EQT Corp (EQT)

CIK: 0000033213. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-18.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=33213. Latest filing source: 0000033213-26-000018.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-18. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000033213.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

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Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-18. Report date: 2025-12-31.

Item 7.        Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and the notes thereto included in Item 8., "Financial Statements and Supplementary Data."

Recent and Significant Events

Olympus Energy Acquisition

Our results of operation for 2025 reflect our acquisition (the Olympus Energy Acquisition) of certain oil and gas properties and related upstream and midstream assets from Olympus Energy LLC, Hyperion Midstream LLC and Bow & Arrow Land Company LLC (collectively, Olympus Energy), which was completed on July 1, 2025. See Note 11 to the Consolidated Financial Statements for further discussion of the Olympus Energy Acquisition.

Midstream Joint Venture Transaction

Our results of operation for 2025 reflect the impact of the Midstream Joint Venture Transaction (defined in Note 9 to the Consolidated Financial Statements), where we received $3.5 billion of cash consideration from a third-party investor in exchange for a noncontrolling equity interest in the Midstream Joint Venture. The Midstream Joint Venture Transaction was completed on December 30, 2024.

NEPA Non-Operated Asset Divestitures and NEPA Gathering System Acquisition

Beginning May 31, 2024, our results of operations reflect (i) our divestiture (the First NEPA Non-Operated Asset Divestiture) of an undivided 40% interest in our non-operated natural gas assets in Northeast Pennsylvania and (ii) our 100% ownership of the NEPA Gathering System (defined in Note 11 to the Consolidated Financial Statements) following our acquisition of additional ownership interests therein in connection with the NEPA Gathering System Acquisition (defined in Note 11 to the Consolidated Financial Statements) and the First NEPA Non-Operated Asset Divestiture.

In addition, our results of operations for 2025 reflect our divestiture (the Second NEPA Non-Operated Asset Divestiture, and together with the First NEPA Non-Operated Asset Divestiture, the NEPA Non-Operated Asset Divestitures) of the remaining undivided 60% interest in our non-operated natural gas assets in Northeast Pennsylvania, which was completed on December 31, 2024. See Note 12 to the Consolidated Financial Statements for further discussion of the NEPA Non-Operated Asset Divestitures.

Equitrans Midstream Merger

Beginning July 22, 2024, our results of operations reflect our operation of the assets acquired in the Equitrans Midstream Merger (defined in Note 11 to the Consolidated Financial Statements).

Following the Equitrans Midstream Merger, the gathering and transmission services previously provided to us by Equitrans Midstream are provided to our Upstream segment by our Gathering and Transmission segments as affiliate transactions. As a result, our Upstream segment's third-party gathering expense decreased and its affiliate transportation and processing expense increased, and our Gathering and Transmission segments' affiliate revenue increased. As the affiliate expense and revenue are eliminated in consolidation, the net impact is a reduction in our consolidated transportation and processing expense.

As a result of the completion of the Equitrans Midstream Merger, our operations expanded from a single operating segment to three discrete operating segments reflecting our three lines of business consisting of Upstream, Gathering and Transmission.

See Note 11 to the Consolidated Financial Statements for further discussion of the Equitrans Midstream Merger.

Trends and Uncertainties

Commodity prices were volatile in 2025, and we expect commodity prices to continue to be volatile in 2026 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical instability and tensions, including in Venezuela, Russia, Ukraine and the Middle East, and potential further imposition of domestic and foreign tariffs. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.

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In response to price volatility in the natural gas market and to optimize in-basin pricing, we implement strategic curtailments from time to time to reduce our gross production. During the year ended December 31, 2025, strategic curtailments resulted in decreased sales volumes of approximately 14 Bcfe. Low natural gas prices or volatility in the natural gas market may result in adjustments to our 2026 planned development schedule and/or adjustments to the development schedule of non-operated wells in which we have a working interest. We cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our 2026 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

On July 4, 2025, President Trump signed the OBBBA into law. See Note 6 to the Consolidated Financial Statements for further discussion of the OBBBA. We expect the enactment of the OBBBA to favorably impact our projected cash income tax obligations over the next five years by deferring the payment of a significant portion of current federal income taxes.

President Trump has also executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of natural gas, increase the price of supplies and raw materials that we rely on to conduct our business, and impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

Consolidated Results of Operations

Net income attributable to EQT Corporation for 2025 was $2,039 million, $3.31 per diluted share, compared to $231 million, $0.45 per diluted share, for 2024. The increase was driven predominantly by higher sales of natural gas, reflecting higher average realized natural gas prices. To a lesser extent, net income also benefited from decreased gathering expense, increased pipeline revenues, decreased transaction costs, increased gains on derivatives and increased equity earnings from the MVP Joint Venture. These favorable impacts were partly offset by gains recognized in 2024 on the NEPA Non-Operated Asset Divestitures as well as higher income tax expense, depreciation and depletion expense and net income attributable to noncontrolling interests.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2024, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2023.

See "Average Realized Price Reconciliation" for a discussion and calculation of our average realized price, which is based on our Upstream segment's adjusted operating revenues (Upstream adjusted operating revenues), a non-GAAP supplemental financial measure that has been reconciled to total Upstream operating revenues in "Non-GAAP Financial Measures Reconciliation." See "Business Segment Results of Operations" for a discussion of segment operating revenues and expenses and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures, including by business segment.

