2025 2024 (Thousands) Balance at January 1 $ 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 (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, 2025 2024 (Thousands) Operating revenues $ 572,975   $ 218,569 Operating expenses 194,576   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, 2025 2024 (Thousands) Property, plant and equipment $ 2,751,815   $ 2,667,352 Less: Accumulated depreciation 110,539   30,027 Net property, plant and equipment $ 2,641,276   $ 2,637,325 99 Table of Contents 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, 2025 2024 (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, 2025 2024 2023 (Thousands) 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 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. 100 Table of Contents 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, 2025 2024 2023 (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 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   — 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. 101 Table of Contents Subsequent Events. The Company has evaluated subsequent events through the date of the financial statement issuance. 2.     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. 102 Table of Contents 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 Upstream Gathering Transmission Total Segment Intersegment Eliminations and Other EQT Corporation (Thousands) Operating revenues: Sales of natural gas, natural gas liquids and oil $ 7,726,712   $ —   $ —   $ 7,726,712   $ —   $ 7,726,712 Gain on derivatives 290,994   —   —   290,994   —   290,994 Pipeline and other 6,351   1,301,434   572,252   1,880,037   ( 1,253,532 ) 626,505 Total operating revenues 8,024,057   1,301,434   572,252   9,897,743   ( 1,253,532 ) 8,644,211 Operating expenses (a): Transportation and processing 2,783,455   —   —   2,783,455   ( 1,251,365 ) 1,532,090 Production 388,696   —   —   388,696   —   388,696 Operating and maintenance —   166,990   58,141   225,131   —   225,131 Exploration 3,601   —   —   3,601   —   3,601 Selling, general and administrative 217,803   66,642   37,339   321,784   58,282   380,066 Depreciation, depletion and amortization 2,263,105   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 leases 50,341   811   —   51,152   —   51,152 Other operating expenses (b) 30,438   18,013   ( 527 ) 47,924   196,756   244,680 Total operating expenses 5,705,926   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. 103 Table of Contents Year Ended December 31, 2024 Upstream Gathering Transmission Total Segment Intersegment Eliminations and Other EQT 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 derivatives 67,880   ( 16,763 ) —   51,117   —   51,117 Pipeline and other 7,587   766,463   218,293   992,343   ( 704,517 ) 287,826 Total operating revenues 5,009,833   749,700   218,293   5,977,826   ( 704,517 ) 5,273,309 Operating expenses (a): Transportation and processing 2,619,710   —   —   2,619,710   ( 704,094 ) 1,915,616 Production 377,007   —   —   377,007   —   377,007 Operating and maintenance —   89,897   20,496   110,393   —   110,393 Exploration 2,735   —   —   2,735   —   2,735 Selling, general and administrative (b) 244,450   38,837   17,183   300,470   36,254   336,724 Depreciation, depletion and amortization 2,016,670   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 leases 97,368   —   —   97,368   —   97,368 Other operating expenses (c) 12,696   —   —   12,696   337,168   349,864 Total operating expenses 4,606,205   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. 104 Table of Contents Year Ended December 31, 2023 Upstream Gathering Total Segment Intersegment Eliminations and Other EQT Corporation (Thousands) Operating revenues: Sales of natural gas, natural gas liquids and oil $ 5,044,768   $ —   $ 5,044,768   $ —   $ 5,044,768 Gain on derivatives 1,838,941   —   1,838,941   —   1,838,941 Pipeline and other 12,649   161,395   174,044   ( 148,830 ) 25,214 Total operating revenues 6,896,358   161,395   7,057,753   ( 148,830 ) 6,908,923 Operating expenses (a): Transportation and processing 2,306,090   —   2,306,090   ( 148,830 ) 2,157,260 Production 239,001   —   239,001   —   239,001 Operating and maintenance —   15,699   15,699   —   15,699 Exploration 3,330   —   3,330   —   3,330 Selling, general and administrative (b) 236,171   —   236,171   —   236,171 Depreciation, depletion and amortization 1,705,311   17,066   1,722,377   9,765   1,732,142 Loss on sale/exchange of long-lived assets 17,445   —   17,445   —   17,445 Impairment and expiration of leases 109,421   —   109,421   —   109,421 Other operating expenses (c) 9,177   —   9,177   74,866   84,043 Total operating expenses 4,625,946   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. 105 Table of Contents Reconciliation of total segment operating income to consolidated income before income taxes Years Ended December 31, 2025 2024 2023 (Thousands) Total segment operating income $ 3,530,017   $ 1,075,902   $ 2,399,042 Less: Intersegment eliminations 2,303   457   — Unallocated amounts: Unallocated other revenues ( 136 ) ( 34 ) — Corporate selling, general and administrative 58,282   36,254   — Corporate depreciation and amortization 23,214   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 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 (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. Upstream Gathering Transmission Total 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 assets 24,295,091   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 assets 22,546,098   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. 106 Table of Contents Reconciliation of total segment assets to consolidated total assets December 31, 2025 2024 2023 (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 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 (a) 830,679   861,739   — Regulatory asset from deferred taxes 139,221   142,757   — Other 170,534   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, 2025 2024 2023 (Thousands) Upstream $ 1,878,052   $ 2,003,635   $ 1,878,417 Gathering 367,697   202,264   31,701 Transmission 51,769   31,446   — Total segment capital expenditures 2,297,518   2,237,345   1,910,118 Other corporate items 26,119   28,603   15,125 Total capital expenditures $ 2,323,637   $ 2,265,948   $ 1,925,243 3.     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. 107 Table of Contents 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. 