Item 8. Financial Statements and Supplementary Data

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Item 8. Financial Statements and Supplementary Data


						Page Reference
Reports of Independent Registered Public Accounting Firm (PCAOB ID: 42)						84
Statements of Consolidated Operations						90
Statements of Consolidated Comprehensive Incom e						91
Consolidated Balance Sheets						92
Statements of Consolidated Cash Flows						93
Statements of Consolidated Equity						94
Notes to the Consolidated Financial Statements						95

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of EQT Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income (loss), cash flows and equity for each of the three years in the period ended December 31, 2024, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 19, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Depreciation, depletion and amortization ('DD&A') of proved oil and natural gas properties


Description of the Matter			At December 31, 2024, the net book value of the Company's proved oil and natural gas properties was $19,497 million, and depreciation and depletion (DD&A) expense of the Company's Production segment was $2,017 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the Company’s internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the Company's engineers, are used to calculate depletion on property acquisitions. Proved natural gas, natural gas liquids (NGLs) and oil reserve estimates are based on geological and engineering evaluations of in-place hydrocarbon volumes. Significant judgment is required by the Company’s engineers in evaluating geological and engineering data when estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including natural gas, NGLs and oil price assumptions and future operating and capital costs assumptions, among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the Company's internal engineers as of December 31, 2024. Auditing the Company's DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of management's determination of the inputs described above used by those engineers in estimating proved natural gas, NGLs and oil reserves.

How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company's controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the internal and external engineers for use in estimating the proved natural gas, NGLs and oil reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff and the independent engineers used to audit the estimates. In addition, we evaluated the completeness and accuracy of the financial data and inputs described above used by the internal and external engineers in estimating proved natural gas, NGLs and oil reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management's development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company's drill plan and the availability of capital relative to the drill plan. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved natural gas, NGLs, and oil reserves amounts used to the Company's reserve report.

Valuation of Acquired property, plant and equipment and the investment in the MVP Joint Venture related to the Equitrans Midstream Merger


Description of the Matter			As described in Note 6 to the consolidated financial statements, on July 22, 2024, the Company completed the Equitrans Midstream Merger. The Company's accounting for the Equitrans Midstream Merger included determining the fair value of the acquired property, plant and equipment (PP&E) and the investment in the MVP Joint Venture. The determination of fair value of the PP&E and investment in the MVP Joint Venture included significant judgment and assumptions by management, including future revenue, future operating costs, and a market-based discount rate. Auditing the Company's valuation of PP&E and the investment in the MVP Joint Venture involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above which include future market and economic conditions.

How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company's process to estimate fair value for the acquired natural gas and oil properties. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions that are inputs to the fair value calculation and management’s review of the valuation model. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the external valuation advisors used to assist with the determination of the fair value of certain acquired assets. Our testing of the Company's estimate of fair value of the PP&E and investment in the MVP Joint Venture included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit procedures involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions described above used to develop the fair value estimate. We assessed the reasonableness of management's assumptions by comparing the key market-related assumptions, such as the market-based discount rate used to develop the fair value estimates.

Accounting for the new Midstream Joint Venture


Description of the Matter			As more fully described in Note 8 to the consolidated financial statements, on November 22, 2024, the Company entered into a contribution agreement (the Contribution Agreement) with an affiliate of Blackstone Credit & Insurance (the BXCI Affiliate) to form a new midstream joint venture (the Midstream Joint Venture). On December 30, 2024, the transactions contemplated by the Contribution Agreement were consummated and, among other things, (i) EQM and certain of its subsidiaries contributed certain midstream assets (through the contribution of certain entities and equity interests) to the Midstream Joint Venture in exchange for 364,285,715 Class A Units in the Midstream Joint Venture and (ii) the BXCI Affiliate contributed $3.5 billion of cash (net of certain transaction fees and expenses) to the Midstream Joint Venture in exchange for 350,000,000 Class B Units in the Midstream Joint Venture (the Class B units). The Company determined the Class B units should be classified as noncontrolling interests within permanent equity. We identified management's evaluation of whether the Class B units should be classified as noncontrolling interests within permanent equity as a critical audit matter. Management applied judgment in assessing relevant terms, provisions, and other conditions, relative to the applicable accounting guidance, to determine the appropriate classification of the Class B units noncontrolling interests. Auditing these assessments made by management involved challenging auditor judgment due to the extent of specialized skills or knowledge required.

How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's accounting for the Midstream Joint Venture. For example, we tested controls over the initial recognition and measurement of the Midstream Joint Venture, including the recording of the noncontrolling interest. To test the initial accounting for the Midstream Joint Venture, our audit procedures included, among others, inspection of the underlying agreements and testing management's application of the relevant accounting guidance, including the determination of the balance sheet classification of the noncontrolling interest. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the Midstream Joint Venture, including conclusions reached with respect to the recognition of the noncontrolling interest.

/s/ Ernst & Young LLP

We have served as the Company's auditor since 1950.

Pittsburgh, Pennsylvania

February 19, 2025

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of EQT Corporation

Opinion on Internal Control Over Financial Reporting

We have audited EQT Corporation and subsidiaries' internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.

As indicated in the accompanying Managements’ Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Equitrans Midstream which are included in the 2024 consolidated financial statements of the Company and constituted approximately 25% of total assets as of December 31, 2024 and approximately 5% of total operating revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Equitrans Midstream.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2024 and the related notes and the financial statement schedule listed in the Index at Item 15(a), and our report dated February 19, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 19, 2025

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

YEARS ENDED DECEMBER 31,


	2024		2023		2022

	(Thousands, except per share amounts)
Operating revenues:
Sales of natural gas, natural gas liquids and oil	$	4,934,366	$	5,044,768	$	12,114,168
Gain (loss) on derivatives	51,117		1,838,941		(4,642,932)
Pipeline, net marketing services and other	287,826		25,214		26,453
Total operating revenues	5,273,309		6,908,923		7,497,689
Operating expenses:
Transportation and processing	1,915,616		2,157,260		2,116,976
Production	377,007		239,001		298,388
Operating and maintenance	110,393		15,699		2,597
Exploration	2,735		3,330		3,438
Selling, general and administrative	336,724		236,171		252,645
Depreciation, depletion and amortization	2,162,350		1,732,142		1,665,962
(Gain) loss on sale/exchange of long-lived assets	(764,044)		17,445		(8,446)
Impairment and expiration of leases	97,368		109,421		176,606
Impairment of contract asset	—		—		214,195
Other operating expenses	349,864		84,043		57,331
Total operating expenses	4,588,013		4,594,512		4,779,692
Operating income	685,296		2,314,411		2,717,997
(Income) loss from investments	(76,039)		(7,596)		4,931
Other income	(25,983)		(1,231)		(11,280)
Loss on debt extinguishment	68,299		80		140,029
Interest expense, net	454,825		219,660		249,655
Income before income taxes	264,194		2,103,498		2,334,662
Income tax expense	22,079		368,954		553,720
Net income	242,115		1,734,544		1,780,942
Less: Net income (loss) attributable to noncontrolling interests	11,538		(688)		9,977
Net income attributable to EQT Corporation	$	230,577	$	1,735,232	$	1,770,965

Income per share of common stock attributable to EQT Corporation:
Basic:
Weighted average common stock outstanding	509,597		380,902		370,048
Net income attributable to EQT Corporation	$	0.45	$	4.56	$	4.79

Diluted (Note 12):
Weighted average common stock outstanding	514,593		413,224		406,495
Net income attributable to EQT Corporation	$	0.45	$	4.22	$	4.38

The accompanying notes are an integral part of these Consolidated Financial Statements.

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

YEARS ENDED DECEMBER 31,


	2024		2023		2022

	(Thousands)
Net income	$	242,115	$	1,734,544	$	1,780,942
Other comprehensive income, net of tax:
Other postretirement benefits liability adjustment, net of tax: $252, $59 and $488	363		310		1,617
Comprehensive income	242,478		1,734,854		1,782,559
Less: Comprehensive income (loss) attributable to noncontrolling interests	11,538		(688)		9,977
Comprehensive income attributable to EQT Corporation	$	230,940	$	1,735,542	$	1,772,582

The accompanying notes are an integral part of these Consolidated Financial Statements.

EQT CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,


	2024		2023

	(Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	202,093	$	80,977
Accounts receivable (less allowance for credit losses: $12,529 and $663)	1,132,608		823,695
Derivative instruments, at fair value	143,581		978,634
Income tax receivable	97,378		91,414
Prepaid expenses and other	139,019		38,255
Total current assets	1,714,679		2,012,975

Property, plant and equipment	44,505,504		33,817,169
Less: Accumulated depreciation and depletion	12,757,686		10,866,999
Net property, plant and equipment	31,747,818		22,950,170

Investments in unconsolidated entities	3,617,397		92,666
Net intangible assets	215,257		22,595
Goodwill	2,079,481		—
Other assets	455,623		206,692
Total assets	$	39,830,255	$	25,285,098

LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt	$	320,800	$	292,432
Accounts payable	1,177,656		1,272,522
Derivative instruments, at fair value	446,519		186,363
Accrued interest	167,157		80,520
Other current liabilities	349,417		205,003
Total current liabilities	2,461,549		2,036,840

Revolving credit facility borrowings	150,000		—
Term Loan Facility borrowings	—		1,244,265
Senior notes	8,853,377		4,176,180
Note payable to EQM Midstream Partners, LP	—		82,236
Deferred income taxes	2,851,103		1,904,821
Other liabilities and credits	1,236,090		1,059,939
Total liabilities	15,552,119		10,504,281

Equity:
Common stock, no par value, shares authorized: 1,280,000 and 640,000, shares issued: 596,870 and 419,896	18,014,711		12,093,986
Retained earnings	2,585,238		2,681,898
Accumulated other comprehensive loss	(2,321)		(2,684)
Total common shareholders' equity	20,597,628		14,773,200
Noncontrolling interest in consolidated subsidiaries	3,680,508		7,617
Total equity	24,278,136		14,780,817
Total liabilities and equity	$	39,830,255	$	25,285,098

The accompanying notes are an integral part of these Consolidated Financial Statements.