Average Realized Price Reconciliation

The following table presents detailed natural gas and liquids operational information to assist in the understanding of our consolidated operations, including the calculation of our average realized price ($/Mcfe), which is based on Upstream adjusted operating revenues, a non-GAAP supplemental financial measure. Upstream adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Upstream adjusted operating revenues should not be considered as an alternative to total Upstream operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of Upstream adjusted operating revenues to total Upstream operating revenues, the most directly comparable financial measure calculated in accordance with United States generally accepted accounting principles (GAAP).

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Years Ended December 31,

2025

2024

(Thousands, unless otherwise noted)

NATURAL GAS

Sales volume (MMcf)

2,238,652 

2,086,441 

NYMEX price ($/MMBtu)

$

3.42 

$

2.30 

Btu uplift

0.19 

0.13 

Natural gas price ($/Mcf)

$

3.61 

$

2.43 

Basis ($/Mcf) (a)

$

(0.48)

$

(0.41)

Cash settled basis swaps ($/Mcf)

(0.01)

(0.07)

Average differential, including cash settled basis swaps ($/Mcf)

(0.49)

(0.48)

Average adjusted price ($/Mcf)

3.12 

1.95 

Cash settled derivatives ($/Mcf)

(0.04)

0.64 

Average natural gas price, including cash settled derivatives ($/Mcf)

$

3.08 

$

2.59 

Natural gas sales, including cash settled derivatives

$

6,888,420 

$

5,401,642 

LIQUIDS

NGLs, excluding ethane:

Sales volume (MMcfe) (b)

88,478 

87,564 

Sales volume (Mbbl)

14,746 

14,594 

NGLs price ($/Bbl)

$

38.04 

$

39.13 

Cash settled derivatives ($/Bbl)

0.15 

(0.30)

Average NGLs price, including cash settled derivatives ($/Bbl)

$

38.19 

$

38.83 

NGLs sales, including cash settled derivatives

$

563,150 

$

566,808 

Ethane:

Sales volume (MMcfe) (b)

44,534 

44,586 

Sales volume (Mbbl)

7,422 

7,431 

Ethane price ($/Bbl)

$

8.01 

$

6.03 

Ethane sales

$

59,447 

$

44,806 

Oil:

Sales volume (MMcfe) (b)

10,703 

9,568 

Sales volume (Mbbl)

1,784 

1,595 

Oil price ($/Bbl)

$

49.08 

$

58.67 

Oil sales

$

87,562 

$

93,551 

Total liquids sales volume (MMcfe) (b)

143,715 

141,718 

Total liquids sales volume (Mbbl)

23,952 

23,620 

Total liquids sales

$

710,159 

$

705,165 

TOTAL

Total natural gas and liquids sales, including cash settled derivatives (c)

$

7,598,579 

$

6,106,807 

Total sales volume (MMcfe)

2,382,367 

2,228,159 

Average realized price ($/Mcfe)

$

3.19 

$

2.74 

(a)Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with our firm transportation agreements, and the NYMEX natural gas price.

(b)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.

(c)Also referred to in this report as Upstream adjusted operating revenues, a non-GAAP supplemental financial measure.

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Non-GAAP Financial Measures Reconciliation

The table below reconciles Upstream adjusted operating revenues, a non-GAAP supplemental financial measure, to total Upstream operating revenues, the most comparable financial measure calculated in accordance with GAAP. See Note 2 to the Consolidated Financial Statements for a reconciliation of total Upstream operating revenues to EQT Corporation operating revenues as reported in the Statements of Consolidated Operations.

Upstream adjusted operating revenues (also referred to in this report as total natural gas and liquids sales, including cash settled derivatives) is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Upstream adjusted operating revenues is defined as total Upstream operating revenues, less the revenue impact of changes in the fair value of derivative instruments prior to settlement and Upstream other revenues. We believe that Upstream adjusted operating revenues provides useful information to investors regarding our financial condition and results of operations because it helps facilitate comparisons of operating performance and earnings trends across periods. Upstream adjusted operating revenues reflects only the impact of settled derivative contracts; thus, the measure excludes the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement. The measure also excludes Upstream other revenues, which consists of costs of, and recoveries on, pipeline capacity releases and other revenues.

Years Ended December 31,

2025

2024

(Thousands, unless otherwise noted)

Total Upstream operating revenues

$

8,024,057 

$

5,009,833 

(Deduct) add:

Upstream gain on derivatives

(290,994)

(67,880)

Net cash settlements (paid) received on derivatives (a)

(83,381)

1,217,895 

Premiums paid for derivatives that settled during the period

(44,752)

(45,454)

Upstream other revenues

(6,351)

(7,587)

Upstream adjusted operating revenues, a non-GAAP financial measure

$

7,598,579 

$

6,106,807 

Total sales volume (MMcfe)

2,382,367 

2,228,159 

Average sales price ($/Mcfe)

$

3.24 

$

2.21 

Average realized price ($/Mcfe)

$

3.19 

$

2.74 

(a)Net cash settlements (paid) received on derivatives are included in average realized price but may not be included in operating revenues. For the year ended December 31, 2025, net cash settlements paid on derivatives consisted of net cash settlements paid on NYMEX natural gas hedge positions of approximately $42 million and net cash settlements paid on basis and liquids hedge positions of approximately $41 million. For the year ended December 31, 2024, net cash settlements received on derivatives consisted of net cash settlements received on NYMEX natural gas hedge positions of approximately $1,374 million, partly offset by net cash settlements paid on basis and liquids hedge positions of approximately $157 million.