108 Table of Contents 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, 2025 2024 2023 (Thousands) Revenues from contracts with customers: Upstream sales Natural gas $ 7,018,766   $ 4,224,882   $ 4,520,817 NGLs 620,384   615,933   427,760 Oil 87,562   93,551   96,191 Sales of natural gas, NGLs and oil 7,726,712   4,934,366   5,044,768 Gathering pipeline revenue Firm reservation fee (a) 632,916   313,987   — Volumetric-based fee 668,518   452,476   161,395 Total Gathering pipeline revenue 1,301,434   766,463   161,395 Transmission pipeline revenue Firm reservation fee 435,194   183,088   — Volumetric-based fee 137,058   35,205   — Total Transmission pipeline revenue 572,252   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 derivatives 290,994   51,117   1,838,941 Other revenues 6,351   7,587   12,649 Total other sources of revenue 297,345   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. 109 Table of Contents 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. 2026 2027 2028 2029 2030 Thereafter Total (Thousands) Upstream natural gas sales $ 4,597   $ 1,978   $ —   $ —   $ —   $ —   $ 6,575 Gathering firm reservation fee revenue: Third-party 100,794   85,998   85,998   85,998   85,998   287,261   732,047 Affiliate 101,792   101,450   97,701   97,701   103,977   1,403,698   1,906,319 Total 202,586   187,448   183,699   183,699   189,975   1,690,959   2,638,366 Gathering revenue supported by MVCs: Third-party 96,377   89,203   80,536   67,311   56,762   132,254   522,443 Affiliate 397,966   410,621   411,740   410,622   408,322   1,634,128   3,673,399 Total 494,343   499,824   492,276   477,933   465,084   1,766,382   4,195,842 Transmission firm reservation fee revenue: Third-party 185,328   176,986   171,814   169,198   165,686   660,199   1,529,211 Affiliate 253,089   262,637   260,776   260,445   260,445   1,704,604   3,001,996 Total 438,417   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. 4.     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. 110 Table of Contents 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. 111 Table of Contents 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 value 137,299   ( 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 value 446,519   ( 117,350 ) ( 86,975 ) 242,194 5.     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 Sheets Quoted 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 value 137,299   39,164   98,135   — December 31, 2024 Asset derivative instruments, at fair value $ 143,581   $ 50,300   $ 93,281   $ — Liability derivative instruments, at fair value 446,519   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. 112 Table of Contents 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. 6.     Income Taxes The following table summarizes the Company's income tax expense. Years Ended December 31, 2025 2024 2023 (Thousands) 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 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. 113 Table of Contents The table below summarizes income tax payments, net of refunds. Years Ended December 31, 2025 2024 2023 (Thousands) Federal $ ( 81,195 ) $ 12,149   $ 12,876 State: Mississippi * * 670 Pennsylvania * ( 4,114 ) * Other U.S. states 2,173   ( 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, 2025 2024 2023 Amount Rate Amount Rate Amount Rate (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   —   % Other 977   —   % 818   0.3   % 1,301   0.1   % Nontaxable or nondeductible items: Transaction costs —   —   % 6,041   2.3   % —   —   % Other 1,814   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. 114 Table of Contents 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, 2025 2024 (Thousands) 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 —   80,723 Other —   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 ) — 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. 115 Table of Contents 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, 2025 2024 (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. 116 Table of Contents The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, excluding interest and penalties. 2025 2024 2023 (Thousands) 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 ) 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, 2025 2024 2023 (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 NOLs 50,612   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. 117 Table of Contents 7.     Debt The table below summarizes the Company's outstanding debt. December 31, 2025 December 31, 2024 Principal Value Carrying Value (a) Fair Value (b) Principal Value Carrying 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 debt 7,855,486   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. 118 Table of Contents Debt Repayments . The Company repaid, redeemed or repurchased the following debt during the year ended December 31, 2025. Debt Tranche Principal Premiums Paid/(Discounts Received) Accrued But Unpaid Interest Total 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. 119 Table of Contents 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. 120 Table of Contents 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. 121 Table of Contents 8.     Investments in Unconsolidated Entities Equity Method Investments The table below summarizes the Company's equity method investments. December 31, 2025 December 31, 2024 Ownership Interest Carrying Value Ownership Interest Carrying Value (Thousands) (Thousands) MVP Joint Venture (a): MVP A 49.3   % $ 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 Venture 3,514,803   3,534,730 Laurel Mountain Midstream, LLC (b) 31.0   % 47,037   31.0   % 28,757 Other 35,724   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, 2025 July 22, 2024 to December 31, 2024 (Thousands) Operating revenues $ 565,312   $ 247,360 Operating income 270,095   126,202 Net income 275,419   129,773 122 Table of Contents December 31, 2025 2024 (Thousands) Current assets $ 129,883   $ 204,028 Noncurrent assets 9,419,089   9,535,975 Total assets $ 9,548,972   $ 9,740,003 Current liabilities $ 24,218   $ 69,303 Noncurrent liabilities 4,629   1,514 Total liabilities 28,847   70,817 Members' equity 9,520,125   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. 123 Table of Contents 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. 9.     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. 124 Table of Contents 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. 10.     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. 