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

YEARS ENDED DECEMBER 31,


	2024		2023		2022

	(Thousands)
Cash flows from operating activities:
Net income	$	242,115	$	1,734,544	$	1,780,942
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	14,732		384,666		534,612
Depreciation, depletion and amortization	2,162,350		1,732,142		1,665,962
(Gain) loss on sale/exchange of long-lived assets	(764,044)		17,445		(8,446)
Impairments	97,368		109,421		390,801
(Income) loss from investments	(76,039)		(7,596)		4,931
Loss on debt extinguishment	68,299		80		140,029
Share-based compensation expense	158,344		49,834		45,201
Distributions from equity method investments	66,200		18,693		50,220
Other	15,069		16,943		32,645
(Gain) loss on derivatives	(51,117)		(1,838,941)		4,642,932
Net cash settlements received (paid) on derivatives	1,217,895		900,650		(5,927,698)
Net premiums (paid) received on derivatives	(42,394)		(322,663)		14,200
Changes in other assets and liabilities:
Accounts receivable	(220,446)		867,679		(168,978)
Accounts payable	16,512		(406,113)		181,459
Other current assets	(85,256)		93,787		48,576
Other items, net	7,385		(171,721)		38,172
Net cash provided by operating activities	2,826,973		3,178,850		3,465,560
Cash flows from investing activities:
Capital expenditures	(2,253,709)		(2,019,037)		(1,400,443)
Cash paid for acquisitions, net of cash acquired	(874,265)		(2,271,881)		(205,347)
Proceeds from sale/exchange of assets	1,696,121		4,200		8,572
Proceeds from sale of investment shares	—		—		189,249
Capital contributions to equity method investments	(148,049)		(12,092)		(1,394)
Other investing activities	(80)		(14,845)		(12,390)
Net cash used in investing activities	(1,579,982)		(4,313,655)		(1,421,753)
Cash flows from financing activities:
Proceeds from revolving credit facility borrowings	6,887,000		1,007,000		10,242,000
Repayment of revolving credit facility borrowings	(7,451,200)		(1,007,000)		(10,242,000)
Proceeds from issuance of debt	750,000		1,250,000		1,000,000
Proceeds from net settlement of Capped Call Transactions (Note 10)	93,290		—		—
Debt issuance costs	(18,854)		(5,336)		(26,506)
Repayment and retirement of debt	(4,313,867)		(1,015,836)		(917,039)
(Premiums paid) discounts received on debt extinguishment	(52,432)		5,178		(135,308)
Dividends paid	(326,581)		(228,339)		(203,629)
Repurchase and retirement of common stock	—		(201,029)		(409,485)
Net proceeds from the sale of units of the Midstream Joint Venture (Note 8)	3,410,392		—		—
Net (distribution to) contribution from noncontrolling interest	(1,640)		(7,322)		3,408
Cash paid for taxes to net settle share-based incentive awards	(102,872)		(41,780)		(24,773)
Other financing activities	889		1,602		14,206
Net cash used in financing activities	(1,125,875)		(242,862)		(699,126)
Net change in cash and cash equivalents	121,116		(1,377,667)		1,344,681
Cash and cash equivalents at beginning of year	80,977		1,458,644		113,963
Cash and cash equivalents at end of year	$	202,093	$	80,977	$	1,458,644

The accompanying notes are an integral part of these Consolidated Financial Statements.

See Note 1 for supplemental cash flow information.

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED EQUITY

YEARS ENDED DECEMBER 31, 2024, 2023 and 2022


	Common Stock			Treasury Stock		(Accumulated Deficit) Retained Earnings		Accumulated Other Comprehensive Loss (a)		Noncontrolling Interest in Consolidated Subsidiaries
	Shares	Amount						Total Equity

	(Thousands, except per share amounts)
Balance at December 31, 2021	376,399	$	10,071,820	$	(18,046)	$	(94,400)	$	(4,611)	$	16,236	$	9,970,999
Comprehensive income, net of tax:
Net income						1,770,965				9,977		1,780,942
Other postretirement benefits liability adjustment, net of tax: $488								1,617				1,617
Dividends ($0.55 per share)						(203,629)						(203,629)
Share-based compensation plans	2,100	23,671		18,046								41,717
Convertible Notes settlements	4	63										63
Repurchase and retirement of common stock	(13,140)	(203,664)				(189,358)						(393,022)
Distribution to noncontrolling interest										(11,592)		(11,592)
Contribution from noncontrolling interest										15,000		15,000
Other										11,233		11,233
Balance at December 31, 2022	365,363	$	9,891,890	$	—	$	1,283,578	$	(2,994)	$	40,854	$	11,213,328
Comprehensive income, net of tax:
Net income (loss)						1,735,232				(688)		1,734,544
Other postretirement benefits liability adjustment, net of tax: $59								310				310
Dividends ($0.61 per share)						(228,339)						(228,339)
Share-based compensation plans	2,274	18,180										18,180
Convertible Notes settlements	8,565	122,830										122,830
Repurchase and retirement of common stock	(5,906)	(91,545)				(109,484)						(201,029)
Tug Hill and XcL Midstream Acquisition (Note 6)	49,600	2,152,631										2,152,631
Distribution to noncontrolling interest										(11,072)		(11,072)
Contribution from noncontrolling interest										3,750		3,750
Dissolution of consolidated variable interest entity										(25,227)		(25,227)
Other						911						911
Balance at December 31, 2023	419,896	$	12,093,986	$	—	$	2,681,898	$	(2,684)	$	7,617	$	14,780,817
Comprehensive income, net of tax:
Net income						230,577				11,538		242,115
Other postretirement benefits liability adjustment, net of tax: $252								363				363
Dividends ($0.63 per share)						(327,237)						(327,237)
Share-based compensation plans	4,554	70,688										70,688
Convertible Notes settlements	19,992	285,608										285,608
Net settlement of Capped Call Transactions		93,290										93,290
Equitrans Midstream Merger (Note 6)	152,428	5,548,608								162,993		5,711,601
Change in ownership of consolidated subsidiary, net (Note 8)		(77,469)								3,500,000		3,422,531
Distribution to noncontrolling interest										(1,640)		(1,640)
Balance at December 31, 2024	596,870	$	18,014,711	$	—	$	2,585,238	$	(2,321)	$	3,680,508	$	24,278,136

Common shares authorized (in thousands): 640,000, 640,000 and 1,280,000. Preferred shares authorized (in thousands): 3,000. There were no preferred shares issued or outstanding.

(a)Amounts included in accumulated other comprehensive loss are related to other postretirement benefits liability adjustments, net of tax, which are attributable to net actuarial losses and net prior service costs.

The accompanying notes are an integral part of these Consolidated Financial Statements.

EQT CORPORATION AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2024

1. Summary of Significant Accounting Policies

Nature of Operations. EQT Corporation is an integrated natural gas company with production, gathering and transmission operations focused in the Appalachian Basin.

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

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

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

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

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

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

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

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

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

Cash and Cash Equivalents. The Company considers all highly-liquid investments with an original maturity of three months or less when purchased to be cash equivalents and accounts for such investments at cost. Interest earned on cash equivalents is included as a reduction of interest expense, net.

Accounts Receivable, Net of Allowance for Credit Losses. The Company's accounts receivable relates primarily to the sales of natural gas, natural gas liquids (NGLs) and oil and amounts due from joint interest partners. See Note 3 for a discussion of amounts due from contracts with customers. Reserves for uncollectible accounts are recorded in selling, general and administrative expense in the Statements of Consolidated Operations. Judgment is required to assess the ultimate realization of the Company's accounts receivable. Reserves are based on historical experience, current and expected economic trends and specific information about customer accounts, such as the customer's creditworthiness.

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

Prepaid Expenses and Other. The following table summarizes the Company's prepaid expenses and other current assets.


	December 31,
	2024		2023

	(Thousands)
Margin requirements with counterparties (see Note 4)	$	86,975	$	13,017
Prepaid expenses and other current assets	52,044		25,238
Total prepaid expenses and other	$	139,019	$	38,255

Property, Plant and Equipment. The following table summarizes the Company's property, plant and equipment.


	December 31,
	2024		2023

	(Thousands)
Oil and gas producing properties	$	33,549,913	$	32,510,595
Less: Accumulated depletion	12,489,317		10,734,099
Net oil and gas producing properties	21,060,596		21,776,496
Other production assets, at cost less accumulated depreciation	20,434		21,679
Net production assets	21,081,030		21,798,175

Gathering assets	8,067,556		1,153,049
Less: Accumulated depreciation	131,546		41,793
Net gathering assets	7,936,010		1,111,256

Transmission and storage assets	2,667,352		—
Less: Accumulated depreciation	30,027		—
Net transmission and storage assets	2,637,325		—

Other property, plant and equipment, at cost less accumulated depreciation	93,453		40,739
Net property, plant and equipment	$	31,747,818	$	22,950,170

The Company uses the successful efforts method of accounting for gas, NGLs and oil producing activities. Under this method, the cost of productive wells and related equipment, development dry holes and productive acreage, including productive mineral interests, are capitalized and depleted using the unit-of-production method. These costs include salaries, benefits and other internal costs directly attributable to production activities. In 2024, 2023 and 2022, the Company capitalized internal costs of approximately $69 million, $57 million and $48 million, respectively, to its oil and gas producing properties. In addition, in 2024, 2023 and 2022, the Company capitalized interest expense related to well development of approximately $54 million, $41 million and $28 million, respectively. Depletion expense is calculated based on actual produced sales volume multiplied by the applicable depletion rate per unit. Depletion rates for leases and wells are each calculated by dividing net capitalized costs by the number of units expected to be produced over the life of the reserves separately. Costs for exploratory dry holes, exploratory geological and geophysical activities and delay rentals as well as other property carrying costs are charged to exploration expense. The Company's producing oil and gas properties had an overall average depletion rate of $0.90, $0.84 and $0.85 per Mcfe for the years ended December 31, 2024, 2023 and 2022, respectively.

There were no exploratory wells drilled during 2024, 2023 and 2022, and there were no capitalized exploratory well costs for the years ended December 31, 2024, 2023 and 2022.

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

Impairment of Property, Plant and Equipment

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

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

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

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

Investments in Unconsolidated Entities. See Note 11 for a discussion of the Company's investments in unconsolidated entities, which include EQT's equity method investments and investments in equity securities. The Company evaluates its investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the investment's fair value is less than its carrying amount. The recognition of an impairment loss is required if the impairment is considered other than temporary. There were no indicators of impairment to the Company's investments in unconsolidated entities identified during 2024, 2023 and 2022.

