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Item 7. Management’s Discussion and Analysis

2026-02-18 compared with 2025-02-19 · 261 added, 246 removed, 227 unchanged (69% of the section changed)

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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

On December 30, 2024, in connection with the completion of the Midstream Joint Venture Transaction, the Midstream Joint Venture received $3.5 billion of cash consideration, net of certain transaction fees and expenses, from a third-party investor in exchange for a noncontrolling equity interest in the Midstream Joint Venture.

We used the proceeds from the Midstream Joint Venture Transaction to repay outstanding borrowings under the Bridge Credit Facility (defined in Note 10 to the Consolidated Financial Statements) and the Term Loan Facility and a portion of outstanding borrowings under EQT's revolving credit facility.

Borrowings under the Bridge Credit Facility were used to fund the redemption and repurchase of certain of EQM's senior notes, including pursuant to the EQM Tender Offer (defined in Note 10 to the Consolidated Financial Statements).

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

Results of operations for 2024 include the results of our operation of assets received as consideration for the First NEPA Non-Operated Asset Divestiture, which closed on May 31, 2024.

Such assets received included the remaining 16.25% equity interest in the NEPA Gathering System (defined in Note 6 to the Consolidated Financial Statements) (which was the sole remaining minority interest following our acquisition of a 33.75% equity interest in the NEPA Gathering System Acquisition (defined in Note 6 to the Consolidated Financial Statements) on April 11, 2024), resulting in our 100% ownership of the NEPA Gathering System.

See Note 7 to the Consolidated Financial Statements.

In addition, on December 31, 2024, we completed the Second NEPA Non-Operated Asset Divestiture.

See Note 7 to the Consolidated Financial Statements.

We used the proceeds from the Second NEPA Non-Operated Asset Divestiture of $1.25 billion, subject to customary post-closing purchase price adjustments and transaction costs, to repay a portion of outstanding borrowings under EQT's revolving credit facility.

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

Results of operations for 2024 include the results of our operation of assets acquired in the Equitrans Midstream Merger, which closed on July 22, 2024.

Following the completion of the Equitrans Midstream Merger, we own a gathering system with 1,975 miles of gathering lines (including gathering lines owned prior to the Equitrans Midstream Merger) and a transmission and storage system with approximately 950 miles of FERC-regulated, interstate pipelines.

See Note 6 to the Consolidated Financial Statements.

For the period from July 22, 2024 through December 31, 2024, our consolidated gathering expense decreased due to our ownership of the gathering and transmission assets acquired in the Equitrans Midstream Merger.

Our ownership of such assets will continue to positively impact our Production segment's gathering expense, with a corresponding increase to our Production segment's affiliate transportation and processing expense, which is eliminated in consolidation.

This relationship will be prominent for full year 2025 results and beyond.

Tug Hill and XcL Midstream Acquisition

Results of operations for 2024 and the second half of 2023 include the results of our operation of assets acquired in the Tug Hill and XcL Midstream Acquisition (defined in Note 6 to the Consolidated Financial Statements), which closed on August 22, 2023.

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

On March 4, 2024, we announced our decision to strategically curtail approximately 1.0 Bcfe per day of gross production (the Strategic Curtailment) beginning on February 24, 2024 in response to the low natural gas price environment resulting from warm winter weather and elevated storage inventories.

The Strategic Curtailment resulted in total decreased sales volume of 107 Bcfe for 2024.

In addition, certain operators of wells in which we have a non-operating working interest also curtailed production in 2024.

For 2024, we estimate that our total expected sales volume was negatively impacted by approximately 130 to 140 Bcfe of curtailments, including our Strategic Curtailment of 107 Bcfe and curtailments by certain operators of wells in which we have a non-operating working interest.

Low natural gas prices or volatility in the natural gas market may result in adjustments to our 2025 planned development schedule or the development schedule of non-operated wells in which we have a working interest.

Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest.

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.

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.

In connection with the recent U.S.

election and corresponding inauguration of President Trump on January 20, 2025, the President 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 institution of tariffs on foreign goods and services.

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.

A changing regulatory environment could increase our costs to comply with such regulations or make us susceptible to lawsuits or fines for failure to comply with such regulations.