Business Segment Results of Operations

The following sections present operating income and key operational measures for our three reportable segments of Upstream, Gathering and Transmission. We believe this information provides useful information to investors regarding our financial condition, results of operations and trends and uncertainties. See Note 2 to the Consolidated Financial Statements for financial information by business segment.

Items that are managed on a consolidated basis, including cash and cash equivalents, debt, income taxes and amounts related to our corporate function, and items related to our energy transition initiatives have not been allocated to our reportable segments. These items are discussed under "Other Income Statement Items."

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

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Upstream Results of Operations

Years Ended December 31,

2025

2024

Change

% Change

(Thousands, unless otherwise noted)

Total sales volume (MMcfe)

2,382,367 

2,228,159 

154,208 

6.9 

Average daily sales volume (MMcfe/d)

6,527 

6,088 

439 

7.2 

Average sales price ($/Mcfe)

$

3.24 

$

2.21 

$

1.03 

46.6 

Operating revenues:

Sales of natural gas, NGLs and oil

$

7,726,712 

$

4,934,366 

$

2,792,346 

56.6 

Gain on derivatives

290,994 

67,880 

223,114 

328.7 

Other revenues

6,351 

7,587 

(1,236)

(16.3)

Total operating revenues

8,024,057 

5,009,833 

3,014,224 

60.2 

Operating expenses:

Transportation and processing:

Gathering

196,594 

775,114 

(578,520)

(74.6)

Transmission

1,008,438 

846,563 

161,875 

19.1 

Processing

327,058 

293,939 

33,119 

11.3 

Transportation and processing to affiliate (a)

1,251,365 

704,094 

547,271 

77.7 

Total transportation and processing

2,783,455 

2,619,710 

163,745 

6.3 

LOE

216,198 

196,771 

19,427 

9.9 

Production taxes

172,498 

180,236 

(7,738)

(4.3)

Exploration

3,601 

2,735 

866 

31.7 

Selling, general and administrative (b)

217,803 

244,450 

(26,647)

(10.9)

Production depletion

2,258,540 

2,013,120 

245,420 

12.2 

Other depreciation and depletion

4,565 

3,550 

1,015 

28.6 

Gain on sale/exchange of long-lived assets

(31,513)

(764,431)

732,918 

(95.9)

Impairment and expiration of leases

50,341 

97,368 

(47,027)

(48.3)

Other operating expenses

30,438 

12,696 

17,742 

139.7 

Total operating expenses

5,705,926 

4,606,205 

1,099,721 

23.9 

Operating income

$

2,318,131 

$

403,628 

$

1,914,503 

474.3 

Per Unit ($/Mcfe):

Gathering

$

0.08 

$

0.35 

$

(0.27)

(77.1)

Transmission

0.42 

0.38 

0.04 

10.5 

Processing

0.14 

0.13 

0.01 

7.7 

Transportation and processing to affiliate (a)

0.53 

0.32 

0.21 

65.6 

LOE

0.09 

0.09 

— 

— 

Production taxes

0.07 

0.08 

(0.01)

(12.5)

Selling, general and administrative (b)

0.09 

0.11 

(0.02)

(18.2)

Production depletion

0.95 

0.90 

0.05 

5.6 

(a)Transportation and processing to affiliate represents intercompany transactions with our Gathering and Transmission segments, which are eliminated in consolidation.

(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for our change in reportable segments from one reportable segment to three reportable segments as the necessary information was not available and the cost to develop such information would be excessive.

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Sales of Natural Gas, NGLs and Oil. Sales of natural gas, NGLs and oil increased by approximately $2,792 million for 2025 compared to 2024, reflecting an increase of approximately $2,451 million from higher average sales price and approximately $341 million from increased sales volumes.

Average sales price increased for 2025 compared to 2024 due primarily to a higher NYMEX price, partly offset by lower NGLs price and an unfavorable basis differential.

Sales volume increased for 2025 compared to 2024 primarily as a result of production curtailments in 2024 of 107 Bcfe (compared to production curtailments in 2025 of 14 Bcfe), wells turned-in-line since 2024, sales volume increases of 92 Bcfe from the assets acquired in the Olympus Energy Acquisition and sales volume increases of 26 Bcfe from the assets received as consideration for (net of assets divested in) the First NEPA Non-Operated Asset Divestiture. Increases in sales volume were partly offset by sales volume decreases of 155 Bcfe from the assets divested in the Second NEPA Non-Operated Asset Divestiture.

The increase in sales volume had a favorable impact on per unit costs for 2025 compared to 2024.

Gain on Derivatives. For 2025, we recognized a gain on derivatives of approximately $291 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $291 million due to decreases in NYMEX forward prices and increases in the fair market value of our basis and liquids swaps of approximately $45 million, partly offset by premiums paid for derivative settlements of $45 million. For 2024, we recognized a gain on derivatives of approximately $68 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $422 million due to decreases in NYMEX forward prices, partly offset by decreases in the fair market value of our basis and liquids swaps of approximately $309 million and premiums paid for derivative settlements of $45 million.

Gathering Expense. Gathering expense decreased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and First NEPA Non-Operated Asset Divestiture. In addition, gathering expense decreased due to our divestiture of assets in the NEPA Non-Operated Asset Divestitures.