Net Intangible Assets. As part of the Equitrans Midstream Merger preliminary purchase price allocation, the Company identified intangible assets related to certain of Equitrans Midstream's transmission services contracts. See Note 6. The Company evaluates its intangible assets for impairment when indicators of impairment are present. There were no indicators of impairment to the Company's net intangible assets identified during 2024.

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

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

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

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

Other Current Liabilities. The following table summarizes the Company's other current liabilities.


	December 31,
	2024		2023

	(Thousands)
Accrued taxes other than income	$	114,700	62,391
Accrued incentive compensation	53,138		24,542
Current portion of long-term capacity contracts	43,697		43,233
Current portion of lease liabilities	41,878		46,380
Deferred revenue	24,187		2,890
Accrued payroll	12,115		8,870
Other accrued liabilities	59,702		16,697
Total other current liabilities	$	349,417	$	205,003

Unamortized Debt Discount and Issuance Costs. Discounts and costs incurred with the issuance of debt are amortized over the life of the debt. These amounts are presented as a reduction of debt in the Consolidated Balance Sheets. See Note 10.

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

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

EQM, Eureka Midstream Holdings and the Midstream Joint Venture are treated as partnerships for U.S. federal and applicable state income tax purposes and are not separately subject to U.S. federal or state income taxes. EQM's, Eureka Midstream Holdings' and the Midstream Joint Venture's income is included in the Company's pre-tax income; however, the Company does not record income tax expense on income attributable to noncontrolling interests in Eureka Midstream Holdings and the Midstream Joint Venture, which reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the effective tax rate in periods when the Company has consolidated pre-tax losses.

Deferred tax assets and liabilities arise from temporary differences between the financial reporting and tax bases of the Company's assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that a portion or all of the deferred tax asset will not be realized. When evaluating whether or not a valuation allowance should be established, the Company exercises judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of the deferred tax assets will not be realized. To determine whether a valuation allowance is needed, the Company considers all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income.

In accounting for uncertainty of a tax position taken or expected to be taken in a tax return, the Company uses a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If it is more likely than not that a tax position will be sustained, the Company measures and recognizes the tax position at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. To determine the amount of financial statement benefit recorded for uncertain tax positions, the Company considers the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense. See Note 9.

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

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

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

The Company is under no legal or contractual obligation to restore or dismantle its gathering and transmission pipeline assets upon abandonment. In addition, the Company is responsible for the operation and maintenance of its gathering and transmission assets and intends to continue such operation and maintenance so long as supply and demand for natural gas exists. As the Company expects supply and demand for natural gas to exist into the foreseeable future, the Company has not recorded asset retirement obligations for its gathering and transmission pipeline assets.

The following table presents a reconciliation of the beginning and ending carrying amounts of the Company's asset retirement obligations included in other liabilities and credits in the Consolidated Balance Sheets.


	December 31,
	2024		2023

	(Thousands)
Balance at January 1	$	911,057	$	732,803
Accretion expense	68,501		47,700
Liabilities incurred	21,587		10,515
Liabilities settled	(66,729)		(33,938)
Liabilities assumed in acquisitions	45,847		64,424
Liabilities removed in divestitures	(28,701)		(6,480)
Change in estimates (a)	52,008		96,033
Balance at December 31	$	1,003,570	$	911,057

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

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

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

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

The following table presents Equitrans, L.P.'s regulated operating revenues and expenses included in the Company's Consolidated Statement of Operations for the period from July 22, 2024 to December 31, 2024.


	July 22, 2024 to December 31, 2024


	(Thousands)
Operating revenues	$	218,569
Operating expenses	$	78,908

The following table presents Equitrans, L.P.'s regulated property, plant and equipment included in the Company's Consolidated Balance Sheet as of December 31, 2024.


	December 31, 2024


	(Thousands)
Property, plant and equipment	$	2,667,352
Less: Accumulated depreciation	30,027
Net property, plant and equipment	$	2,637,325

The Company includes Equitrans, L.P.'s regulated assets and liabilities in its Consolidated Balance Sheet. Equitrans, L.P.'s regulated assets are reported in other assets, and Equitrans, L.P.'s regulated liabilities are reported in other liabilities and credits. The following table summarizes Equitrans, L.P.'s regulated assets and liabilities as of December 31, 2024.


	December 31, 2024


	(Thousands)
Regulated assets:
Deferred taxes (a)	$	142,757
Other recoverable costs (b)	23,182
Total regulated assets	$	165,939
Regulated liabilities:
Deferred taxes (a)	$	8,534
Ongoing postretirement benefits other than pension and other reimbursable costs (c)	20,158
Total regulated liabilities	$	28,692

(a)The regulated asset from deferred taxes is related primarily to a historical deferred income tax position as well as taxes on the equity component of allowance for funds used during construction (AFUDC). The regulated liability from deferred taxes is related to the revaluation of a historical difference between the regulatory and tax bases of regulated property, plant and equipment. Equitrans, L.P. expects to recover the amortization of the deferred income tax positions ratably over the depreciable lives of the underlying assets. In addition, Equitrans, L.P. expects to recover the taxes on the equity component of AFUDC through future rates over the depreciable lives of the underlying long-lived assets.

(b)The regulated asset from other recoverable costs is related primarily to costs associated with Equitrans, L.P.'s asset retirement obligations, which Equitrans, L.P. expects to continue to recover over the next 9.5 years, and costs associated with a legacy postretirement benefits plan, which Equitrans, L.P. expects to continue to recover over the next 7.5 years.

(c)Equitrans, L.P. defers costs for other postretirement benefits plans, which are subject to recovery in approved rates. The related regulated liability reflects lower cumulative actuarial expenses than the amounts recovered through rates. Equitrans, L.P. expects to continue to recover costs as long as the existing recourse rates provide for recovery.

Revenue Recognition. For information on revenue recognition from contracts with customers, see Note 3. For information on gains and losses on derivative commodity instruments, see Note 4.

Transportation and Processing. Costs incurred to gather, process and transport gas produced by the Company to market sales points are recorded as transportation and processing costs in the Statements of Consolidated Operations. The Company markets some transportation for resale. These costs, which are not incurred to transport gas produced by the Company, are reflected as a deduction from net marketing services and other revenues.

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

Other Operating Expenses. The following table summarizes the Company's other operating expenses.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Transaction costs	$	309,419	$	56,263	$	14,185
Changes in legal and environmental reserves, including settlements	16,271		9,342		$	30,394
Other	24,174		18,438		12,752
Total other operating expenses	$	349,864	$	84,043	$	57,331

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

Income Per Share. See Note 12 for a discussion of the Company's common stock and income per share computation.

Supplemental Cash Flow Information. The following table summarizes net cash paid for interest and income taxes and non-cash activity included in the Statements of Consolidated Cash Flows.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Cash paid during the year for:
Interest, net of amount capitalized	$	401,768	$	213,141	$	236,797
Income taxes, net	7,960		13,350		20,773

Non-cash activity during the period for:
Equity issued as consideration for acquisitions (Note 6)	$	5,548,608	$	2,152,631	$	—
Issuance of EQT common stock for Convertible Notes settlement (Note 10)	285,608		122,830		63
First NEPA Non-Operated Asset Divestiture (Note 7)	155,318		—		—
Increase in asset retirement costs and obligations	73,576		106,548		54,608
Increase in right-of-use assets and lease liabilities, net	29,568		45,774		23,356
Capitalization of non-cash equity share-based compensation	10,095		6,287		5,406
Investments in nonconsolidated entities	3,428		—		—
Accrued transaction costs related to the sale of units of the Midstream Joint Venture (Note 8)	1,135		—		—
Dissolution of consolidated variable interest entity	—		25,227		—

Recently Issued Accounting Standards

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

In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures, to improve income tax disclosure requirements. Under this ASU, public business entities must annually (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. This ASU is effective for annual reporting periods beginning after December 15, 2024, and early adoption is permitted. The Company does not expect adoption of ASU 2023-09 to have a material impact on its financial statements and related disclosures.

In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses, to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization and depletion) in commonly presented expense captions (such as cost of sales; selling, general and administrative expense; and research and development). This ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The requirements should be applied prospectively with the option for retrospective application. The Company is evaluating the impact ASU 2024-03 will have on its financial statements and related disclosures.

Subsequent Events. The Company has evaluated subsequent events through the date of the financial statement issuance.

2. Financial Information by Business Segment

Prior to the completion of the Equitrans Midstream Merger, the Company's operations consisted of one reportable segment. Historically, the Company administered all properties as a whole rather than by discrete operating segments and measured financial performance as a single enterprise and not on an area-by-area basis.

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

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

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

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

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

Substantially all of the Company's operating revenues and assets are generated and located in the United States.

Total segment operating income. The follow tables present the Company's profit and loss metric of operating income by segment.


	Year Ended December 31, 2024
	Production		Gathering		Transmission		Total Segment		Intersegment eliminations and other		EQT Corporation

	(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil	$	4,934,366	$	—	$	—	$	4,934,366	$	—	$	4,934,366
Gain (loss) on derivatives	67,880		(16,763)		—		51,117		—		51,117
Pipeline, net marketing services and other	7,587		766,463		218,293		992,343		(704,517)		287,826
Total operating revenues	5,009,833		749,700		218,293		5,977,826		(704,517)		5,273,309
Operating expenses (a):
Transportation and processing	2,619,710		—		—		2,619,710		(704,094)		1,915,616
Production	377,007		—		—		377,007		—		377,007
Operating and maintenance	—		89,897		20,496		110,393		—		110,393
Exploration	2,735		—		—		2,735		—		2,735
Selling, general and administrative (b)	244,450		38,837		17,183		300,470		36,254		336,724
Depreciation, depletion and amortization	2,016,670		89,513		39,406		2,145,589		16,761		2,162,350
(Gain) loss on sale/exchange of long-lived assets	(764,431)		(22)		409		(764,044)		—		(764,044)
Impairment and expiration of leases	97,368		—		—		97,368		—		97,368
Other operating expenses (c)	12,696		—		—		12,696		337,168		349,864
Total operating expenses	4,606,205		218,225		77,494		4,901,924		(313,911)		4,588,013
Operating income (loss)	$	403,628	$	531,475	$	140,799	$	1,075,902	$	(390,606)	$	685,296

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.

(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.

(c)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger. See Note 1 for a summary of the Company's consolidated other operating expenses.