Further, tariffs on foreign goods and services could result in other countries instituting tariffs on U.S.

goods and services, which could impact the price of natural gas, increase the price of supplies and raw materials that we rely on to conduct our business, and could impact interest rates.

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.

Lastly, we expect commodity prices to be volatile through 2025 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical tensions, including developments pertaining to Russia's invasion of Ukraine, conflicts in 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.

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 decrease was attributable primarily to a lower gain on derivatives, increased depreciation, depletion and amortization, increased other operating expenses and increased net interest expense, partly offset by the gains on the NEPA Non-Operated Asset Divestitures, decreased income tax expense, increased pipeline revenues and decreased transportation and processing expense.

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.

We did not recast our discussion and analysis of financial condition and results of operations for the year ended December 31, 2022 for our change in reportable segments as such change does not materially change our historic comparative discussion of our financial condition and results of operations for the years ended December 31, 2023 and 2022 included within the 2023 Annual Report.

Prior to the Equitrans Midstream Merger, we operated our business as a single segment and did not generate material third-party gathering operating income.

Further, in our judgment, we do not believe such a recast is necessary to an understanding of our business, financial condition, changes in financial condition and results of operations.

See Note 2 to the Consolidated Financial Statements for financial information by business segment, including our profit and loss metric and capital expenditures for the year ended December 31, 2022 and segment assets as of December 31, 2022.

See "Average Realized Price Reconciliation" for a discussion and calculation of our average realized price, which is based on our Production segment's adjusted operating revenues (Production adjusted operating revenues), a non-GAAP supplemental financial measure that has been reconciled from total Production 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 "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 Production adjusted operating revenues, a non-GAAP supplemental financial measure.

Production adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends.

Production adjusted operating revenues should not be considered as an alternative to total Production operating revenues.

See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of Production adjusted operating revenues from total Production operating revenues, the most directly comparable financial measure calculated in accordance with United States generally accepted accounting principles (GAAP).

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).

Years Ended December 31,

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(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 Production adjusted operating revenues, a non-GAAP supplemental financial measure.

Non-GAAP Financial Measures Reconciliation

The table below reconciles Production adjusted operating revenues, a non-GAAP supplemental financial measure, from total Production 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 Production operating revenues to EQT Corporation operating revenues as reported in the Statements of Consolidated Operations.

Production 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.

Production adjusted operating revenues is defined as total Production operating revenues, less the revenue impact of changes in the fair value of derivative instruments prior to settlement and Production net marketing services and other revenues.

We believe that Production 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.

Production adjusted operating revenues reflects only the impact of settled derivative contracts;

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 Production net marketing services and other revenues, which consists of costs of, and recoveries on, pipeline capacity releases and other revenues.

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,

(Thousands, unless otherwise noted)

Total Production operating revenues $ 5,009,833 $ 6,896,358

Total Upstream operating revenues $ 8,024,057 $ 5,009,833

(Deduct) add:

Production gain on derivatives (67,880) (1,838,941)

Net cash settlements received on derivatives (a) 1,217,895 900,650

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)

Production net marketing services and other (7,587) (12,649)

Production adjusted operating revenues, a non-GAAP financial measure $ 6,106,807 $ 5,622,549

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

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Average realized price ($/Mcfe) $ 3.19 $ 2.74

(a) For the years ended December 31, 2024 and 2023, composed of net cash settlements received on NYMEX natural gas hedge positions of approximately $1,374 million and $976 million , respectively, and net cash settlements paid on basis and liquids hedge positions of $157 million and $76 million, respectively.

Net cash settlements received on derivatives are included in average realized price but may not be included in operating revenues.

(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

Operating segments are revenue-producing components of an entity for which separate financial information is produced internally and reviewed by the chief operating decision maker to measure financial performance and allocate resources.

Prior to the completion of the Equitrans Midstream Merger, we reported our results of operations as a single consolidated segment.

Thereafter, and as a result thereof, we adjusted our internal reporting structure and our chief operating decision maker changed the manner in which he measures financial performance and allocates resources to incorporate the gathering and transmission assets we acquired in the Equitrans Midstream Merger.