Transmission Expense. Transmission expense increased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to capacity charges of approximately $193 million on the MVP Mainline, which entered into service in June 2024, and additional contracted capacity on the Transco pipeline of approximately $33 million, partly offset by capacity released in connection with the NEPA Non-Operated Asset Divestitures of approximately $57 million.

Processing Expense. Processing expense increased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to increased production of gas requiring processing from wells turned-in-line since 2024.

Transportation and Processing Expense to Affiliate. Affiliate transportation and processing expense increased on an absolute and per Mcfe basis for 2025 compared to 2024 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger and the Olympus Energy Acquisition, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and First NEPA Non-Operated Asset Divestiture.

Production Taxes. Production tax expense decreased on an absolute and per Mcfe basis for 2025 compared to 2024 due to decreased property tax expense of approximately $53 million from lower property tax value based on prior year pricing, partly offset by increased severance tax expense of approximately $35 million from increased sales volume and higher sales prices.

Selling, General and Administrative Expense. Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for our change in reportable segments; upon the Equitrans Midstream Merger closing date, we adjusted our basis for selling, general and administrative expense allocation for multi-segment reporting. On a consolidated basis, selling, general and administrative expense increased for 2025 compared to 2024 due primarily to higher labor costs driven by increased headcount as well as higher long-term incentive compensation costs as a result of increases in awards outstanding and changes in the fair value of awards.

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Production Depletion Expense. Production depletion expense increased on a per Mcfe basis for 2025 compared to 2024 due to higher annual depletion rate. In addition, production depletion expense increased on an absolute basis due to higher sales volumes.

Gain on Sale/Exchange of Long-Lived Assets. During 2025, we recognized a net gain on sale/exchange of long-lived assets of approximately $36 million related to acreage trade transactions. During 2024, we recognized a gain on the First NEPA Non-Operated Asset Divestiture of approximately $299 million and a gain on the Second NEPA Non-Operated Asset Divestiture of approximately $463 million. See Note 12 to the Consolidated Financial Statements.

Impairment and Expiration of Leases. During 2025 and 2024, we recognized impairment and expiration of leases of approximately $50 million and $97 million, respectively, related to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.

Other Operating Expenses. Other operating expenses increased for 2025 compared to 2024 due primarily to proceeds received in 2024 from business interruption insurance claim recoveries and increased expense from changes in legal and environmental reserves, including settlements. See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses.

Gathering Results of Operations

Years Ended December 31,

2025

2024

Change

% Change

(Thousands, unless otherwise noted)

Gathered volume (BBtu/d):

Firm capacity (a)

5,407 

5,277 

130 

2 

Volumetric-based services (a)

4,788 

4,234 

554 

13 

Total gathered volume

10,195 

9,511 

684 

7 

Operating revenues:

Loss on derivatives

$

— 

$

(16,763)

$

16,763 

(100)

Firm reservation fee revenue (b)

632,916 

313,987 

318,929 

102 

Volumetric-based fee revenue

668,518 

452,476 

216,042 

48 

Total operating revenues

1,301,434 

749,700 

551,734 

74 

Operating expenses:

Operating and maintenance

166,990 

89,897 

77,093 

86 

Selling, general and administrative (c)

66,642 

38,837 

27,805 

72 

Depreciation

212,353 

89,513 

122,840 

137 

Gain on sale/exchange of long-lived assets

(29)

(22)

(7)

32 

Impairment and expiration of leases

811 

— 

811 

100 

Other operating expenses

18,013 

— 

18,013 

100 

Total operating expenses

464,780 

218,225 

246,555 

113 

Operating income

$

836,654 

$

531,475 

$

305,179 

57 

(a)For agreements structured with MVCs, firm capacity includes volumes up to the contractual MVC and volumetric-based services includes volumes in excess of the contractual MVC.

(b)Firm reservation fee revenue included unbilled revenues supported by MVCs of approximately $18.4 million and $4.2 million for the year ended December 31, 2025 and 2024, respectively.

(c)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for our change in reportable segments from one reportable segment to three reportable segments as the necessary information was not available and the cost to develop such information would be excessive.

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Firm Reservation Fee Revenue. Firm reservation fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger, which contributed approximately $377 million of additional firm reservation fee revenue in 2025, partly offset by lower revenue of approximately $66 million from the declining rate structures under the gas gathering agreement with our Upstream segment.

Volumetric-Based Fee Revenue. Volumetric-based fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger, which contributed approximately $157 million of additional volumetric-based fee revenue in 2025, the gathering assets acquired in the Olympus Energy Acquisition, which contributed approximately $43 million of additional volumetric-based fee revenue in 2025, and increased ownership of the NEPA Gathering System as a result of the NEPA Gathering System Acquisition and the First NEPA Non-Operated Asset Divestiture.

Operating Expenses. Gathering operating expenses increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger. In addition, during 2025, Gathering recognized other operating expenses related to environmental reserves.