	Year Ended December 31, 2023
	Production		Gathering		Total Segment		Intersegment eliminations and other		EQT Corporation

	(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil	$	5,044,768	$	—	$	5,044,768	$	—	$	5,044,768
Gain on derivatives	1,838,941		—		1,838,941		—		1,838,941
Pipeline, net marketing services and other	12,649		161,395		174,044		(148,830)		25,214
Total operating revenues	6,896,358		161,395		7,057,753		(148,830)		6,908,923
Operating expenses (a):
Transportation and processing	2,306,090		—		2,306,090		(148,830)		2,157,260
Production	239,001		—		239,001		—		239,001
Operating and maintenance	—		15,699		15,699		—		15,699
Exploration	3,330		—		3,330		—		3,330
Selling, general and administrative (b)	236,171		—		236,171		—		236,171
Depreciation, depletion and amortization	1,705,311		17,066		1,722,377		9,765		1,732,142
Loss on sale/exchange of long-lived assets	17,445		—		17,445		—		17,445
Impairment and expiration of leases	109,421		—		109,421		—		109,421
Other operating expenses (c)	9,177		—		9,177		74,866		84,043
Total operating expenses	4,625,946		32,765		4,658,711		(64,199)		4,594,512
Operating income (loss)	$	2,270,412	$	128,630	$	2,399,042	$	(84,631)	$	2,314,411

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.

(c)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition (defined in Note 6). See Note 1 for a summary of the Company's consolidated other operating expenses.


	Year Ended December 31, 2022
	Production		Gathering		Total Segment		Intersegment eliminations and other		EQT Corporation

	(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil	$	12,114,168	$	—	$	12,114,168	$	—	$	12,114,168
Loss on derivatives	(4,642,932)		—		(4,642,932)		—		(4,642,932)
Pipeline, net marketing services and other	12,827		96,947		109,774		(83,321)		26,453
Total operating revenues	7,484,063		96,947		7,581,010		(83,321)		7,497,689
Operating expenses (a):
Transportation and processing	2,200,297		—		2,200,297		(83,321)		2,116,976
Production	298,388		—		298,388		—		298,388
Operating and maintenance	—		2,597		2,597		—		2,597
Exploration	3,438		—		3,438		—		3,438
Selling, general and administrative (b)	252,645		—		252,645		—		252,645
Depreciation, depletion and amortization	1,648,808		8,035		1,656,843		9,119		1,665,962
Gain on sale/exchange of long-lived assets	(8,446)		—		(8,446)		—		(8,446)
Impairment and expiration of leases	176,606		—		176,606		—		176,606
Impairment of contract asset	214,195		—		214,195		—		214,195
Other operating expenses (c)	32,605		—		32,605		24,726		57,331
Total operating expenses	4,818,536		10,632		4,829,168		(49,476)		4,779,692
Operating income (loss)	$	2,665,527	$	86,315	$	2,751,842	$	(33,845)	$	2,717,997

(a)The significant expense categories and amounts presented align with information that is regularly provided to the chief operating decision maker.

(c)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition. See Note 1 for a summary of the Company's consolidated other operating expenses.

Reconciliation of total segment operating income to income before income taxes


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Total segment operating income	$	1,075,902	$	2,399,042	$	2,751,842
Intersegment eliminations	457		—		—
Unallocated amounts:
Other revenue	(34)		—		—
Corporate selling, general and administrative	36,254		—		—
Corporate other depreciation and amortization	16,761		9,765		9,119
Corporate other operating expenses (a)	337,168		74,866		24,726
(Income) loss from investments (b)	(76,039)		(7,596)		4,931
Other income	(25,983)		(1,231)		(11,280)
Loss on debt extinguishment	68,299		80		140,029
Interest expense, net	454,825		219,660		249,655
Income before income taxes	$	264,194	$	2,103,498	$	2,334,662

(a)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger for the year ended December 31, 2024. Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition for both years ended December 31, 2023 and 2022. See Note 1 for a summary of the Company's consolidated other operating expenses.

(b)Income from investments for the year ended December 31, 2024 included $78.8 million of equity earnings from the Company's investment in the MVP Joint Venture, which is reported in the Company's Transmission segment.

Total segment assets. The following table presents the Company's total assets by segment. The Company's investment in the MVP Joint Venture is presented in investments in unconsolidated entities in the Consolidated Balance Sheet. The Company did not have an investment in the MVP Joint Venture or goodwill prior to completion of the Equitrans Midstream Merger.


	Production		Gathering		Transmission		Total Segment

December 31, 2024	(Thousands)
Investment in the MVP Joint Venture	$	—	$	—	$	3,534,730	$	3,534,730
Goodwill	—		—		1,217,742		1,217,742
Other segment assets	22,546,098		8,295,625		2,919,532		33,761,255
Total assets	$	22,546,098	$	8,295,625	$	7,672,004	$	38,513,727

December 31, 2023
Total assets	$	23,803,913	$	1,215,627	$	—	$	25,019,540

December 31, 2022
Total assets	$	20,469,506	$	417,117	$	—	$	20,886,623

Reconciliation of total segment assets to total assets


	December 31,
	2024		2023		2022

	(Thousands)
Total segment assets	$	38,513,727	$	25,019,540	$	20,886,623
Intersegment eliminations	(318,835)		(47,471)		(19,288)
Unallocated amounts:
Cash and cash equivalents	202,093		80,977		1,458,644
Income tax receivable	97,378		91,414		—
Other property, plant and equipment, at cost less accumulated depreciation	93,453		40,739		32,594
Goodwill (a)	861,739		—		—
Regulated asset from deferred taxes	142,757		—		—
Other	237,943		99,899		311,353
Total assets	$	39,830,255	$	25,285,098	$	22,669,926

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

Total segment capital expenditures. The following table presents the Company's capital expenditures by segment.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Production	$	2,003,635	$	1,878,417	$	1,427,995
Gathering	202,264		31,701		6,155
Transmission	31,446		—		—
Total segment capital expenditures	2,237,345		1,910,118		1,434,150
Other corporate items	28,603		15,125		5,962
Total capital expenditures	$	2,265,948	$	1,925,243	$	1,440,112

Consolidated GGA

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

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

The Company's Production and Gathering segments recorded their respective derivative liability and asset and any gain or loss related to the Henry Hub Cash Bonus. During the fourth quarter of 2024, the EQT Party paid $4.2 million to the EQM Affiliate, and, as of December 31, 2024, the derivative related to the Henry Hub Cash Bonus was settled. As of December 31, 2023, the derivative related to the Henry Hub Cash Bonus had a fair value of approximately $48 million. The fair value of the derivative asset and liability related to the Henry Hub Cash Bonus was based on significant inputs that are interpolated from observable market data and, as such, was a Level 2 fair value measurement. See Note 5 for a description of the fair value hierarchy.

3. Revenue from Contracts with Customers

Sales of natural gas, NGLs and oil. Under the Company's natural gas, NGLs and oil sales contracts, the Company generally considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. These contracts typically require payment within 25 days of the end of the calendar month in which the commodity is delivered. A significant number of these contracts contain variable consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company's efforts to satisfy the performance obligations. Other contracts, such as fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices, contain fixed consideration. The Company allocates the fixed consideration to each performance obligation on a relative standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price.

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

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

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

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

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

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

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

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

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

Disaggregated revenue information. The table below provides disaggregated information on the Company's revenues. Certain other revenue contracts are outside the scope of ASU 2014-09, Revenue from Contracts with Customers. These contracts are reported in pipeline, net marketing services and other revenues in the Statements of Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Revenues from contracts with customers:
Production:
Sales of natural gas, NGLs and oil
Natural gas sales	$	4,224,882	$	4,520,817	$	11,448,293
NGLs sales	615,933		427,760		586,715
Oil sales	93,551		96,191		79,160
Sales of natural gas, NGLs and oil	4,934,366		5,044,768		12,114,168

Gathering:
Pipeline revenue
Firm reservation fee revenue (a)	313,987		—		—
Volumetric-based fee revenue (b)	452,476		161,395		96,947
Total	766,463		161,395		96,947

Transmission:
Pipeline revenues
Firm reservation fee revenue	183,088		—		—
Volumetric-based fee revenue	34,968		—		—
Total	218,056		—		—

Intersegment eliminations and other	(704,517)		(148,830)		(83,321)
Total revenues from contracts with customers (c)	5,214,368		5,057,333		12,127,794

Other sources of revenue:
Gain (loss) on derivatives	51,117		1,838,941		(4,642,932)
Net marketing services and other revenues	7,824		12,649		12,827
Total other sources of revenue	58,941		1,851,590		(4,630,105)

Total operating revenues	$	5,273,309	$	6,908,923	$	7,497,689

(a)Firm reservation fee revenue for the year ended December 31, 2024 included unbilled revenues supported by MVCs of $4.2 million.

(b)Volumetric-based fee revenue for the year ended December 31, 2024 included unbilled revenues supported by MVCs of $4.5 million.

(c)For contracts with customers where the Company's performance obligations had been satisfied and an unconditional right to consideration existed as of the balance sheet date, the Company recorded amounts due from contracts with customers of $939.9 million and $584.8 million in accounts receivable in the Consolidated Balance Sheets as of December 31, 2024 and 2023, respectively.

Summary of remaining performance obligations. The following table summarizes the transaction price allocated to the Company's remaining obligations on all contracts with fixed consideration as of December 31, 2024. The table excludes contracts that qualified for the exception to the relative standalone selling price method as of December 31, 2024.


	2025		2026		2027		2028		2029		Thereafter		Total

	(Thousands)


Gathering firm reservation fees:
Third-party contracts	$	101,671	$	92,311	$	85,651	$	85,651	$	85,651	$	371,792	$	822,727
Affiliate contracts	91,918		101,728		101,393		97,701		97,701		1,482,452		1,972,893
Total Gathering firm reservation fees	193,589		194,039		187,044		183,352		183,352		1,854,244		2,795,620

Gathering revenues supported by MVCs:
Third-party contracts	82,396		89,217		80,904		77,153		65,788		185,423		580,881
Affiliate contracts	372,446		397,966		410,621		411,740		410,621		2,042,451		4,045,845
Total Gathering revenues supported by MVCs	454,842		487,183		491,525		488,893		476,409		2,227,874		4,626,726

Transmission firm reservation fees:
Third-party contracts	176,189		174,435		171,768		169,410		166,324		814,742		1,672,868
Affiliate contracts	241,507		261,045		261,045		260,715		260,383		1,964,638		3,249,333
Total Transmission firm reservation fees	417,696		435,480		432,813		430,125		426,707		2,779,380		4,922,201

Total	$	1,066,127	$	1,116,702	$	1,111,382	$	1,102,370	$	1,086,468	$	6,861,498	$	12,344,547

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

In addition, based on total projected contractual revenues, the Company's firm gathering third-party contracts and firm transmission and storage third-party contracts had a weighted average remaining term of approximately 10 years and 11 years, respectively, as of December 31, 2024. Based on total projected contractual revenues, the Company's firm gathering affiliate contracts and firm transmission and storage affiliate contracts had a weighted average remaining term of approximately 14 years and 13 years, respectively, as of December 31, 2024.