Hence, our operations expanded to comprise three discrete segments reflective of our three lines of business of Production, Gathering and Transmission.

Accordingly, the manner in which we report our operations has been changed retrospectively, with certain prior period amounts recast between our Production segment and Gathering segment.

The following sections summarize operating income and certain operational measures by our three reportable segments.

We believe this information is useful to investors for evaluating our financial condition, results of operations and trends and uncertainties of our segments.

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.

Certain amounts, including cash and cash equivalents, debt, income taxes and other amounts related to our headquarters function as well as amounts related to our energy transition initiatives are managed on a consolidated basis and, as such, have not been allocated to our reportable segments.

Changes to these amounts are discussed under "Other Income Statement Items."

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.

Upstream Results of Operations

Years Ended December 31,

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Gain on derivatives 290,994 67,880 223,114 328.7

Pipeline, net marketing services and other 7,587 12,649 (5,062) (40.0)

Other revenues 6,351 7,587 (1,236) (16.3)

Total operating revenues 8,024,057 5,009,833 3,014,224 60.2

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Other depreciation and depletion 4,565 3,550 1,015 28.6

(Gain) loss on sale/exchange of long-lived assets (764,431) 17,445 (781,876) (4,481.9)

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)

12 unchanged sentences

(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 as the necessary information is not available and the cost to develop such information would be excessive.

(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.

Sales of Natural Gas, NGLs and Oil.

Sales of natural gas, NGLs and oil decreased for 2024 compared to 2023 by approximately $110 million, of which approximately $640 million was attributable to lower average sales price, which was partly offset by approximately $530 million attributable to increased sales volumes.

The average sales price decreased for 2024 compared to 2023 due to a lower NYMEX price, partly offset by lower basis spreads and higher NGLs price.

Sales volume increased for 2024 compared to 2023 primarily as a result of sales volume increases of 164 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition as well as increases from wells turned-in-line, partly offset by sales volume decreases of 107 Bcfe from the Strategic Curtailment and net decreases of 21 Bcfe due to the First NEPA Non-Operated Asset Divestiture.

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.

Production gain on derivatives.

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 $377 million due to decreases in NYMEX forward prices, partly offset by decreases in the fair market value of our basis swaps of approximately $309 million.

For 2023, we recognized a gain on derivatives of approximately $1,839 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $1,830 million due to decreases in NYMEX forward prices as well as increases in the fair market value of our basis swaps of approximately $9 million.

Transportation and processing

Gathering expense decreased on an absolute and per Mcfe basis for 2024 compared to 2023 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 the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the First NEPA Non-Operated Asset Divestiture.

Transmission.

Transmission expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to capacity charges related to the in service of the MVP (which commenced long-term firm capacity obligations on July 1, 2024) of approximately $165 million, additional contracted capacity on the Columbia Gas and Transco pipelines of an aggregate approximate $47 million and credits received in 2023 from pipeline credits of approximately $14 million.

We record our equity earnings from our investment in the MVP Joint Venture in income from investments in our Statements of Consolidated Operations.

Processing expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to increased processing expense from the liquids-rich properties acquired in the Tug Hill and XcL Midstream Acquisition of approximately $40 million and increased volumes of gas requiring processing from wells that we turned-in-line in 2024.

Transportation and processing to affiliate.

Affiliate transportation and processing expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 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 the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the First NEPA Non-Operated Asset Divestiture.

In addition, affiliate transportation and processing expense increased on a per Mcfe basis for 2024 compared to 2023 due to our Gathering segment's ownership of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023.

LOE increased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to increased LOE from the operation and maintenance of our assets, including assets acquired in the Tug Hill and XcL Midstream Acquisition and the Equitrans Midstream Merger and water assets internally-developed in the prior year, as well as increased salt water disposal costs.

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 increased on an absolute and per Mcfe basis for 2024 compared to 2023 due to increased property tax expense of approximately $63 million primarily from the assets acquired in the Tug Hill and XcL Midstream Acquisition and higher price as well as increased severance tax expense of approximately $24 million from increased sales volume in West Virginia.

Selling, general and administrative.