125 Table of Contents The table below provides the computation for basic and diluted income per share. Years Ended December 31, 2025 2024 2023 (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 – Basic 611,571   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 – Diluted 615,717   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 11.     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. 126 Table of Contents 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 Cash 473,360 Total consideration $ 1,944,725 Fair value of assets acquired: 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 Fair value of liabilities assumed: Accounts payable $ 3,082 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 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. 127 Table of Contents 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 derivatives 31,257 Pipeline and other 4,559 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. 128 Table of Contents 12.     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. 13.     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. 129 Table of Contents 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. 130 Table of Contents 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. 14.     Share-Based Compensation Plans The following table summarizes the Company's share-based compensation expense. Years Ended December 31, 2025 2024 2023 (Thousands) Incentive Performance Share Unit Programs $ 14,505   $ 20,919   $ 23,915 Restricted stock awards 41,310   25,473   20,119 Stock appreciation rights —   —   4,056 Other programs, including non-employee director awards 3,784   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. 131 Table of Contents 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 Settled Nonvested Shares Weighted Average Fair Value Aggregate Fair Value Outstanding at January 1, 2023 2,861,990   $ 16.66   $ 47,674,881 Granted in Period 404,790   38.79   15,701,804 Granted from Multiplier 409,383   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 Period 371,500   40.08   14,889,720 Granted from Multiplier 451,805   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 Period 377,570   74.14   27,993,040 Granted from Multiplier 649,020   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, 2025 2024 2023 (a) 2022 2021 (a) Risk-free 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 3 years 3 years 3 years 3 years 3 years (a) There were two grant dates for the 2023 Incentive PSU Program and the 2021 Incentive PSU Program. Amounts shown represent weighted average. 132 Table of Contents 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 Settled Nonvested Shares Weighted Average Fair Value Aggregate Fair Value Outstanding at January 1, 2023 2,926,945   $ 16.67   $ 48,792,574 Granted 953,270   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 Granted 982,990   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 Granted 1,720,700   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. 133 Table of Contents 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 rate 1.10   % Dividend yield —   % Volatility factor 60.00   % Expected term 4 years Number of Options Granted 1,000,000 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 Options Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2025 1,195,336   $ 12.14 Exercised ( 95,874 ) 23.93 Outstanding and Exercisable at December 31, 2025 1,099,462   $ 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. 134 Table of Contents 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. 15.     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, 2025 2024 2023 (Thousands) 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 (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, 2025 2024 2023 (Thousands) Operating lease liabilities $ 21,155   $ 13,595   $ 10,078 Finance lease liabilities 6,347   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. 135 Table of Contents 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, 2025 2024 (Thousands) Right-of-Use Assets Operating $ 74,111   $ 60,496 Finance 35,650   34,803 Total right-of-use assets $ 109,761   $ 95,299 Lease Liabilities Current lease liabilities Operating $ 51,042   $ 36,275 Finance 7,082   5,603 Total current lease liabilities 58,124   41,878 Noncurrent lease liabilities Operating 27,369   29,391 Finance 29,973   29,263 Total noncurrent lease liabilities 57,342   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 2027 10,859   8,355   19,214 2028 7,915   7,058   14,973 2029 5,972   5,879   11,851 2030 4,885   4,697   9,582 Thereafter 350   7,705   8,055 Total lease payment obligations 83,620   42,416   126,036 Less: Imputed interest 5,209   5,361   10,570 Present value of lease liabilities $ 78,411   $ 37,055   $ 115,466 16.     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. 136 Table of Contents 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. 17.     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, 2025 2024 (Thousands) 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 depreciation and depletion 14,344,974   12,489,317 Net capitalized costs $ 22,440,936   $ 21,060,596 137 Table of Contents Years Ended December 31, 2025 2024 2023 (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 Exploration 3,601   2,735   3,330 Development 1,725,438   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, 2025 2024 2023 (Thousands) Sales of natural gas, NGLs and oil $ 7,726,712   $ 4,934,366   $ 5,044,768 Transportation and processing 1,532,090   1,915,616   2,157,260 Production 388,696   377,007   254,700 Operating and maintenance 23,013   37,951   — 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   $ 583,007 138 Table of Contents 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, 2025 2024 2023 (MMcfe) Natural gas, NGLs and oil Proved developed and undeveloped reserves: Balance at January 1 26,264,669   27,596,694   25,002,589 Revision of previous estimates ( 27,073 ) ( 1,079,677 ) ( 1,402,039 ) Purchase of hydrocarbons in place 1,768,560   413,040   2,600,667 Sale of hydrocarbons in place ( 22,027 ) ( 1,562,849 ) — Extensions, discoveries and other additions 2,444,717   3,125,620   3,411,750 Production ( 2,382,367 ) ( 2,228,159 ) ( 2,016,273 ) Balance at December 31 28,046,479   26,264,669   27,596,694 Proved developed reserves: Balance at January 1 18,804,929   19,558,176   17,513,645 Balance at December 31 20,580,992   18,804,929   19,558,176 Proved undeveloped reserves: Balance at January 1 7,459,740   8,038,518   7,488,944 Balance at December 31 7,465,487   7,459,740   8,038,518 139 Table of Contents Years Ended December 31, 2025 2024 2023 (MMcf) Natural gas Proved