4. Derivative Instruments

The Company's primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the Company's operating results. The Company uses derivative commodity instruments to hedge its cash flows from sales of produced natural gas and NGLs. The overall objective of the Company's hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.

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

The Company does not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of the Company's derivative instruments are recognized in operating revenues in gain (loss) on derivatives in the Statements of Consolidated Operations. The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.

Contracts that result in physical delivery of a commodity expected to be sold by the Company in the normal course of business are generally designated as normal sales and are exempt from derivative accounting. Contracts that result in the physical receipt or delivery of a commodity but are not designated or do not meet all of the criteria to qualify for the normal purchase and normal sale scope exception are subject to derivative accounting.

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

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

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

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

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

When the Company enters into exchange traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good faith deposits to guard against the risks associated with changing market conditions. The Company is required to make such deposits based on an established initial margin requirement and the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Consolidated Balance Sheets. When the fair value of such contracts is in a net asset position, the broker may remit funds to the Company. The Company records these deposits as a current liability in the Consolidated Balance Sheets. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the contract. The margin requirements are subject to change at the exchanges' discretion. As of December 31, 2024 and 2023, there were $87.0 million and $13.0 million, respectively, of such deposits recorded as a current asset in the Consolidated Balance Sheets.

The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The table below summarizes the impact of netting agreements and margin deposits on gross derivative assets and liabilities.


	Gross derivative instruments recorded in the Consolidated Balance Sheet		Derivative instruments subject to master netting agreements		Margin requirements with counterparties		Net derivative instruments

December 31, 2024	(Thousands)
Asset derivative instruments, at fair value	$	143,581	$	(117,350)	$	—	$	26,231
Liability derivative instruments, at fair value	446,519		(117,350)		(86,975)		242,194

December 31, 2023
Asset derivative instruments, at fair value	$	978,634	$	(112,203)	$	—	$	866,431
Liability derivative instruments, at fair value	186,363		(112,203)		(13,017)		61,143

5. Fair Value Measurements

The Company records its financial instruments, which are principally derivative instruments, at fair value in the Consolidated Balance Sheets. The Company estimates the fair value of its financial instruments using quoted market prices when available. If quoted market prices are not available, the fair value is based on models that use market-based parameters, including forward curves, discount rates, volatilities and nonperformance risk, as inputs. Nonperformance risk considers the effect of the Company's credit standing on the fair value of liabilities and the effect of the counterparty's credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to EQT's or the counterparty's credit rating and the yield on a risk-free instrument.

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

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

The table below summarizes assets and liabilities measured at fair value on a recurring basis.


			Fair value measurements at reporting date using:
	Gross derivative instruments recorded in the Consolidated Balance Sheets		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)

December 31, 2024	(Thousands)
Asset derivative instruments, at fair value	$	143,581	$	50,300	$	93,281	$	—
Liability derivative instruments, at fair value	446,519		81,074		365,445		—

December 31, 2023
Asset derivative instruments, at fair value	$	978,634	$	66,302	$	912,332	$	—
Liability derivative instruments, at fair value	186,363		42,218		144,145		—

The carrying value of cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. The carrying value of borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and (prior to its redemption) the Term Loan Facility (defined in Note 10) approximates fair value as each facility's interest rate is based on prevailing market rates. The Company considers all of these fair values to be Level 1 fair value measurements.

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

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

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

See Note 1 for a discussion of the fair value measurement and impairment of the Company's property, plant equipment. In addition, see Note 1 for a discussion of impairment of the Company's contract asset, investments in unconsolidated entities, net intangible assets and goodwill. See Note 1 for a discussion of the fair value measurement of the Company's asset retirement obligations. See Note 2 for a discussion of the fair value measurement of the Henry Hub Cash Bonus. See Note 6 for a discussion of the fair value measurement of assets acquired and liabilities assumed in the Equitrans Midstream Merger. See Note 7 for a discussion of the fair value measurement of the assets received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 11 for a discussion of the fair value measurement of the Company's investment in the Investment Fund (defined in Note 11).

6. Acquisitions

Equitrans Midstream Merger

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

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

Upon the closing of the Equitrans Midstream Merger, each share of common stock, no par value, of Equitrans Midstream (Equitrans Midstream common stock) that was issued and outstanding immediately prior to the effective time of the First Merger (other than shares of Equitrans Midstream common stock owned by Equitrans Midstream or its subsidiaries or by the Company) was converted into the right to receive, without interest, 0.3504 shares of EQT common stock, which totaled 152,427,848 shares of EQT common stock with an aggregate value of $5.5 billion, based on an EQT common stock share price of $35.88. In addition, in connection with the closing of the Equitrans Midstream Merger, the Company paid an aggregate of $79.5 million of equity consideration to employees of Equitrans Midstream who did not continue with the Company upon the Equitrans Midstream Merger closing date.

Immediately prior to the completion of the Equitrans Midstream Merger, on July 22, 2024, using borrowings under EQT's revolving credit facility, the Company paid $685.3 million to effect the purchase and redemption of all of the issued and outstanding Series A Perpetual Convertible Preferred Shares, no par value, of Equitrans Midstream (the Equitrans Midstream preferred stock).

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

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

For the year ended December 31, 2024, the Company recognized $304.8 million of transaction costs related to the Equitrans Midstream Merger in other operating expenses in the Statement of Consolidated Operations. Included in such transaction costs was severance and other termination benefits and stock-based compensation costs of $165.4 million, of which $60.8 million was cash and $104.6 million was non-cash.

Allocation of Purchase Price. The Equitrans Midstream Merger was accounted for as a business combination using the acquisition method. The table below summarizes the preliminary purchase price and estimated fair values of assets acquired and liabilities assumed as of July 22, 2024 with the excess of purchase price over estimated fair value of the identified net assets recognized as goodwill. Certain information necessary to complete the purchase price allocation is not yet available, including, but not limited to, final appraisals of assets acquired and liabilities assumed and final income tax computations. The Company expects to complete the purchase price allocation once it has received all necessary information, at which time the value of the assets acquired and liabilities assumed will be revised if necessary.


	Preliminary Purchase Price Allocation

	(Thousands)
Consideration:
Equity	$	5,548,608
Cash (paid in lieu of fractional shares)	29
Redemption of Equitrans Midstream preferred stock	685,337
Settlement of pre-existing relationships	(239,741)
Total consideration	$	5,994,233

Fair value of assets acquired:
Cash and cash equivalents	$	58,767
Accounts receivable, net	82,072
Income tax receivable	2,142
Prepaid expenses and other	22,048
Property, plant and equipment	9,379,642
Investments in unconsolidated entities	3,363,336
Net intangible assets	200,000
Other assets	249,846
Noncontrolling interest in consolidated subsidiaries	(162,993)
Amount attributable to assets acquired	$	13,194,860

Fair value of liabilities assumed:
Current portion of debt	$	699,837
Accounts payable	65,006
Accrued interest	47,996
Other current liabilities	70,951
Revolving credit facility borrowings	1,035,000
Senior notes	6,273,941
Deferred income taxes	935,106
Other liabilities and credits	152,271
Amount attributable to liabilities assumed	$	9,280,108

Goodwill	$	2,079,481

The fair value of Equitrans Midstream's property, plant and equipment, which primarily includes gathering, transmission and storage systems and water infrastructure assets, and Equitrans Midstream's equity method investment in the MVP Joint Venture was measured using a combination of a cost and income approach based on inputs that are not observable in the market and, as such, are Level 3 fair value measurements. Significant inputs to the valuation of Equitrans Midstream's property, plant and equipment and investment in the MVP Joint Venture include replacement costs for similar assets, relative age of the assets, any potential economic or functional obsolescence associated with the assets, future revenue estimates and future operating cost assumptions and estimated weighted average costs of capital.

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

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

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

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

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

See Note 5 for a description of the fair value hierarchy.

Post-Acquisition Operating Results. The table below summarizes amounts contributed by the assets acquired in the Equitrans Midstream Merger, inclusive of intercompany eliminations, to the Company's consolidated results for the period beginning on July 22, 2024 and ending on December 31, 2024.


	July 22, 2024 through December 31, 2024

	(Thousands)
Loss on derivatives	$	(16,763)
Pipeline, net marketing services and other	274,646
Total operating revenues	$	257,883

Net loss (a)	$	(136,946)
Less: Net income attributable to noncontrolling interests	12,879
Net loss attributable to EQT Corporation	$	(149,825)

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

Unaudited Pro Forma Information. The table below summarizes the Company's results as though the Equitrans Midstream Merger had been completed on January 1, 2023. Certain historical amounts were reclassified to conform to the Company's current financial presentation of operations. Such unaudited pro forma information is provided for informational purposes only and does not represent what consolidated results of operations would have been had the Equitrans Midstream Merger occurred on January 1, 2023 nor are they indicative of future consolidated results of operations.


	Years Ended December 31,
	2024		2023

	(Thousands, except per share amounts)
Pro forma operating revenues:
Pro forma sales of natural gas, NGLs and oil	$	4,934,366	$	5,044,768
Pro forma gain on derivatives	17,685		1,887,016
Pro forma pipeline, net marketing services and other	621,214		616,245
Pro forma total operating revenues	$	5,573,265	$	7,548,029

Pro forma net income (a)	$	489,503	$	2,439,515
Less: Pro forma net income attributable to noncontrolling interests	28,303		30,037
Pro forma net income attributable to EQT Corporation	$	461,200	$	2,409,478

Pro forma income per share of common stock attributable to EQT Corporation:
Pro forma net income attributable to EQT Corporation – Basic	$	0.78	$	4.52
Pro forma net income attributable to EQT Corporation – Diluted	$	0.77	$	4.27

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

NEPA Gathering System Acquisition

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

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

Tug Hill and XcL Midstream Acquisition

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

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

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

2022 Asset Acquisition

In the fourth quarter of 2022, the Company completed its acquisition (the 2022 Asset Acquisition) of approximately 4,600 net Marcellus acres in Northeast Pennsylvania for a total purchase price of approximately $56 million. The 2022 Asset Acquisition was accounted for as an asset acquisition, and, as such, the purchase price was allocated to property, plant and equipment.