Selling, general and administrative expense increased on an absolute basis for 2024 compared to 2023 due primarily to higher legal and professional services costs as well as higher personnel costs due to increased workforce headcount.

In addition, we did not recast selling, general and administrative expense for periods prior to the Equitrans Midstream Merger closing date and, upon the Equitrans Midstream Merger closing date, we adjusted our basis for selling, general and administrative expense allocation for multi-segment reporting.

Depreciation and depletion.

Production depletion expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due to increased sales volume and higher annual depletion rate.

(Gain) loss on sale/exchange of long-lived assets .

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.

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.

During 2023, we recognized a loss on sale/exchange of long-lived assets of approximately $17 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.

Impairment and Expiration of Leases.

During 2024 and 2023, we recognized impairment and expiration of leases related to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.

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.

We recognized approximately $13 million and $9 million of other operating expenses for 2024 and 2023, respectively.

Other operating expenses increased for 2024 compared to 2023 due primarily to increased rig release expense and increased legal and environmental reserves, including from settlements, partly offset by proceeds received in 2024 from business interruption insurance claim recoveries.

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,

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Gathered volume (BBtu/d):

Firm capacity 5,277 — 5,277 100

Volumetric-based services 4,234 976 3,258 334

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

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Loss on derivatives $ — $ (16,763) $ 16,763 (100)

Firm reservation fee revenue 313,987 — 313,987 100

Volumetric-based fee revenue (a) 452,476 161,395 291,081 180

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

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Operating and maintenance 166,990 89,897 77,093 86

Selling, general and administrative (b) 38,837 — 38,837 100

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, includes volumes up to the contractual MVC;

volumes in excess of the contractual MVC are reported under volumetric-based services.

Gathering revenues and expenses increased for 2024 compared to 2023 primarily from the gathering assets acquired in the Equitrans Midstream Merger during the third quarter of 2024 and in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023.

Prior to the completion of the Equitrans Midstream Merger, we did not own gathering assets that provided firm gathering services.

Prior to the completion of the Equitrans Midstream Merger, we did not have transmission or storage assets.

December 31, 2024

(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.

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)

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Volumetric-based fee revenue 137,058 35,205 101,853 289

Other revenues 237

Total operating revenues 572,252 218,293 353,959 162

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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

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(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.

Other Income Statement Items

Other Operating Expenses.

We recognized $337.2 million and $74.9 million of corporate other operating expenses for 2024 and 2023, respectively.

Corporate other operating expenses increased for 2024 compared to 2023 due primarily to transaction costs related to the Equitrans Midstream Merger of $304.8 million and higher legal reserves, partly offset by lower transaction costs related to the Tug Hill and XcL Midstream Acquisition.

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.

Total transaction costs related to the Equitrans Midstream Merger recognized during 2024 included severance and other termination benefits and stock-based compensation costs of $165.4 million, of which $60.8 million was cash and $104.6 million was non-cash.

Income from Investments .

Income from investments increased for 2024 compared to 2023 due primarily to equity earnings from our investment in the MVP Joint Venture of $78.8 million, partly offset by a decrease in the fair value of our investment in the Investment Fund (defined in Note 11 to the Consolidated Financial Statements).

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.

Other income increased for 2024 compared to 2023 due to proceeds received from insurance claim recoveries of $19.1 million related to the assets acquired in the Tug Hill and XcL Midstream Acquisition and dividends received from our investment in the Investment Fund.

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.

During 2024, we recognized a loss on debt extinguishment of $68.3 million due primarily to premiums and financing costs paid on our redemption and repurchase of certain of EQM's senior notes, including pursuant to the EQM Tender Offer, and non-cash losses related to our write off of the unamortized fair value adjustments of those redeemed and repurchased EQM senior notes and unamortized deferred issuance costs of the Term Loan Facility.

See Note 10 to the Consolidated Financial Statements.

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 increased for 2024 compared to 2023 due primarily to interest expense on EQM's senior notes, increased interest expense on our borrowings under EQT's revolving credit facility, interest expense on EQT's 5.750% senior notes issued in January 2024, lower interest income earned on cash on hand and interest expense on Eureka Midstream, LLC's (Eureka) borrowings under its revolving credit facility, partly offset by decreased interest expense from our repayment and repurchase of certain of EQT's senior notes as well as higher capitalized interest from the assets acquired in the Tug Hill and XcL Midstream Acquisition.