developed and undeveloped reserves: Balance at January 1 24,545,229   25,795,134   23,824,887 Revision of previous estimates ( 15,493 ) ( 917,676 ) ( 1,461,305 ) Purchase of natural gas in place 1,768,120   395,423   2,012,159 Sale of natural gas in place ( 16,145 ) ( 1,562,849 ) — Extensions, discoveries and other additions 2,373,231   2,921,638   3,326,736 Production ( 2,238,652 ) ( 2,086,441 ) ( 1,907,343 ) Balance at December 31 26,416,290   24,545,229   25,795,134 Proved developed reserves: Balance at January 1 17,440,191   18,186,432   16,541,017 Balance at December 31 19,237,547   17,440,191   18,186,432 Proved undeveloped reserves: Balance at January 1 7,105,038   7,608,702   7,283,870 Balance at December 31 7,178,743   7,105,038   7,608,702 Years Ended December 31, 2025 2024 2023 (Mbbl) NGLs 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 NGLs in place 73   2,529   90,604 Sale of NGLs in place ( 902 ) —   — 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   66,822 140 Table of Contents Years Ended December 31, 2025 2024 2023 (Mbbl) Oil 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 oil in place —   407   7,481 Sale of oil in place ( 78 ) —   — 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 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. 141 Table of Contents 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. 142 Table of Contents 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, 2025 2024 2023 (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 flows 43,263,471   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, 2025 2024 2023 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. 143 Table of Contents The following table summarizes the changes in the standardized measure of discounted future net cash flows. Years Ended December 31, 2025 2024 2023 (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 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 ) — 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 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. 144 Table of Contents Item 9.        Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable. Item 9A.    Controls and Procedures Evaluation of Disclosure Controls and Procedures Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was conducted as of the end of the period covered by this report. Based on that evaluation, the principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report. Management's Report on Internal Control over Financial Reporting Management is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act). Our internal control system is designed to provide reasonable assurance to management and our Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2025. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on this assessment, our management concluded that we maintained effective internal control over financial reporting as of December 31, 2025. Ernst & Young LLP (Ernst & Young), the independent registered public accounting firm that audited our Consolidated Financial Statements, has issued an attestation report on our internal control over financial reporting. Ernst & Young's attestation report on our internal control over financial reporting appears in Part II, Item 8., of this Annual Report on Form 10-K and is incorporated herein by reference. Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Item 9B.    Other Information During the fourth quarter of 2025, none of our directors or "officers" (as such term is defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" (as each term is defined in Item 408(a) of Regulation S-K). Item 9C.    Disclosure Regarding Foreign Jurisdictions that Prevent Inspections Not applicable. 145 Table of Contents PART III Item 10.        Directors, Executive Officers and Corporate Governance The following information is incorporated herein by reference from our definitive proxy statement relating to the 2026 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the end of our fiscal year ended December 31, 2025: • Information required by Item 401 of Regulation S-K with respect to directors; • Information required by Item 405 of Regulation S-K with respect to non-compliance with Section 16(a) of the Exchange Act, if any; • Information required by Item 407(d)(4) of Regulation S-K with respect to our separately-designated standing Audit Committee and the members of the Audit Committee; • Information required by Item 407(d)(5) of Regulation S-K with respect to our audit committee financial expert; and • Information required by Item 408(b) of Regulation S-K with respect to our insider trading policy. Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Annual Report on Form 10-K under the caption "Information about Our Executive Officers (as of February 18, 2026)." We have adopted a code of business conduct and ethics applicable to all directors and employees, including the principal executive officer, principal financial officer and principal accounting officer. Our code of business conduct and ethics is posted on our website https://www.eqt.com (accessible by clicking on the "Investors" link on the main page, followed by the "Governance" heading, then the "Governance Documents" link), and a printed copy will be delivered free of charge on request by writing to the Corporate Secretary at EQT Corporation, c/o Corporate Secretary, 625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222. We intend to satisfy the disclosure requirement regarding certain amendments to, or waivers from, provisions of our code of business conduct and ethics by posting such information on our website. Item 11.        Executive Compensation The following information is incorporated herein by reference from our definitive proxy statement relating to the 2026 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the end of our fiscal year ended December 31, 2025: • Information required by Item 402 of Regulation S-K with respect to named executive officer and director compensation; and • Information required by paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K with respect to certain matters related to the Management Development and Compensation Committee of our Board of Directors. Item 12.        Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference from our definitive proxy statement relating to the 2026 annual meeting of shareholders, which is expected to be filed with the SEC within 120 days after the end of our fiscal year ended December 31, 2025. 