7. NEPA Non-Operated Asset Divestitures

First NEPA Non-Operated Asset Divestiture. On May 31, 2024, the Company completed the divestiture (the First NEPA Non-Operated Asset Divestiture) of an undivided 40% interest in the Company's non-operated natural gas assets in Northeast Pennsylvania with a carrying amount of approximately $523 million to Equinor USA Onshore Properties Inc. and its affiliates (collectively, the Equinor Parties). The carrying value was composed of approximately $549 million of property, plant and equipment, approximately $6 million of other current liabilities and approximately $20 million of other liabilities and credits. In exchange, as consideration, the Company received from the Equinor Parties cash of $500 million, subject to customary post-closing purchase price adjustments, certain upstream assets and the remaining 16.25% equity interest in the NEPA Gathering System. The total fair value of consideration received, net of liabilities assumed, was approximately $832 million, subject to customary post-closing purchase price adjustments, and included $413 million of property, plant and equipment.

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

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

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

See Note 5 for a description of the fair value hierarchy.

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

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

As a result of the Second NEPA Non-Operated Asset Divestiture, the Company recognized a gain of approximately $463 million in (gain) loss on sale/exchange of long-lived assets in the Statement of Consolidated Operations. The gain was calculated as the carrying value of the divested assets less the consideration received and approximately $7 million of divestiture costs incurred. The long-lived assets divested and resulting gain are reported in the Company's Production segment. The Company used cash proceeds from the Second NEPA Non-Operated Asset Divestiture to repay a portion of outstanding borrowings under EQT's revolving credit facility.

8. The Midstream Joint Venture Transaction

On September 24, 2024, the Company formed PipeBox LLC (the Midstream Joint Venture) as a wholly-owned subsidiary of EQM. On November 22, 2024, EQM entered into a contribution agreement (the Contribution Agreement) with an affiliate of Blackstone Credit & Insurance (the BXCI Affiliate).

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

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

In addition, on December 30, 2024, EQT (solely for the limited purposes set forth therein), EQM, the BXCI Affiliate and the Midstream Joint Venture entered into an amended and restated limited liability company agreement of the Midstream Joint Venture (the JV Agreement). The JV Agreement provides for, among other things, quarterly distributions of available cash flow to the Midstream Joint Venture's unitholders, of which EQM, as Class A Unitholder, will receive 40% and the BXCI Affiliate, as Class B Unitholder, will receive 60% until the Base Return (as defined in the JV Agreement) has been achieved. After the Base Return has been achieved and until the 8th anniversary of the closing of the Midstream Joint Venture Transaction of December 30, 2024, 100% of the Midstream Joint Venture's distributions, including in a liquidation or sale of the Midstream Joint Venture, will be distributed to EQM as Class A Unitholder and zero percent will be distributed to the BXCI Affiliate as Class B Unitholder; after the Base Return has been achieved and from the 8th anniversary of December 30, 2024 and thereafter, no less than 95% of the Midstream Joint Venture's distributions, including in a liquidation or sale of the Midstream Joint Venture, will be distributed to EQM as Class A Unitholder, and up to 5% of the Midstream Joint Venture's distributions will be distributed to the BXCI Affiliate as Class B Unitholder (with specific distribution percentages determined based on the BXCI Affiliate's ownership of Class B Units as of the time of such distribution).

Based on the governing provisions of the JV Agreement, EQT's management determined that the allocation of income between the Company and the BXCI Affiliate should be based on the change in the investors claim on the Midstream Joint Venture's book value. Under this method, the Company recognizes net income/loss attributable to the noncontrolling interest based on changes to the amount that each member would hypothetically receive at each balance sheet date under the JV Agreement's liquidation provisions, assuming that the net assets of the Midstream Joint Venture were liquidated at the recorded amounts, after taking into account any capital transactions between the Company and the BXCI Affiliate.

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

9. Income Taxes

The following table summarizes the Company's income tax expense.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Current:
Federal	$	1,222	$	(10,894)	$	651
State	6,125		(4,818)		18,457
Subtotal	7,347		(15,712)		19,108
Deferred:
Federal	(21,463)		450,091		527,539
State	36,195		(65,425)		7,073
Subtotal	14,732		384,666		534,612
Total income tax expense	$	22,079	$	368,954	$	553,720

For the year ended December 31, 2024, current income tax expense is composed of state and federal income tax liabilities. For the year ended December 31, 2023, current income tax benefit related primarily to 2014 through 2017 audit settlement interest and reduction in prior year state income tax liabilities. For the year ended December 31, 2022, current income tax expense related primarily to state income tax liabilities.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (IRA). The IRA establishes a 15% corporate alternative minimum tax for certain corporations and a 1% excise tax on stock repurchases made by publicly traded U.S. corporations. The IRA also includes new and renewed options for energy credits. These changes are effective for tax years beginning after December 31, 2022. The impact of these changes did not have a material impact on the Company's financial statements and disclosures.

The table below summarizes the reasons for income tax expense differences from amounts computed at the federal statutory rate of 21% on pre-tax income.


	Years Ended December 31,
	2024			2023			2022
	Amount		Rate	Amount		Rate	Amount		Rate

	(Thousands)			(Thousands)			(Thousands)
Income before income taxes	$	264,194		$	2,103,498		$	2,334,662

Tax at statutory rate	$	55,481	21.0%	$	441,735	21.0%	$	490,279	21.0%
State income taxes	5,440		2.1%	50,263		2.4%	48,970		2.1%
Valuation allowance	(9,601)		(3.6)%	(81,483)		(3.9)%	12,685		0.5%
Convertible Notes repurchase premium	—		—%	—		—%	35,957		1.5%
Uncertain tax positions	(16,977)		(6.4)%	(7,015)		(0.3)%	11,135		0.5%
State law change	(11,315)		(4.3)%	(21,670)		(1.0)%	(49,511)		(2.1)%
Federal and state tax credits	(6,537)		(2.5)%	(4,715)		(0.2)%	(4,319)		(0.2)%
Transaction costs	6,041		2.3%	—		—%	—		—%
Other	(453)		(0.2)%	(8,161)		(0.4)%	8,524		0.4%
Income tax expense	$	22,079	8.4%	$	368,954	17.5%	$	553,720	23.7%

The Company's effective tax rate for the year ended December 31, 2024 was lower compared to the U.S. federal statutory rate due primarily to the release of valuation allowances related to capital loss carryforward utilization, expiration of a statute of limitations related to uncertain tax positions, inclusive of interest, and net state deferred tax benefit related to a rate reduction from a Pennsylvania tax law change enacted on July 8, 2022 (the Pennsylvania Tax Legislation). The Pennsylvania Tax Legislation lowered the corporate net income tax rate from 8.99% to 8.49% in 2024 and continues to lower the corporate net income tax rate by 0.5% annually thereafter until the corporate net income tax rate reaches 4.99% in 2031. The rate reductions were partly offset by valuation allowances limiting certain state income tax benefits and non-deductible transaction costs incurred with the Equitrans Midstream Merger.

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

The Company's effective tax rate for the year ended December 31, 2022 was higher compared to the U.S. federal statutory rate due primarily to state income taxes, including valuation allowances limiting certain state income tax benefits and nondeductible repurchase premiums on the Convertible Notes (defined in Note 10), partly offset by state income tax benefits related to the Pennsylvania Tax Legislation. Included in the state law change was a decrease in state net operating loss (NOL) carryforwards of $214.1 million and a decrease in state valuation allowance on NOL carryforwards of $198.5 million.

The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.


	December 31,
	2024		2023

	(Thousands)
Deferred tax assets:
NOL carryforwards	$	708,518	$	740,802
Interest disallowance limitation	106,622		59,668
Federal tax credits	89,644		92,730
Net unrealized losses	80,723		—
State capital loss carryforward	44,496		99,632
Incentive compensation and deferred compensation plans	18,032		16,854
Other	2,433		1,156
Deferred tax assets	1,050,468		1,010,842
Valuation allowance	(257,218)		(290,812)
Net deferred tax asset	793,250		720,030
Deferred tax liabilities:
Property, plant and equipment	(2,516,074)		(2,457,946)
Investment in partnerships	(1,128,279)		—
Net unrealized gains	—		(166,905)
Deferred tax liability	(3,644,353)		(2,624,851)
Net deferred tax liability	$	(2,851,103)	$	(1,904,821)

During 2024, the net deferred tax liability increased by $946.3 million compared to 2023 due primarily to the additional deferred tax liability related to the Company's investment in EQM (treated as a partnership for tax purposes) and the additional deferred tax liabilities that arose from the fair value accounting of net assets acquired in the Equitrans Midstream Merger, partly offset by an increase in net unrealized losses.

The following table presents the expiration periods of the NOL carryforward deferred tax assets and associated valuation allowance by jurisdiction.


	December 31,
	2024		2023

	(Thousands)
NOL carryforwards:
Federal (expires between 2032 and 2037)	$	14,644	$	67,958
Federal (indefinite expiration)	322,258		323,598
State (expires between 2025 and 2037)	347,279		332,153
State (indefinite expiration)	24,337		17,093
Total NOL carryforwards	$	708,518	$	740,802

Valuation allowance on NOL carryforwards:
Federal	$	(14,263)	$	(24,927)
State	(187,321)		(156,700)
Total valuation allowance on NOL carryforwards	$	(201,584)	$	(181,627)

The Company recognizes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, is considered when determining the need for a valuation allowance. To determine whether a valuation allowance is required, the Company uses judgement to estimate future taxable income and considers the tax consequences in the jurisdiction where such taxable income is generated as well as evidence including the Company's current financial position, actual and forecasted results of operations, the reversal of deferred tax liabilities and tax planning strategies in addition to the current and forecasted business economics of the oil and gas industry.