Transmission Results of Operations

Years Ended December 31,

2025

2024

Change

% Change

(Thousands, unless otherwise noted)

Transmission pipeline throughput (BBtu/d):

Firm capacity (a)

4,426 

3,695 

731 

20 

Interruptible capacity

39 

24 

15 

63 

Total transmission pipeline throughput

4,465 

3,719 

746 

20 

Average contracted firm transmission reservation commitments (BBtu/d)

5,025 

4,779 

246 

5 

Operating revenues:

Firm reservation fee revenue

$

435,194 

$

183,088 

$

252,106 

138 

Volumetric-based fee revenue

137,058 

35,205 

101,853 

289 

Total operating revenues

572,252 

218,293 

353,959 

162 

Operating expenses:

Operating and maintenance

58,141 

20,496 

37,645 

184 

Selling, general and administrative

37,339 

17,183 

20,156 

117 

Depreciation

88,385 

33,505 

54,880 

164 

Amortization of intangible assets

13,333 

5,901 

7,432 

126 

Loss on sale/exchange of long-lived assets

349 

409 

(60)

(15)

Other operating expenses

(527)

— 

(527)

100 

Total operating expenses

197,020 

77,494 

119,526 

154 

Operating income

$

375,232 

$

140,799 

$

234,433 

167 

(a)Includes all volumes associated with firm capacity contracts, including volumes in excess of firm capacity.

Firm Reservation Fee Revenue. Firm reservation fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger.

Volumetric-Based Fee Revenue. Volumetric-based fee revenue increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger as well as increased throughput.

Operating Expenses. Transmission operating expenses increased for 2025 compared to 2024 due primarily to the timing of the completion of the Equitrans Midstream Merger.

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Other Income Statement Items

Other Operating Expenses. Corporate other operating expenses decreased for 2025 compared to 2024 due primarily to decreased acquisition-related transaction costs. During 2025, we recognized approximately $29 million of transaction costs related to the Olympus Energy Acquisition compared to approximately $305 million of transaction costs related to the Equitrans Midstream Merger in 2024. In addition, during 2025 and 2024, we recognized net expense of approximately $134 million and $18 million, respectively, for loss contingencies related to the Securities Class Action (defined in Note 13 to the Consolidated Financial Statements). See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses.

Income from Investments. Income from investments increased for 2025 compared to 2024 due primarily to higher equity earnings from our investments in the MVP Joint Venture and Laurel Mountain Midstream, LLC of approximately $76 million and $32 million, respectively.

Other Income. During 2024, we received proceeds from insurance claim recoveries of approximately $19 million related to the assets acquired in the Tug Hill and XcL Midstream Acquisition (defined in Note 11 to the Consolidated Financial Statements).

Loss on Debt Extinguishment. Loss on debt extinguishment decreased for 2025 compared to 2024 due to the derecognition of unamortized fair value adjustments and deferred financing costs associated with debt redemptions, which resulted in a gain of approximately $17 million in 2025 compared to a loss of approximately $16 million in 2024. In addition, net cash call premiums paid were approximately $18 million lower in 2025 compared to 2024.

Interest Expense, Net. Net interest expense decreased for 2025 compared to 2024 due primarily to lower interest expense resulting from the repayment of borrowings under EQT's revolving credit facility and the prepayment of term loans outstanding under EQT's unsecured term loan facility, which was prepaid in full and terminated in December 2024. These decreases were partly offset by higher interest expense on the senior notes assumed in connection with the Equitrans Midstream Merger as well as higher capitalized interest associated with the assets acquired in the Equitrans Midstream Merger.

Income Tax Expense. See Note 6 to the Consolidated Financial Statements.

Net Income Attributable to Noncontrolling Interests. Net income attributable to noncontrolling interests in the Midstream Joint Venture increased approximately $263 million for 2025 compared to 2024 as a result of the Midstream Joint Venture Transaction, which was completed in December 2024. In addition, net income attributable to noncontrolling interests in Eureka Holdings increased approximately $11 million due primarily to the timing of the completion of the Equitrans Midstream Merger.

Capital Resources and Liquidity

Although we cannot provide any assurance, we believe cash flows from operating activities and availability under EQT's revolving credit facility should be sufficient to meet our cash requirements, including, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long term.

Planned Capital Expenditures, Capital Contributions and Sales Volume

In 2026, we expect to spend approximately $2,650 million to $2,850 million on total capital expenditures. We expect to fund our capital expenditures with cash generated from operations and, if required, borrowings under EQT's revolving credit facility. Because we are the operator of a high percentage of our developed acreage, the amount and timing of certain of our capital expenditures is largely discretionary. We could choose to defer a portion of our planned 2026 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; and drilling, completion and acquisition costs.

In 2026, we expect to make approximately $70 million to $80 million of capital contributions to our equity method investments, including to the MVP Joint Venture.

In 2026, we expect our sales volume to be 2,275 Bcfe to 2,375 Bcfe.

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Material Cash Requirements

We have commitments to pay demand charges under long-term contracts and binding precedent agreements with various pipelines as well as charges for processing capacity to extract heavier liquid hydrocarbons from the natural gas stream. In addition, we have commitments to pay for services related to our operations, including electric hydraulic fracturing services and purchase equipment, materials and sand. See Note 13 to the Consolidated Financial Statements for a summary of aggregated future payments for these commitments.

We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 7 to the Consolidated Financial Statements for a summary of such contractual commitments, including maturity dates.

Through our controlling interest in the Midstream Joint Venture, we are required to distribute available cash flow to the holder of the Midstream Joint Venture's Class B units (Class B Unitholder). See "Financing Activities" below and Note 9 to the Consolidated Financial Statements for further discussion.