146 Table of Contents Equity Compensation Plan Information The following table and related footnotes provide information as of December 31, 2025 with respect to shares of EQT common stock that may be issued under our existing equity compensation plans, including the 2020 Long-Term Incentive Plan (2020 LTIP), 2019 Long-Term Incentive Plan (2019 LTIP), 2014 Long-Term Incentive Plan (2014 LTIP), 2009 Long-Term Incentive Plan (2009 LTIP), 2025 Employee Stock Purchase Plan (2025 ESPP), 2008 Employee Stock Purchase Plan (2008 ESPP), and 2005 Directors' Deferred Compensation Plan (2005 DDCP): Plan Category   Number Of Securities To Be Issued Upon Exercise Of Outstanding Options, Warrants and Rights (A)    Weighted Average Exercise Price Of Outstanding Options, Warrants and Rights (B)     Number Of Securities Remaining Available For Future Issuance Under Equity Compensation Plans, Excluding Securities Reflected In Column A (C) Equity Compensation Plans Approved by Shareholders (1)   3,615,911  (2) $ 11.11  (3) 15,467,559  (4) Equity Compensation Plans Not Approved by Shareholders (5)   69,795  (6) N/A   93,221  (7) Total 3,685,706  $ 11.11  15,560,780 (1) Consists of the 2020 LTIP, 2019 LTIP, 2014 LTIP, 2009 LTIP, the 2025 ESPP and the 2008 ESPP. Effective as of May 1, 2020, in connection with the adoption of the 2020 LTIP, we ceased making new grants under the 2019 LTIP. Effective as of July 10, 2019 in connection with the adoption of the 2019 LTIP, we ceased making new grants under the 2014 LTIP. Effective as of April 30, 2014, in connection with the adoption of the 2014 LTIP, we ceased making new grants under the 2009 LTIP. The 2019 LTIP, 2014 LTIP, and the 2009 LTIP remain effective solely for the purpose of issuing shares upon the exercise or payout of awards outstanding under such plans on May 1, 2020 (for the 2019 LTIP), July 10, 2019 (for the 2014 LTIP) and April 30, 2014 (for the 2009 LTIP). (2) Consists of (i) 2,136,706 shares subject to outstanding performance awards under the 2020 LTIP, inclusive of dividend reinvestments thereon (counted at a 2X multiple assuming maximum performance is achieved under the awards (representing 1,068,353 target awards and dividend reinvestments thereon)), (ii) 315,315 shares subject to outstanding directors' deferred stock units under the 2020 LTIP, inclusive of dividend reinvestments thereon, (iii) 1,000,000 shares subject to outstanding stock options under the 2019 LTIP, (iv) 23,897 shares subject to outstanding directors' deferred stock units under the 2019 LTIP, inclusive of dividend reinvestments thereon, (v) 99,462 shares subject to outstanding stock options under the 2014 LTIP, (vi) 35,809 shares subject to outstanding directors' deferred stock units under the 2014 LTIP, inclusive of dividend reinvestments thereon; and (vii) 4,721 shares subject to outstanding directors' deferred stock units under the 2009 LTIP, inclusive of dividend reinvestments thereon. (3) The weighted-average exercise price is calculated solely based on outstanding stock options under the 2019 LTIP, 2014 LTIP and the 2009 LTIP and excludes deferred stock units under the 2020 LTIP, 2019 LTIP, 2014 LTIP and the 2009 LTIP and performance awards under the 2020 LTIP, 2019 LTIP and 2014 LTIP. The weighted average remaining term of the outstanding stock options was 1.3 years as of December 31, 2025. (4) Consists of (i) 14,467,559 shares available for future issuance under the 2020 LTIP and (ii) 1,000,000 shares available for future issuance under the 2025 ESPP in which the first purchase commenced in January 2026. (5) Consists of the 2005 DDCP, which is described below, and the legacy Equitrans Midstream Corporation Directors Deferred Compensation Plan (the Equitrans DDCP). (6) Consists entirely of shares invested in the EQT common stock fund, payable in shares of common stock, allocated to non-employee directors' accounts under the 2005 DDCP and the Equitrans DDCP as of December 31, 2025. (7) Consists entirely of shares available for future issuance under the 2005 DDCP as of December 31, 2025. 2005 Directors' Deferred Compensation Plan The 2005 DDCP was adopted by the Compensation Committee, effective January 1, 2005. Neither the original adoption of the plan nor its amendments required approval by our shareholders. The plan allows non-employee directors to defer all or a portion of their directors' fees and retainers. Amounts deferred are payable on or following retirement from our Board of Directors unless an early payment is authorized after the director suffers an unforeseeable financial emergency. In addition to deferred directors' fees and retainers, the deferred stock units granted to directors on or after January 1, 2005 under the 2009 LTIP and the 2014 LTIP are administered under this plan. 147 Table of Contents Item 13.        Certain Relationships and Related Transactions, and Director Independence Information required by Items 404 and 407(a) of Regulation S-K with respect to related person transactions and director independence is incorporated herein by reference from our definitive proxy statement relating to the 2026 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the end of our fiscal year ended December 31, 2025. Item 14.        Principal Accountant Fees and Services Information required by Item 9(e) of Schedule 14A with respect to our principal accountant's fees and services is incorporated herein by reference from our definitive proxy statement relating to the 2026 annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the end of our fiscal year ended December 31, 2025. 148 Table of Contents PART IV Item 15.        Exhibits and Financial Statements Schedules (a) 1 Financial Statements Page Reference Statements of Consolidated Operations 88 Statements of Consolidated Comprehensive Income 89 Consolidated Balance Sheets 90 Statements of Consolidated Cash Flows 91 Statements of Consolidated Equity 92 Notes to the Consolidated Financial Statements 93 2 Financial Statements Schedule Schedule II – Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 2025 EQT CORPORATION AND SUBSIDIARIES SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 2025 Column A Column B Column C Column D Column E Description Balance at Beginning of Period Additions Charged to Costs and Expenses Deductions Charged to Other Accounts Deductions Balance 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. 149 Table of Contents 3 Exhibits Exhibit Description Method of Filing 2.01(a)+ Amended and Restated Purchase Agreement, dated December 23, 2022, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation. Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on December 27, 2022. 