For 2024 and 2023, positive evidence considered included the reversals of financial-to-tax temporary differences, the implementation of and/or ability to employ various tax planning strategies and the Company's estimation of future taxable income. Negative evidence considered included historical pre-tax book losses of the Company and the uncertainty of future commodity prices and inability to generate capital gains. A review of positive and negative evidence regarding these tax benefits resulted in the conclusion that valuation allowances for certain NOLs and state capital loss carryforwards were warranted as it was more likely than not that the Company would not use them prior to expiration.

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

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

The following table reconciles the beginning and ending amount of reserve for uncertain tax positions, excluding interest and penalties.


	2024		2023		2022

	(Thousands)
Balance at January 1	$	89,197	$	204,035	$	182,032
Additions for tax positions taken in current year	11,720		11,986		9,612
Additions (reductions) for tax positions taken in prior years	15,177		(883)		12,391
Reductions for tax positions settled with tax authorities	(29,645)		(125,941)		—
Reductions for lapse in statute of limitations	(13,706)		—		—
Balance at December 31	$	72,743	$	89,197	$	204,035

The following table presents specific line items that were included in the reserve for uncertain tax positions.


	December 31,
	2024		2023		2022

	(Thousands)
If recognized, effect to the effective tax rate	$	67,105	$	83,669	$	117,341
Reduction of related deferred tax asset for general business credit carryforwards and NOLs	$	60,415	$	77,013	$	110,744

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

As of December 31, 2024, the Company believed that, as a result of potential settlements with relevant taxing authorities, it is reasonably possible that a decrease of $14.6 million in unrecognized tax benefits related to state income tax positions may be necessary within twelve months.

In September 2024, the Company settled its consolidated U.S. federal income tax liability with the IRS through 2019 for amounts included in the reserve for uncertain tax positions with minimal impact to the effective tax rate. The settlement resulted in forgone research and development tax credits of $29.6 million, which are reflected in the table above. The refundable alternative minimum tax credits realized with the settlement of the previous IRS audit are included in the income tax receivable in the Consolidated Balance Sheet as of December 31, 2024. As of December 31, 2024, the Company is no longer subject to state examinations by income tax authorities for years prior to 2016 and has considered ongoing state income tax matters in its reserve for uncertain tax positions.

There were no material changes to the Company's methodology for accounting for unrecognized tax benefits during 2024.

10. Debt

The table below summarizes the Company's outstanding debt.


	December 31, 2024						December 31, 2023
	Principal Value		Carrying Value (a)		Fair Value (b)		Principal Value		Carrying Value (a)		Fair Value (b)

	(Thousands)
EQT's revolving credit facility maturing July 23, 2029	$	150,000	$	150,000	$	150,000	$	—	$	—	$	—
Eureka's revolving credit facility maturing November 13, 2025	320,800		320,800		320,800		—		—		—
Term Loan Facility due June 30, 2026	—		—		—		1,250,000		1,244,265		1,244,265
Debentures and senior notes:
EQT's 6.125% notes due February 1, 2025 (c)	—		—		—		601,521		600,389		605,082
EQT's 1.75% convertible notes due May 1, 2026	—		—		—		290,177		286,185		768,554
EQT's 3.125% notes due May 15, 2026	392,915		391,193		382,994		392,915		389,978		373,261
EQT's 7.75% debentures due July 15, 2026	115,000		114,213		119,590		115,000		113,716		121,590
EQM's 7.500% notes due June 1, 2027	500,000		511,377		510,140		—		—		—
EQM's 6.500% notes due July 1, 2027	900,000		915,538		912,159		—		—		—
EQT's 3.90% notes due October 1, 2027	1,169,503		1,166,523		1,137,248		1,169,503		1,165,439		1,121,027
EQT's 5.700% notes due April 1, 2028	500,000		492,640		508,695		500,000		490,376		509,280
EQM's 5.500% notes due July 15, 2028	118,683		118,204		117,382		—		—		—
EQT's 5.00% notes due January 15, 2029	318,494		315,785		314,357		318,494		315,121		316,784
EQM's 4.50% notes due January 15, 2029	742,923		711,754		711,297		—		—		—
EQM's 6.375% notes due April 1, 2029	600,000		608,667		606,774		—		—		—
EQT's 7.000% notes due February 1, 2030 (c)	674,800		671,641		718,358		674,800		671,020		726,645
EQM's 7.500% notes due June 1, 2030	500,000		535,671		534,950		—		—		—
EQM's 4.75% notes due January 15, 2031	1,100,000		1,045,219		1,039,995		—		—		—
EQT's 3.625% notes due May 15, 2031	435,165		430,818		388,111		435,165		430,141		389,925
EQT's 5.750% notes due February 1, 2034	750,000		742,796		744,743		—		—		—
EQM's 6.500% notes due July 15, 2048	80,233		81,338		81,932		—		—		—
EQT's note payable to EQM	—		—		—		88,483		88,483		91,063
Total debt	9,368,516		9,324,177		9,299,525		5,836,058		5,795,113		6,267,476
Less: Current portion of debt (d)	320,800		320,800		320,800		296,424		292,432		774,983
Long-term debt	$	9,047,716	$	9,003,377	$	8,978,725	$	5,539,634	$	5,502,681	$	5,492,493

(a)For EQT's revolving credit facility, Eureka's revolving credit facility and, as of December 31, 2023, EQT's note payable to EQM, the principal value represents carrying value. For all other debt, the principal value less the unamortized debt issuance costs and debt discounts and, for EQM's senior notes, the unamortized fair value adjustments recorded with Equitrans Midstream Merger purchase price accounting represents carrying value.

(b)The carrying value of borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and, as of December 31, 2023, the Term Loan Facility approximates fair value as their interest rates are based on prevailing market rates; therefore, the Company considers the fair value of EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility to be Level 1 fair value measurements. As of December 31, 2023, the Company measured the fair value of EQT's note payable to EQM using Level 3 inputs. For all other debt, fair value is measured using Level 2 inputs. See Note 5 for the fair value hierarchy.

(c)Interest rates for EQT's 7.000% senior notes fluctuate based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Prior to their redemption, interest rates for EQT's 6.125% senior notes fluctuated based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Interest rates for the Company's other senior notes do not fluctuate.

(d)As of December 31, 2024, the current portion of debt included borrowings outstanding under Eureka's revolving credit facility. As of December 31, 2023, the current portion of debt included EQT's 1.75% convertible notes and a portion of EQT's note payable to EQM. Upon the closing of the Equitrans Midstream Merger, EQT's note payable to EQM became an intercompany transaction on a consolidated basis and, as such, was effectively settled on July 22, 2024.

Debt Repayments. The Company repaid, redeemed or repurchased the following debt during the year ended December 31, 2024.


Debt Tranche	Principal		Premiums/(Discounts)		Accrued but Unpaid Interest		Total Cost

	(Thousands)
EQM's 6.000% notes due July 1, 2025 (a)	$	400,000	$	1,284	$	11,933	$	413,217
EQM's 4.125% notes due December 1, 2026 (a)	500,000		—		1,662		501,662
EQM's 5.500% notes due July 15, 2028 (a)	731,317		15,541		18,435		765,293
EQM's 4.50% notes due January 15, 2029 (a)	57,077		(713)		1,177		57,541
EQM's 6.500% notes due July 15, 2048 (a)	469,767		27,012		13,995		510,774
EQM's 4.00% notes due August 1, 2024	300,000		—		6,000		306,000
EQT's 6.125% notes due February 1, 2025	601,521		1,178		13,612		616,311
Term Loan Facility due June 30, 2026	1,250,000		15		6,136		1,256,151
EQT's 1.75% convertible notes due May 1, 2026	583		—		—		583
Total	$	4,310,265	$	44,317	$	72,950	$	4,427,532

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

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

EQT's revolving credit facility may be used for working capital, capital expenditures, share repurchases and any other lawful corporate purposes. EQT's revolving credit facility is underwritten by a syndicate of a large group of financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by EQT. As of December 31, 2024, no one lender of the large group of financial institutions in the syndicate for EQT's revolving credit facility holds more than 10% of the financial commitments under such facility. The large syndicate group and relatively low percentage of participation by each lender are expected to limit the Company's exposure to disruption or consolidation in the banking industry.

EQT is not required to maintain compensating bank balances. EQT's debt issuer credit ratings, as determined by Moody's, S&P or Fitch on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with EQT's revolving credit facility in addition to the interest rate charged by the lenders on any amounts borrowed against EQT's revolving credit facility; the lower EQT's debt credit rating, the higher the level of fees and borrowing rate.

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

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

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

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

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

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

For the period beginning on July 22, 2024 and ending on December 31, 2024, under Eureka's revolving credit facility, the maximum amount of outstanding borrowings was $330 million, the average daily balance was $328 million and interest was incurred at a weighted average annual interest rate of 7.8%. For the period beginning on July 22, 2024 and ending on December 31, 2024, the Company incurred commitment fees of approximately 50 basis points on the undrawn portion of Eureka's revolving credit facility to maintain credit availability.

EQM's Bridge Credit Facility. In connection with its entry into the Contribution Agreement, on November 22, 2024, EQM entered into a debt commitment letter with Royal Bank of Canada (EQM Debt Commitment Letter), pursuant to which Royal Bank of Canada committed, subject to satisfaction of certain conditions, to provide EQM with a senior unsecured bridge term loan facility in an aggregate principal amount of up to $2.3 billion (the Bridge Credit Facility). On December 27, 2024, EQM entered into the Bridge Credit Facility and borrowed $2.23 billion thereunder to fund (with cash on hand) the redemption and repurchase of certain of EQM's senior notes. See "Debt Repayments" table and "EQM's Senior Notes." Upon the closing of the Midstream Joint Venture discussed in Note 8, the Company used a portion of the proceeds from the Midstream Joint Venture Transaction to repay outstanding borrowings, and interest thereon, under the Bridge Credit Facility, and, thereafter, EQM terminated the Bridge Credit Facility.