See Note 10 to the Consolidated Financial Statements.

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 (loss) attributable to noncontrolling interests .

During 2024, we recognized $11.4 million of net income attributable to noncontrolling interests of Eureka Midstream Holdings, a consolidated joint venture in which we acquired an equity interest as a result of the Equitrans Midstream Merger.

Sees Note 1 and 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.

Purchase Obligations

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 15 to the Consolidated Financial Statements for a summary of aggregated future payments for these commitments.

Unrecognized Tax Benefits

As of December 31, 2024, we had a total reserve for unrecognized tax benefits of $9.0 million and an additional reserve of $60.4 million that was offset against deferred tax assets for general business tax credit carryforwards and net operating losses (NOLs).

We settled our consolidated U.S.

federal income tax liability with the IRS through 2019 in September 2024.

We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities.

See Note 9 to the Consolidated Financial Statements for further discussion.

Planned Capital Expenditures and Sales Volume

In 2025, we expect to spend approximately $2.3 billion to $2.5 billion on total capital expenditures.

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.

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and drilling, completion and acquisition costs.

In addition, our gathering and transmission businesses are capital intensive, requiring significant investment to develop new facilities and maintain and upgrade existing operations.

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.

Material Cash Requirements

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 $2,827 million and $3,179 million for 2024 and 2023, respectively.

The decrease was due primarily to changes in working capital from movements in the market price for natural gas and timing of payments as well as higher cash operating expenses (including from transaction costs related to the Equitrans Midstream Merger), higher net interest expense and higher share-based compensation expense.

Such decreases were partly offset by higher net cash settlements received on derivatives, lower net premiums paid on derivatives, higher cash operating revenues (including from pipeline revenues on assets acquired in the Equitrans Midstream Merger) and higher distributions from equity method investments (including approximately $53 million from our investment in the MVP Joint Venture).

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.

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Investing Activities.

Net cash used in investing activities was $1,580 million and $4,314 million for 2024 and 2023, respectively.

The decrease was attributable primarily to the proceeds received from the NEPA Non-Operated Asset Divestitures in 2024 and lower cash paid for acquisitions in 2024 (primarily for the NEPA Gathering System Acquisition) compared to 2023 (primarily for the Tug Hill and XcL Midstream Acquisition), partly offset by increased capital expenditures and capital contributions made to our investment in the MVP Joint Venture of approximately $145 million.

The following table summarizes our capital expenditures by business segment.

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.

The following table summarizes our capital expenditures by segment.

Years Ended December 31,

Reserve development (a) $ 1,653 $ 1,587

Reserve development $ 1,537 $ 1,653

Land and lease 153 156

Other production infrastructure 71 63

Capitalized interest, capitalized overhead and other 124 98

Total Production 2,004 1,878

Other upstream infrastructure 70 71

Capitalized overhead, capitalized interest and other 118 124

Total Upstream 1,878 2,004

Gathering 368 202

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Total capital expenditures 2,324 2,266

(Deduct) add:

Non-cash items (b) (12) 94

Non-cash items (a) (36) (12)

Total cash capital expenditures $ 2,288 $ 2,254

(a) Capital expenditures for reserve development included capital expenditures for water infrastructure of $79.8 million and $35.9 million for 2024 and 2023, respectively.

(b) 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.

(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 $1,126 million and $243 million for 2024 and 2023, respectively.

For 2024, the primary uses of financing cash flows were our repayment and retirement of debt, repayment of EQM's revolving credit facility, payment of dividends and cash paid for taxes to net settle share-based incentive awards.

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, net borrowings under EQT's revolving credit facility and proceeds from the net settlement of the Capped Call Transactions (defined in Note 10 to the Consolidated Financial Statements).

For 2023, the primary uses of financing cash flows were our repayment and retirement of debt, payment of dividends and repurchase and retirement of EQT common stock, and the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings.

See Note 10 to the Consolidated Financial Statements for further discussion of our debt.