2.01(b) First Amendment to Amended and Restated Purchase Agreement, dated April 21, 2023, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation. Incorporated herein by reference to Exhibit 2.2 to Form 8-K (#001-3551) filed on August 22, 2023. 2.01(c) Second Amendment to Amended and Restated Purchase Agreement, dated August 21, 2023, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation. Incorporated herein by reference to Exhibit 2.3 to Form 8-K (#001-3551) filed on August 22, 2023. 2.02+ Agreement and Plan of Merger, dated March 10, 2024, among EQT Corporation, Humpty Merger Sub Inc., Humpty Merger Sub LLC and Equitrans Midstream Corporation. Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on March 11, 2024. 2.03+ Contribution Agreement, dated November 22, 2024, among PipeBox LLC, EQM Midstream Partners, LP, EQM Gathering OpCo, LLC, MVP HoldCo, LLC and Pibb Member LLC. Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on November 26, 2024. 3.01(a) Restated Articles of Incorporation of EQT Corporation (as amended through November 13, 2017). Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on November 14, 2017. 3.01(b) Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective May 1, 2020). Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on May 4, 2020. 3.01(c) Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective July 23, 2020). Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on July 23, 2020. 3.01(d) Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective July 18, 2024). Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on July 18, 2024. 3.02 Amended and Restated Bylaws of EQT Corporation (as amended through October 16, 2025). Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on October 20, 2025. 4.01 Description of Capital Stock. Incorporated herein by reference to Exhibit 4.01 to Form 10-K (#001-3551) for the year ended December 31, 2021. 4.02(a) Indenture, dated July 1, 1996, between EQT Corporation (as successor to Equitable Resources, Inc.) and The Bank of New York (as successor to Bank of Montreal Trust Company), as trustee. Incorporated herein by reference to Exhibit 4.01(a) to Form S-4 Registration Statement (#333-103178) filed on February 13, 2003. 4.02(b) Resolutions adopted January 18 and July 18, 1996 by the Board of Directors of Equitable Resources, Inc. and Resolution adopted July 18, 1996 by the Executive Committee of the Board of Directors of Equitable Resources, Inc., establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996. Incorporated herein by reference to Exhibit 4.01(j) to Form 10-K (#001-3551) for the year ended December 31, 1996. 4.02(c) First Supplemental Indenture, dated June 30, 2008, between EQT Corporation, Equitable Resources, Inc., and The Bank of New York, as trustee, pursuant to which EQT Corporation assumed the obligations of Equitable Resources, Inc. under the related Indenture. Incorporated herein by reference to Exhibit 4.02(f) to Form 8-K (#001-3551) filed on July 1, 2008. 4.03(a) Indenture, dated March 18, 2008, between EQT Corporation (as successor to Equitable Resources, Inc.) and The Bank of New York, as trustee. Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-3551) filed on March 18, 2008. 150 Table of Contents Exhibit Description Method of Filing 4.03(b) Cross-reference table for Indenture dated March 18, 2008 (listed as Exhibit 4.04(a) above) and the Trust Indenture Act of 1939, as amended. Incorporated herein by reference to Exhibit 4.03(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. 4.03(c) Second Supplemental Indenture, dated June 30, 2008, between EQT Corporation, Equitable Resources, Inc. and The Bank of New York, as trustee, pursuant to which EQT Corporation assumed the obligations of Equitable Resources, Inc. under the related Indenture. Incorporated herein by reference to Exhibit 4.03(c) to Form 8-K (#001-3551) filed on July 1, 2008. 4.03(d) Eighth Supplemental Indenture, dated October 4, 2017, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 3.900% Senior Notes due 2027 were issued. Incorporated herein by reference to Exhibit 4.9 to Form 8-K (#001-3551) filed on October 4, 2017. 4.03(e) Tenth Supplemental Indenture, dated January 21, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 7.000% Senior Notes due 2030 were issued. Incorporated herein by reference to Exhibit 4.5 to Form 8-K (#001-3551) filed on January 21, 2020. 4.03(f) Eleventh Supplemental Indenture, dated November 16, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 5.00% Senior Notes due 2029 were issued. Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on November 16, 2020. 4.03(g) Twelfth Supplemental Indenture, dated May 17, 2021, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 3.125% Senior Notes due 2026 were issued. Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on May 18, 2021. 4.03(h) Thirteenth Supplemental Indenture, dated May 17, 2021, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 3.625% Senior Notes due 2031 were issued. Incorporated herein by reference to Exhibit 4.4 to Form 8-K (#001-3551) filed on May 18, 2021. 4.03(i) Fifteenth Supplemental Indenture, dated October 4, 2022, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 5.700% Senior Notes due 2028 were issued. Incorporated herein by reference to Exhibit 4.5 to Form 8-K (#001-3551) filed on October 4, 2022. 4.03(j) Sixteenth Supplemental Indenture, dated May 10, 2023, between EQT Corporation and The Bank of New York Mellon, as trustee, relating to EQT Corporation’s 5.700% Senior Notes due 2028. Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-3551) filed on May 11, 2023. 4.03(k) Seventeenth Supplemental Indenture, dated January 19, 2024, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 5.750% Senior Notes due 2034 were issued. Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on January 19, 2024. 4.03(l) Nineteenth Supplemental Indenture, dated as of April 2, 2025, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 6.500% Senior Notes due 2027 were issued. Incorporated herein by reference to Exhibit 4.5 to Form 8-K (#001-3551) filed on April 3, 2025. 4.03(m) Twentieth Supplemental Indenture, dated as of April 2, 2025, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 5.500% Senior Notes due 2028 were issued. Incorporated herein by reference to Exhibit 4.7 to Form 8-K (#001-3551) filed on April 3, 2025. 4.03(n) Twenty-First Supplemental Indenture, dated as of April 2, 2025, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 4.50% Senior Notes due 2029 were issued. Incorporated herein by reference to Exhibit 4.9 to Form 8-K (#001-3551) filed on April 3, 2025. 