In addition, in January 2026, we exercised our preferential buy-out right in accordance with the MVP Joint Venture's limited liability company agreement (the MVP LLC Agreement) to acquire additional equity interests in MVP A and MVP C from an affiliate of Con Edison Gas Pipeline and Storage, LLC. Total consideration for our acquisition of the equity interests in MVP A is approximately $200.7 million, of which $98.4 million is expected to be funded by the BXCI Affiliate, subject to purchase price adjustment. Total consideration for our acquisition of the equity interests in MVP C is approximately $12.5 million, subject to purchase price adjustments. The transaction is expected to close in the first half of 2026, subject to regulatory approvals.

Sources and Uses of Cash

Operating Activities. Net cash provided by operating activities was approximately $5,126 million and $2,827 million for 2025 and 2024, respectively. The increase was due primarily to higher cash operating revenues, lower net cash operating expenses and higher distributions received from our investment in MVP A of approximately $189 million, partly offset by net cash settlements paid on derivatives in 2025 compared to net cash settlements received in 2024.

Our cash flows from operating activities, including changes in working capital, are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. For a discussion of potential commodity market risks, refer to Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."

Investing Activities. Net cash used in investing activities was approximately $2,845 million and $1,580 million for 2025 and 2024, respectively. The change is attributable primarily to cash proceeds received in 2024 from the NEPA Non-Operated Asset Divestitures. This impact was partly offset by lower cash paid in 2025 for the Olympus Energy Acquisition compared to cash paid in 2024 for the purchase and redemption of the Equitrans Midstream preferred stock (defined in Note 11 to the Consolidated Financial Statements) and for the NEPA Gathering System Acquisition.

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The following table summarizes our capital expenditures by segment.

Years Ended December 31,

2025

2024

(Millions)

Upstream:

Reserve development

$

1,537 

$

1,653 

Land and lease

153 

156 

Other upstream infrastructure

70 

71 

Capitalized overhead, capitalized interest and other

118 

124 

Total Upstream

1,878 

2,004 

Gathering

368 

202 

Transmission

52 

31 

Other corporate items

26 

29 

Total capital expenditures

2,324 

2,266 

Deduct: Non-cash items (a)

(36)

(12)

Total cash capital expenditures

$

2,288 

$

2,254 

(a)Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures, transfers to or from inventory as assets are completed or assigned to a project and capitalized share-based compensation costs. The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual.

Financing Activities. Net cash used in financing activities was approximately $2,372 million and $1,126 million for 2025 and 2024, respectively. For 2025, the primary uses of financing cash flows were the repayment and retirement of debt, payment of dividends, distributions to the Midstream Joint Venture's Class B Unitholder (see below) and net repayments of revolving credit facility borrowings. For 2024, the primary uses of financing cash flows were the repayment and retirement of debt, repayment of borrowings under the revolving credit facility of our wholly owned subsidiary, EQM Midstream Partners LP, and payment of dividends. In addition, for 2024, the primary sources of financing cash flows were net proceeds from the sale of units of the Midstream Joint Venture, proceeds from the issuance of EQT's 5.750% senior notes and net borrowings under EQT's revolving credit facility.

We, through our controlling ownership interest in the Midstream Joint Venture, expect to make available cash flow distributions to the Midstream Joint Venture Class B Unitholder at least quarterly. During 2025, the Midstream Joint Venture made distributions of approximately $355 million to its Class B Unitholder. As of December 31, 2025, the remaining amount required to achieve the Base Return (defined and discussed in Note 9 to the Consolidated Financial Statements) was approximately $3.41 billion. See Note 9 to the Consolidated Financial Statements.

On February 5, 2026, our Board of Directors declared a quarterly cash dividend of $0.165 per share of EQT common stock, payable on March 2, 2026, to shareholders of record at the close of business on February 17, 2026.

Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to redeem or repurchase our outstanding debt or equity securities through tender offers or other cash purchases in the open market or privately negotiated transactions. The amounts involved in any such transactions may be material. See Note 7 to the Consolidated Financial Statements for discussion of redemptions and repurchases of debt and Note 10 to the Consolidated Financial Statements for discussion of repurchases of EQT common stock.

Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under EQT's and Eureka's revolving credit facilities, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. EQT's revolving credit facility contains financial covenants that require us to have a total debt to total capitalization ratio no greater than 65%. As of December 31, 2025, we were in compliance with all provisions and covenants under our debt agreements. See Note 7 to the Consolidated Financial Statements for a discussion of borrowings under EQT's and Eureka's revolving credit facilities.

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Security Ratings

Our credit ratings and rating outlooks are subject to revision or withdrawal at any time by the assigning rating agency, and each rating should be evaluated independently from any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in the rating agency's judgment, circumstances so warrant. See Note 4 to the Consolidated Financial Statements for a description of what is deemed investment grade.

The table below reflects the credit ratings and rating outlooks assigned to EQT's debt instruments as of February 11, 2026.

Rating agency

Senior notes

Outlook

Moody's Investors Service, Inc. (Moody's)

Baa3

Stable

S&P Global Ratings (S&P)

BBB–

Stable

Fitch Ratings Service (Fitch)

BBB–

Stable

Changes in our credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our revolving credit facilities, the interest rate on our senior notes with adjustable rates, the rates available on new debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties.

Commodity Risk Management

The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of February 11, 2026. The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.