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.

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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.

Security Ratings and Financing Triggers

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.

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.

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Moody's Investors Service, Inc.

(Moody's) Baa3 Negative

(Moody's) Baa3 Stable

S&P Global Ratings (S&P) BBB–

Fitch Ratings Service (Fitch) BBB–

The table below reflects the credit ratings and rating outlooks assigned to EQM's debt instruments as of February 14, 2025.

Rating agency Senior notes Outlook

Moody's Ba2 Stable

S&P BBB– Stable

Fitch BB+ Stable

Changes in 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.

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.

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 revolving credit facility and Eureka's revolving credit facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions.

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, 2024, we were in compliance with all EQT, Eureka and EQM debt provisions and covenants under our debt agreements.

See Note 10 to the Consolidated Financial Statements for a discussion of borrowings under EQT's revolving credit facility and Eureka's revolving credit facility.

Commodity Risk Management

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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 2025(a) Q2 2025 Q3 2025 Q4 2025

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

Swaps – Short

Volume (MMDth) 250 290 281 95

Price ($/Dth) $ 3.49 $ 3.11 $ 3.26 $ 3.27

Calls – Short

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Strike ($/Dth) $ 4.25 $ 3.50 $ 3.50 $ 3.72 $ 3.30

Option Premiums

Cash Settlement of Deferred Premiums (millions) $ — $ — $ — $ (45)

(a) January 1 through March 31.

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Off-Balance Sheet Arrangements

As of December 31, 2024, we did not have any material off-balance sheet arrangements other than the commitments described in Note 15 to the Consolidated Financial Statements.

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.

Commitments and Contingencies

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Recently Issued Accounting Standards

Our recently issued accounting standards are described in Note 1 to the Consolidated Financial Statements.

See Note 1 to the Consolidated Financial Statements for a description of recently issued accounting standards.

Critical Accounting Estimates

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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 requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities.

The following critical accounting estimates, which were reviewed by the Audit Committee of our Board of Directors, relate to our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements.

Actual results could differ from our estimates.

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 a given date forward from known reservoirs and 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 estimates of proved reserves are reassessed annually using geological, reservoir and production performance data.

Reserve estimates are prepared by our engineers and audited by independent engineers.

Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions.

Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner.

A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.

We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a 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.

Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

Income tax expense is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.

We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures.

Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions.

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;

• 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.

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 our Consolidated Financial Statements or tax returns.

See Note 1 to the Consolidated Financial Statements for a discussion of significant accounting policies related to income taxes and Note 9 to the Consolidated Financial Statements for a discussion of deferred tax assets, valuation allowances and the amount of financial statement benefit recorded for uncertain tax positions.

We believe income taxes is a "critical accounting estimate" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions.

When evaluating whether or not a valuation allowance should be established, we exercise judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of our deferred tax assets will not be realized.

To determine whether a valuation allowance is needed, we consider all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income.

To determine the amount of financial statement benefit recorded for uncertain tax positions, we consider 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.

To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an income tax expense or benefit in our Statements of Consolidated Operations.

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.

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Changes in our assumptions are sensitive to numerous factors;

however, based on income before taxes for the years ended December 31, 2024, 2023 and 2022, we estimate that a 1% change in our effective tax rate would decrease or increase income tax expense by approximately $3 million, $21 million and $23 million, respectively.

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 enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of our natural gas production.

See Note 5 to the Consolidated Financial Statements for a description of the fair value hierarchy.

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 our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis.

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.

Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.

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 based on our assessment that a loss is probable and the amount of the loss can be reasonably estimated.

We consider many factors in making these assessments, including historical experience and matter specifics.

Estimates are developed in consultation with legal counsel and are based on an analysis of potential results.

See Note 15 to the Consolidated Financial Statements.

We accrue 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 our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud.

See Note 1 to the Consolidated Financial Statements.

We believe contingencies and asset retirement obligations is a "critical accounting estimate" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligation settlement.

In addition, we must determine the estimated present value of future liabilities.

Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.

If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations.

If the expected amount and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future periods.

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

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.

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

Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value.

In the third quarter of 2024, we completed the Equitrans Midstream Merger.