4.03(o) Twenty-Second Supplemental Indenture, dated as of April 2, 2025, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 6.375% Senior Notes due 2029 were issued. Incorporated herein by reference to Exhibit 4.11 to Form 8-K (#001-3551) filed on April 3, 2025. 4.03(p) Twenty-Third Supplemental Indenture, dated as of April 2, 2025, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 7.500% Senior Notes due 2030 were issued. Incorporated herein by reference to Exhibit 4.13 to Form 8-K (#001-3551) filed on April 3, 2025. 151 Table of Contents Exhibit Description Method of Filing 4.03(q) Twenty-Fourth Supplemental Indenture, dated as of April 2, 2025, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 4.75% Senior Notes due 2031 were issued. Incorporated herein by reference to Exhibit 4.15 to Form 8-K (#001-3551) filed on April 3, 2025. 4.03(r) Twenty-Fifth Supplemental Indenture, dated as of April 2, 2025, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which EQT Corporation's 6.500% Senior Notes due 2048 were issued. Incorporated herein by reference to Exhibit 4.17 to Form 8-K (#001-3551) filed on April 3, 2025. 10.01+ Fourth Amended and Restated Credit Agreement, dated July 22, 2024, among EQT Corporation, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and L/C Issuer, and the other lenders party thereto. Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on July 22, 2024 10.02(a)+ Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated April 6, 2018, by and among MVP Holdco, LLC, US Marcellus Gas Infrastructure, LLC, WGL Midstream MVP LLC (formerly WGL Midstream, Inc.), Con Edison Gas Pipeline and Storage, LLC, RGC Midstream, LLC and Mountain Valley Pipeline, LLC. Incorporated herein by reference to Exhibit 10.1 to EQM Midstream Partners, LP's Form 10-Q/A (#001-35574) for the quarter ended March 31, 2018. 10.02(b) First Amendment to Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated April 6, 2018, adopted, executed and agreed as of February 5, 2020. Incorporated herein by reference to Exhibit 10.21(b) to Equitrans Midstream Corporation's Form 10-K (#001-38629) for the year ended December 31, 2019. 10.02(c)+ Second Amendment to Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated April 6, 2018, adopted, executed and agreed as of November 1, 2025. Filed herewith as Exhibit 10.02(c). 10.03(a)+ Amended and Restated Limited Liability Company Agreement of PipeBox LLC, dated December 30, 2024. Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on December 31, 2024. 10.03(b) First Amendment to the Amended and Restated Limited Liability Company Agreement of PipeBox LLC, dated January 16, 2026. Filed herewith as Exhibit 10.03(b). 10.04 Registration Rights Agreement, dated July 1, 2025, by and among EQT Corporation and certain security holders thereof party thereto, including Olympus Energy Holdings LLC, HNP Holdco LP and HNP Holdco II LLC. Incorporated herein by reference to Exhibit 4.3 to Form S-3ASR Registration Statement (333-288464) filed on July 2, 2025. 10.05(a) Equitrans Midstream Corporation Amended and Restated Directors' Deferred Compensation Plan. Incorporated herein by reference to Exhibit 10.18 to Equitrans Midstream Corporation’s Form 10-Q (#001-38629) for the quarter ended March 31, 2020. 10.05(b)* Form of Equitrans Midstream Corporation Director Participant Award Agreement Incorporated herein by reference to Exhibit 10.10 to Equitrans Midstream Corporation’s Form 10-Q (#001-38629) for the quarter ended March 31, 2019. 10.06(a)* EQT Corporation 2009 Long-Term Incentive Plan (as amended and restated through July 11, 2012). Incorporated herein by reference to Exhibit 10.2 to Form 10-Q (#001-3551) for the quarter ended June 30, 2012. 10.06(b)* Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2009 Long-Term Incentive Plan (pre-2013 grants). Incorporated herein by reference to Exhibit 10.02(b) to Form 10-K (#001-3551) for the year ended December 31, 2012. 10.06(c)* Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2009 Long-Term Incentive Plan (2013 and 2014 grants). Incorporated herein by reference to Exhibit 10.02(s) to Form 10-K (#001-3551) for the year ended December 31, 2012. 10.07(a)* EQT Corporation 2014 Long-Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 1, 2014. 10.07(b)* Form of Participant Award Agreement (Phantom Stock Unit Awards) under 2014 Long-Term Incentive Plan. Incorporated herein by reference to Exhibit 10.03(b) to Form 10-K (#001-3551) for the year ended December 31, 2014. 152 Table of Contents Exhibit Description Method of Filing 10.08(a)* EQT Corporation 2019 Long-Term Incentive Plan. Incorporated herein by reference to Exhibit 99.1 to Form S-8 (#001-3551) filed on July 15, 2019. 10.08(b)* Form of Restricted Stock Unit Award Agreement (Standard) under 2019 Long-Term Incentive Plan. Incorporated herein by reference to Exhibit 10.06(c) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.08( c )* Form of Participant Award Agreement (Stock Option) under 2019 Long-Term Incentive Plan. Incorporated herein by reference to Exhibit 10.06(g) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.09(a)* EQT Corporation 2020 Long-Term Incentive Plan. Incorporated herein by reference to Exhibit 99.1 to Form S-8 (#333-237953) filed on May 1, 2020. 10.09(b)* Amendment to EQT Corporation 2020 Long-Term Incentive Plan. Incorporated by reference to Exhibit 99.2 to Form S-8 (#333-264423) filed on April 21, 2022. 10.09(c)* Second Amendment to the EQT Corporation 2020 Long-Term Incentive Plan. Incorporated herein by reference to Exhibit 10.3 to Form 8-K (#001-3551) filed on July 22, 2024. 10.10(a)* Form of Restricted Stock Unit Award Agreement (Standard) Incorporated herein by reference to Exhibit 10.10(a) to Form 10-K (#001-3551) for the year ended December 31, 2020. 10.10( b )* Form of Restricted Stock Unit Award Agreement (Non-Employee Directors). Incorporated herein by reference to Exhibit 10.06(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.11* Form of EQT Corporation Short-Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 4, 2020. 10.12(a)* Form of Incentive Performance Share Unit Program. Incorporated herein by reference to Exhibit 10.12(a) to Form 10-K (#001-3551) for the year ended December 31, 2020. 10.12(b)* Form of Participant Award Agreement under Incentive Performance Share Unit Program. Incorporated herein by reference to Exhibit 10.12(b) to Form 10-K (#001-3551) for the year ended December 31, 2020. 