Q1 2026 (a)

Q2 2026

Q3 2026

Q4 2026

Q1 2027

Hedged Volume (MMDth)

228 

127 

125 

108 

9 

Hedged Volume (MMDth/d)

2.5 

1.4 

1.4 

1.2 

0.1 

Calls – Short

Volume (MMDth)

228 

127 

125 

108 

9 

Avg. Strike ($/Dth)

$

6.29 

$

4.94 

$

4.94 

$

5.13 

$

4.25 

Puts – Long

Volume (MMDth)

228 

127 

125 

108 

9 

Avg. Strike ($/Dth)

$

4.25 

$

3.50 

$

3.50 

$

3.72 

$

3.30 

(a)January 1 through March 31.

We have also entered into derivative instruments to hedge basis. We may use other contractual agreements to implement our commodity hedging strategy from time to time.

See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 4 to the Consolidated Financial Statements for further discussion of our hedging program.

Off-Balance Sheet Arrangements

As of December 31, 2025, we did not have any material off-balance sheet arrangements other than the commitments described in Note 13 to the Consolidated Financial Statements and the MVP B and MVP C guarantees discussed in Note 8 to the Consolidated Financial Statements.

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Commitments and Contingencies

See Note 13 to the Consolidated Financial Statements for a discussion of our commitments and contingencies.

Recently Issued Accounting Standards

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

Critical Accounting Estimates

Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements. Management's discussion and analysis of the Consolidated Financial Statements and results of operations are based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of the Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported therein. The following critical accounting estimates, which were reviewed by the Audit Committee of our Board of Directors, relate to our more significant estimates and assumptions used in the preparation of the Consolidated Financial Statements. Actual results could differ from those estimates.

Oil and Gas Reserves

Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.

Our proved reserve estimates rely on several significant assumptions, including those listed as follows:

•future rates of production and estimated ultimate recoveries of developed and undeveloped reserves;

•our five-year development plan, including the amount and timing of expected development expenditures;

•future liquids recovery in wet-gas areas; and

•commodity prices, production costs and income taxes.

Proved reserve estimates are reassessed annually using geological, reservoir and production performance data. Estimates are prepared by internal engineers and audited by independent engineers. Management evaluates significant changes in development plans, cost structure and operating conditions that could affect reserve quantities.

Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions or governmental restrictions. For example, decreases in prices may reduce certain proved reserves by accelerating the timing at which economic limits are reached. Material changes in proved reserve quantities could affect our depletion rates and, therefore, the Consolidated Financial Statements.

We estimate future net cash flows from proved reserves based on selling prices using the prescribed twelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period and, as such, is subject to change in subsequent periods. Future production and development costs are based on current costs with no escalation. Income taxes are based on currently enacted statutory tax rates and available tax deductions and credits.

Estimate changes during 2025 primarily reflected proved reserves acquired as part of the Olympus Energy Acquisition and development schedule refinements. See Note 17 to the Consolidated Financial Statements for additional information on changes to our proved reserve estimates.

We believe oil and gas reserves is a "critical accounting estimate" because changes in proved reserve estimates and the significant assumptions underlying those estimates could materially affect our results of operations or financial position. Based on proved reserves as of December 31, 2025, we estimate that a 1% change in proved reserves would decrease or increase 2026 depletion expense by approximately $11 million and $21 million, respectively, based on current production estimates for 2026.

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See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."

Income Taxes

We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Consolidated Financial Statements or tax returns. See Notes 1 and 6 to the Consolidated Financial Statements for additional information on our accounting policies for income taxes and the composition of deferred tax assets, valuation allowances and uncertain tax positions.

We believe income taxes is a "critical accounting estimate" because we rely on significant assumptions regarding the likelihood, including whether it is more likely than not, that our deferred tax assets will be recovered from future taxable income and the assessment of the amount of financial statement benefit recorded for uncertain tax positions.

We evaluate deferred tax assets and valuation allowances using all available evidence, both positive and negative, including federal and state taxable income forecasts, state apportionment analyses, reversals of temporary differences, tax planning strategies, prior year carrybacks and the expected utilization of tax credits. We evaluate uncertain tax positions based on the technical merits of each position and the probability of realization.

Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid. Changes in our assumptions are sensitive to numerous factors; however, based on income before taxes for the years ended December 31, 2025, 2024 and 2023, we estimate that a 1% change in our effective tax rate would increase or decrease income tax expense by approximately $30 million, $3 million and $21 million, respectively.

Derivative Instruments

We use derivative commodity instruments primarily to reduce exposure to commodity price risk associated with future sales of natural gas production. See Note 4 to the Consolidated Financial Statements for a description of our derivative instruments and Note 5 to the Consolidated Financial Statements for a description of the fair value hierarchy. The values reported in the Consolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, many of which are beyond our control, change.

We believe derivative instruments is a "critical accounting estimate" because changes in the market value of our derivative instruments resulting from the volatility of both NYMEX natural gas prices and basis can materially affect our results of operations or financial position. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. The sensitivity of our derivative fair value measurements to changes in natural gas prices is quantified through the hypothetical 10% price change analysis disclosed in Item 7A., "Quantitative and Qualitative Disclosures about Market Risk," which is calculated using a valuation methodology consistent with our derivative fair value measurements.

Contingencies and Asset Retirement Obligations

We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies when a loss is probable and the amount can be reasonably estimated. Our contingency estimates rely on assumptions about the likelihood of loss and the ability to reasonably estimate a range of potential outcomes. We evaluate contingencies on an ongoing basis in consultation with legal counsel, considering developments in each matter and the potential range of outcomes. See Note 13 to the Consolidated Financial Statements for information on our contingencies.