See Note 6 to the Consolidated Financial Statements for a discussion of the most significant assumptions used to estimate the fair value of the assets acquired and liabilities assumed in the Equitrans Midstream Merger.

We believe business combinations is a "critical accounting estimate" because the valuation of acquired assets and assumed liabilities involves significant judgment about future events.

Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

Property, Plant and Equipment (Including Gas, NGLs and Oil Producing Properties).

We use the successful efforts method of accounting for gas, NGLs and oil producing activities.

See Note 1 to the Consolidated Financial Statements for a discussion of the fair value measurement and any impairment of our oil and gas properties and other property, plant and equipment as well as our evaluation of the recoverability of capitalized costs of unproved oil and gas properties.

We believe the accounting for our property, plant and equipment, including our gas, NGLs and oil producing properties, is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, including future sales prices of natural gas and NGLs, future production costs, the amount of natural gas and NGLs recorded and timing of recoveries, as well as discount and inflation rates.

In addition, evaluations of impairment of our other property, plant and equipment also involve significant judgement about future events, including assumptions about future cash flows, discount rates and operating levels.

Significant changes in these estimates could result in the costs of our property, plant and equipment, including our proved and unproved properties, not being recoverable, which would require us to recognize impairment.

An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

See Note 1 to the Consolidated Financial Statements for additional information on impairment of our proved and unproved oil and gas properties, impairment of other property, plant and equipment.

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;

• 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.

Intangible Assets.

Refer to Notes 1 and 6 to the Consolidated Financial Statements for a discussion of our intangible assets.

We evaluate our intangible assets for impairment when indicators of impairment are present.

We believe impairment of intangible assets is a "critical accounting estimate" because the determination of whether an indicator of impairment has occurred and if further evaluation of impairment is required involves significant judgment about future events, including shifts in the market price of the assets, changes in the extent or manner in which the assets are being used, changes in legal factors of the business climate that could affect the value of the assets or a more-likely-than-not expectation that the assets will be sold or otherwise disposed of before the end of their previously estimated useful lives.

Investments in Unconsolidated Entities

Refer to Notes 1 and 11 to the Consolidated Financial Statements for a discussion of our investments in unconsolidated entities.

We evaluate our investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the investment's fair value is less than its carrying value.

The recognition of an impairment loss is required if the impairment is considered other than temporary.

We believe the impairment of investments in unconsolidated entities is a "critical accounting estimate" because evaluations of impairment involve significant judgment about future events, such as our ability to recover the carrying value of our investment or the investee's inability to generate cash flows sufficient to justify the carrying value of our investment.

Goodwill is evaluated for impairment annually as of October 1 or more frequently if indicators of impairment exist.

A significant amount of judgement is involved in determining if an indicator of impairment has occurred.

Such indicators may include, among others, deterioration in general economic conditions, negative developments in equity and credit markets, adverse changes in the market environments in which we operate, increases in operating costs or other factors that could have a negative effect on earnings and cash flows or a trend of negative or declining cash flows over multiple periods.

We test goodwill for impairment on a qualitative or quantitative basis.

When performing a qualitative impairment test, we consider a number of factors in our assessment, such as:

general economic conditions, performance equity and credit markets, industry and market conditions, market capitalization, earnings and cash flow trends.

When performing a quantitative impairment test, we may use a combination of the income and market approach to estimate the fair value of our reporting units.

Refer to Note 1 to the Consolidated Financial Statements for further discussion of our goodwill impairment assessment process.

We believe the impairment of goodwill is a "critical accounting estimate" because a significant amount of judgement is involved in determining whether an indicator of impairment has occurred.

In addition, the estimation of the fair value of a reporting unit involves significant judgment and is sensitive to changes in assumptions, including changes in our stock price, weighted-average cost of capital, forecasted cash flows, terminal growth rates and industry multiples.

Changes to assumptions could materially affect the estimated fair value of our reporting units and the resulting conclusion on impairment could materially affect our results of operations and financial position.

In addition, future assumptions and estimates may materially differ from current assumptions and estimates.

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.

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;

• 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 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.

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What changed 10-K

Item 7. Management’s Discussion and Analysis