10.13* Form of Participant Award Agreement (Stock Option). Incorporated herein by reference to Exhibit 10.06(g) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.14* EQT Corporation Executive Severance Plan and Form of Participation Notice. Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on May 20, 2020. 10.15(a)* 2005 Directors' Deferred Compensation Plan (as amended and restated December 3, 2014). Incorporated herein by reference to Exhibit 10.09 to Form 10-K (#001-3551) for the year ended December 31, 2014. 10.15(b)* Amendment to 2005 Directors' Deferred Compensation Plan (as amended October 2, 2018). Incorporated herein by reference to Exhibit 10.5 to Form 10-Q (#001-3551) for the quarter ended September 30, 2018. 10.16* Form of Indemnification Agreement between EQT Corporation and executive officers and outside directors. Incorporated herein by reference to Exhibit 10.18 to Form 10-K (#001-3551) for the year ended December 31, 2008. 10.17* Separation and Release Agreement, dated November 13, 2017, among EQT Corporation, EQT RE, LLC and Daniel J. Rice IV. Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on November 17, 2017. 153 Table of Contents Exhibit Description Method of Filing 10.18(a)* Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam. Incorporated herein by reference to Exhibit 10.9 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on November 13, 2018. 10 .1 8 (b)* First Amendment, dated February 20, 2023, to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam. Incorporated herein by reference to Exhibit 10.15(b) to Equitrans Midstream Corporation’s Form 10-K (#001-38629) for the year ended December 31, 2022. 10.18(c)* Second Amendment, effective September 6, 2023, to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam. Incorporated herein by reference to Exhibit 10.3 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on September 7, 2023. 10.18(d)* Transition Agreement, dated September 6, 2023, between Equitrans Midstream Corporation and Thomas F. Karam. Incorporated herein by reference to Exhibit 10.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on September 7, 2023. 10.18(e)+ Separation Agreement and General Release, dated August 14, 2024, between EQT Corporation and Thomas F. Karam. Incorporated herein by reference to Exhibit 10.06(e) to Form 10-Q (#001-3551) for the quarter ended September 30, 2024. 10.19 Offer Letter, dated January 6, 2020, between EQT Corporation and William E. Jordan. Incorporated herein by reference to Exhibit 10.29(a) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.20(a)* Offer Letter, dated July 18, 2019, between EQT Corporation and Richard Anthony Duran. Incorporated herein by reference to Exhibit 10.30(a) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.20(b)* Confidentiality, Non-Solicitation and Non-Competition Agreement, dated August 5, 2019, between EQT Corporation and Richard Anthony Duran. Incorporated herein by reference to Exhibit 10.30(b) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.20(c)* Relocation Expense Reimbursement Agreement, dated July 24, 2019, between EQT Corporation and Richard Anthony Duran. Incorporated herein by reference to Exhibit 10.30(c) to Form 10-K (#001-3551) for the year ended December 31, 2019. 10.21* Offer Letter, dated July 16, 2019, between EQT Corporation and Lesley Evancho. Incorporated herein by reference to Exhibit 10.31(a) to Form 10-K (#001-3551) for the year ended December 31, 2019. 19 EQT Corporation Insider Trading Policy Incorporated herein by reference to Exhibit 19 to Form 10-K (#001-3551) for the year ended December 31, 2024. 21 Schedule of Subsidiaries. Filed herewith as Exhibit 21. 23.01 Consent of Independent Registered Public Accounting Firm. Filed herewith as Exhibit 23.01. 23.02 Consent of Netherland, Sewell & Associates, Inc. Filed herewith as Exhibit 23.02. 31.01 Rule 13(a)-14(a) Certification of Principal Executive Officer. Filed herewith as Exhibit 31.01. 31.02 Rule 13(a)-14(a) Certification of Principal Financial Officer. Filed herewith as Exhibit 31.02. 32 Section 1350 Certification of Principal Executive Officer and Principal Financial Officer. Furnished herewith as Exhibit 32. 97 EQT Corporation Clawback Policy. Incorporated herein by reference to Exhibit 97 to Form 10-K (#001-3551) for the year ended December 31, 2023. 99 Independent Petroleum Engineers' Audit Report. Filed herewith as Exhibit 99 101 Interactive Data File. Filed herewith as Exhibit 101. 154 Table of Contents Exhibit Description Method of Filing 104 Cover Page Interactive Data File Formatted as Inline XBRL and contained in Exhibit 101. *Management contract or compensatory plan or arrangement. +Certain schedules and similar attachments to this exhibit have been omitted pursuant to Item 601(a)(5) and/or Item 601(b)(10)(iv), as applicable, of Regulation S-K. EQT Corporation agrees to furnish an unredacted, supplemental copy (including any omitted schedule or attachment) to the SEC upon request. Redactions and omissions are designated with brackets containing asterisks. Certain instruments evidencing long-term debt have not been filed as exhibits hereto because none of the debt authorized under any such instruments exceeds 10% of the Company's total assets. EQT Corporation agrees to furnish to the SEC, upon request, a copy of any such instruments. Item 16.        Form 10-K Summary None. 155 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. EQT CORPORATION By: /s/ Toby Z. Rice Toby Z. Rice President and Chief Executive Officer February 18, 2026 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/    TOBY Z. RICE   President,   February 18, 2026 Toby Z. Rice   Chief Executive Officer and (Principal Executive Officer)   Director /s/    JEREMY T. KNOP   Chief Financial Officer   February 18, 2026 Jeremy T. Knop (Principal Financial Officer) /s/    TODD M. JAMES   Chief Accounting Officer   February 18, 2026 Todd M. James (Principal Accounting Officer) /s/    VICKY A. BAILEY   Director   February 18, 2026 Vicky A. Bailey /s/    LEE M. CANAAN   Director   February 18, 2026 Lee M. Canaan /s/    FRANK C. HU Director February 18, 2026 Frank C. Hu /s/    KATHRYN J. JACKSON Director   February 18, 2026 Kathryn J. Jackson /s/    THOMAS F. KARAM Chair February 18, 2026 Thomas F. Karam /s/    JOHN F. MCCARTNEY Director February 18, 2026 John F. McCartney /s/    DANIEL J. RICE IV   Director   February 18, 2026 Daniel J. Rice IV /s/    ROBERT F. VAGT Director February 18, 2026 Robert F. Vagt /s/    HALLIE A. VANDERHIDER   Director   February 18, 2026 Hallie A. Vanderhider 156