We also accrue a liability for asset retirement obligations based on the estimated timing and cost of settlement. For oil and gas wells, the fair value of plugging and abandonment obligations is recorded when the obligation is incurred, which is typically at the time the well is spud. Our asset retirement obligation estimates are based on methodologies and assumptions described in Note 1 to the Consolidated Financial Statements, including assessments of the expected timing and cost of settlement and the discount rates applied to determine the present value of future obligations. Estimate changes during 2025 primarily reflected routine updates to plugging cost inputs. There were no material changes to our estimation methodologies.

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We believe contingencies and asset retirement obligations is a "critical accounting estimate" because changes in these estimates and the significant assumptions underlying them could materially affect our results of operations or financial position. Actual losses related to contingencies could differ from our estimates, which may require additional cash expenditures. Changes in the expected timing or amount of asset retirement obligations may require adjustments to the carrying value of our liabilities. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved.

Business Combinations

In a business combination, the identifiable assets acquired and liabilities assumed are recorded at fair value as of the acquisition date. Goodwill results when the cost of an acquisition exceeds the fair value of the net assets acquired.

During 2025, we completed the Olympus Energy Acquisition. The significant assumptions used to estimate the fair value of assets acquired and liabilities assumed in the Olympus Energy Acquisition are discussed in Note 11 to the Consolidated Financial Statements.

We believe business combinations is a "critical accounting estimate" because the valuation of acquired assets and assumed liabilities requires significant judgment about future events and may rely on inputs that are not observable in the market. Changes in these assumptions could materially affect our results of operations or financial position. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved.

Long-Lived Assets (Including Property, Plant and Equipment and Intangible Assets)

See Note 1 to the Consolidated Financial Statements for a discussion of our fair value measurements and impairment evaluations for oil and gas properties, midstream assets, other property, plant and equipment (including our assessment of the recoverability of capitalized costs of unproved oil and gas properties) and intangible assets.

Our impairment evaluations for long-lived assets rely on the following significant assumptions, as applicable:

•future natural gas and NGLs sales prices;

•estimated reserve quantities and expected timing of production;

•future operating costs and capital requirements;

•discount rates and inflation assumptions used in estimating the present value of expected future cash flows; and

•operating levels, utilization and other asset-specific performance expectations (e.g., projected gathered and processed volumes and transmission throughput for midstream assets; expected contract utilization for intangible assets related to acquired transmission service agreements).

We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying amounts may not be recoverable. We consider indicators such as changes in commodity prices, well performance, expected development activity, operating cost trends, asset utilization levels and asset-specific market conditions. When indicators are present, we estimate recoverable value using income-based and, when appropriate, market-based valuation techniques. There were no indicators of impairment to our material asset groups identified during 2025, 2024 and 2023.

We believe long-lived asset impairment is a "critical accounting estimate" because these evaluations require significant judgment about future events. Changes in these assumptions could materially affect our results of operations or financial position, including the timing or amount of impairment charges. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved.

See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."

Investments in Unconsolidated Entities

See Notes 1 and 8 to the Consolidated Financial Statements for a discussion of our accounting policies for investments in unconsolidated entities and the carrying value of our investments.

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Our impairment evaluations for investments in unconsolidated entities rely on the following significant assumptions, as applicable:

•expected future cash flows of the investee, including assumptions regarding commodity prices, operating costs and capital requirements;

•the investee’s ability to generate cash flows sufficient to recover our carrying value; and

•market, operational or financial developments that may affect the recoverability of the investment.

We evaluate investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the carrying amounts may not be recoverable. We consider indicators such as changes in the investee's financial condition, operating performance, forecasted cash flows or market environment. When indicators are present, we estimate recoverable value using expected future cash flows or other relevant valuation information. There were no indicators of impairment to our investments in unconsolidated entities identified during 2025, 2024 and 2023.

We believe the impairment of investments in unconsolidated entities is a "critical accounting estimate" because these evaluations require significant judgment regarding the investee's ability to recover its carrying value. Changes in assumptions about the investee’s operating performance, cash flows or market environment could materially affect our results of operations or financial position. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved.

Goodwill

Goodwill is tested for impairment annually as of October 1 or when events or changes in circumstances indicate the carrying value of a reporting unit may not be recoverable. Indicators of potential impairment may include adverse changes in market conditions, declining operating performance or negative developments in equity or credit markets.

When performed, a quantitative impairment analysis requires judgment in estimating future cash flows, long-term commodity prices, development and operating costs and discount rates used in determining fair value. For 2025, we performed a qualitative assessment and concluded that it was more likely than not that the fair values of our reporting units exceeded their carrying amounts. Because a quantitative test was not performed, no fair value assumptions were developed. See Note 1 to the Consolidated Financial Statements for a discussion of our goodwill impairment assessment process.

We believe goodwill impairment is a "critical accounting estimate" because these evaluations require significant judgment about future events. Although we performed a qualitative assessment for 2025, the determination of fair value in a quantitative test would be sensitive to assumptions related to forecasted cash flows, market conditions, industry factors and discount rates. Changes in these assumptions could materially affect the estimated fair values of our reporting units and the resulting conclusion on impairment. An estimate of the sensitivity to changes in these assumptions is not practicable given the number of variables involved.