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

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

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

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

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

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

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

On November 25, 2024, the Company announced EQM's commencement of a tender offer (the EQM Tender Offer) to purchase certain of EQM's senior notes, subject to a maximum aggregate purchase price, excluding accrued and unpaid interest, of up to $1.275 billion, in accordance with acceptance priority levels correlating to the order in which the notes are listed as follows: EQM's 6.500% senior notes due 2048, EQM's 5.500% senior notes due 2028, EQM's 4.50% senior notes due 2029 and EQM's 7.500% senior notes due 2030. On December 10, 2024, the Company announced the early results of the EQM Tender Offer, including an increase of the maximum aggregate purchase price to $1.3 billion. On December 27, 2024, EQM used borrowings under the Bridge Credit Facility and cash on hand to fund the EQM Tender Offer. Refer to "Debt Repayments" for details. In accordance with the established acceptance priority levels, none of EQM's 7.500% senior notes due 2030 were purchased.

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

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

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

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

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

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

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

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

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

Inclusive of January 2024 settlements of Convertible Notes conversion right exercises that were exercised in December 2023, during January 2024, EQT settled $290.2 million aggregate principal amount of Convertible Notes conversion right exercises by issuing an aggregate 20,036,639 shares of EQT common stock to the converting holders at an average conversion price of $38.03.

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

On January 18, 2024, EQT entered into separate termination agreements with each of the Capped Call Counterparties, pursuant to which the Capped Call Counterparties paid EQT an aggregate $93.3 million (the Termination Payments), and the Capped Call Transactions were terminated. EQT received the Termination Payments on January 22, 2024. The Termination Payments were recorded as an increase to shareholders' equity.

11. Investments in Unconsolidated Entities

Equity Method Investments

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

The table below summarizes the Company's equity method investments.


	December 31, 2024				December 31, 2023
	Ownership Interest		Carrying Value		Ownership Interest		Carrying Value
			(Thousands)				(Thousands)
MVP Joint Venture (a):
The MVP (b)	49.3	%	$	3,469,438	—	%	$	—
MVP Southgate	47.2	%	65,292		—	%	—
Total MVP Joint Venture			3,534,730				—

Laurel Mountain Midstream, LLC (c)	31	%	28,757		31	%	39,923
WATT Fuel Cell Corporation (d)	15.63	%	14,533		15.43	%	16,700
Yellowbird Energy LLC (e)	50	%	6,135		—	%	—
Total			$	3,584,155			$	56,623

(a)Mountain Valley Pipeline, LLC (the MVP Joint Venture) is a Delaware series limited liability company joint venture formed among (i) with respect to Series A, an affiliate of EQT and affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating the MVP and (ii) with respect to Series B, a wholly-owned subsidiary of EQT and affiliates of NextEra Energy, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing, owning and operating MVP Southgate.

(b)As discussed in Note 8, upon the completion of the Midstream Joint Venture Transaction, the Company contributed its interest in the MVP (via its Series A ownership interest in the MVP Joint Venture) to the Midstream Joint Venture.

(c)Laurel Mountain Midstream, LLC is a natural gas gathering and processing joint venture formed among the Company, Williams Companies Inc. and certain other energy companies.

(d)Watt Fuel Cell Corporation is a developer and manufacturer of solid oxide fuel cell systems that operate on common, readily available fuels such as natural gas and propane.

(e)Yellowbird Energy LLC is a joint venture formed in 2024 between a subsidiary of EQT and a third-party investor.

The MVP. The MVP is a 303-mile long, 42-inch diameter natural gas interstate pipeline with a total capacity of 2.0 Bcf per day that spans from the Company's transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia. Following receipt of authorization from the Federal Energy Regulatory Commission (the FERC), the MVP entered into service on June 14, 2024 and became available for interruptible or short-term firm transportation service. On July 1, 2024, the MVP commenced long-term firm capacity obligations. A wholly-owned subsidiary of EQM is the operator of the MVP.

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

The Company has a negative basis difference between the carrying value of its equity method investment in the MVP and its proportionate share of the MVP's net assets (composed of fixed assets). The basis difference is accreted over the useful life of the fixed assets, with accretion expense presented in (income) loss from investments in the Company's Statement of Consolidated Operations. As of December 31, 2024, the basis difference, net of accretion, was $1.3 billion.

For the year ended December 31, 2024, the Company's Series A ownership interest (with respect to the MVP) in the MVP Joint Venture was significant as defined by the SEC's Regulation S-X Rule 1-02(w). Accordingly, pursuant to Regulation S-X Rule 4-08(g), the following table presents summarized financial information of the MVP Joint Venture in relation to the MVP for the period beginning on July 22, 2024 and ending December 31, 2024 and as of December 31, 2024.


	July 22, 2024 to December 31, 2024


	(Thousands)
Operating revenues	$	247,360
Operating income	$	126,202
Net income	$	129,773


	December 31, 2024


	(Thousands)
Current assets	$	204,028
Noncurrent assets	9,535,975
Total assets	$	9,740,003

Current liabilities	$	69,303
Noncurrent liabilities	1,514
Total liabilities	70,817
Members' equity	9,669,186
Total liabilities and members' equity	$	9,740,003

MVP Southgate. MVP Southgate is a contemplated interstate pipeline that was approved by the FERC. The pipeline was initially designed to extend approximately 75 miles from the MVP in Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina using 24-inch and 16-inch diameter pipe.

In December 2023, the MVP Joint Venture entered into precedent agreements with Public Service Company of North Carolina, Inc. and Duke Energy Carolinas, LLC. The precedent agreements contemplate a modified project and, among other things, describe certain conditions precedent to the parties' respective obligations regarding MVP Southgate. As modified, the natural gas interstate pipeline would extend approximately 31 miles from the terminus of the MVP in Pittsylvania County, Virginia to planned new delivery points in Rockingham County, North Carolina using 30-inch diameter pipe and have a targeted capacity of 550,000 dekatherms per day. The proposed 31-mile route passes through a portion of the Southern Virginia Mega Site at Berry Hill, which is one of the largest business parks on the East Coast.

On February 3, 2025, the MVP Joint Venture filed an application with the FERC seeking to amend its existing Certificate of Public Convenience and Necessity to reflect the amended project. The Company expects a wholly-owned subsidiary of EQM to operate MVP Southgate upon its completion, which is targeted for June 2028. MVP Southgate is estimated to have a total cost of approximately $370 million to $430 million, excluding AFUDC and certain costs incurred for purposes of the originally certificated project, of which the Company will fund its proportionate share through capital contributions to the MVP Joint Venture.

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

Investments in Equity Securities

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

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

Equitrans Midstream. Prior to the Company's sale of all of its then-owned shares of Equitrans Midstream common stock in 2022, the Company accounted for its investment in Equitrans Midstream as an investment in equity security.

12. Common Stock and Income Per Share

On July 18, 2024, following approval by its shareholders, EQT amended its Restated Articles of Incorporation to increase the authorized number of shares of EQT common stock from 640,000,000 shares to 1,280,000,000 shares.

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

On December 13, 2021, the Company announced that its Board of Directors approved a share repurchase program (the Share Repurchase Program) authorizing the Company to repurchase shares of outstanding EQT common stock for an aggregate purchase price of up to $1 billion, excluding fees, commissions and expenses. On September 6, 2022, the Company announced that its Board of Directors approved a $1 billion increase to the Share Repurchase Program, pursuant to which approval the Company is authorized to repurchase shares of outstanding EQT common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses. The Share Repurchase Program was originally scheduled to expire on December 31, 2023; however, on April 26, 2023, the Company announced that its Board of Directors approved a one-year extension of the Share Repurchase Program, and, on December 18, 2024, the Company announced that its Board of Directors approved an additional two-year extension of the Share Repurchase Program. As a result of such extension, the Share Repurchase Program will expire on December 31, 2026, but it may be suspended, modified or discontinued at any time without prior notice.

From the Share Repurchase Program's inception and through December 31, 2024, the Company has purchased shares under the Share Repurchase Program for an aggregate purchase price of $622.1 million, excluding fees, commissions and expenses. The table below summarizes the Company's share repurchases under the Share Repurchase Program for the years ended December 31, 2023 and 2022. The Company did not repurchase any equity securities during the year ended December 31, 2024.


	Total number of shares purchased	Aggregate purchase price (a)		Average price paid per share (a)
		(Millions)
Year Ended December 31, 2022	13,139,641	$	392.7	$	29.89
Year Ended December 31, 2023	5,906,159	200.0		$	33.86

Total	19,045,800	$	592.7

(a)Excludes fees and broker commissions.

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

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

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

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

The table below provides the computation for basic and diluted income per share.


	Years Ended December 31,
	2024		2023		2022

	(Thousands, except per share amounts)
Net income attributable to EQT Corporation – Basic income available to shareholders	$	230,577	$	1,735,232	$	1,770,965
Add back: Interest expense on Convertible Notes, net of tax	86		7,551		8,019
Diluted income available to shareholders	$	230,663	$	1,742,783	$	1,778,984

Weighted average common stock outstanding – Basic	509,597		380,902		370,048
Options, restricted stock, performance awards and stock appreciation rights	4,625		5,232		5,731
Convertible Notes	371		27,090		30,716
Weighted average common stock outstanding – Diluted	514,593		413,224		406,495

Income per share of common stock attributable to EQT Corporation:
Basic	$	0.45	$	4.56	$	4.79
Diluted	$	0.45	$	4.22	$	4.38

13. Share-Based Compensation Plans

The following table summarizes the Company's share-based compensation expense.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Incentive Performance Share Unit Programs	$	20,919	$	23,915	$	23,443

Restricted stock awards	25,473		20,119		23,028
Stock appreciation rights	—		4,056		17,406
Other programs, including non-employee director awards	3,596		3,110		3,534
Total share-based compensation expense (a)	$	49,988	$	51,200	$	67,411

(a)For the years ended December 31, 2024 and 2023, share-based compensation expense of $105.4 million and $3.6 million, respectively, was included in other operating expenses. Share-based compensation expense for 2024 related primarily to the Equitrans Midstream Merger. There were no such costs in 2022.

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

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

Incentive Performance Share Unit Programs

The Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) has adopted the following programs under each respective Long-Term Incentive Plan (LTIP):

2020 Incentive Performance Share Unit Program (2020 Incentive PSU Program) under the 2019 LTIP;
2021 Incentive Performance Share Unit Program (2021 Incentive PSU Program) under the 2020 LTIP;
2022 Incentive Performance Share Unit Program (2022 Incentive PSU Program) under the 2020 LTIP;
2023 Incentive Performance Share Unit Program (2023 Incentive PSU Program) under the 2020 LTIP; and
2024 Incentive Performance Share Unit Program (2024 Incentive PSU Program) under the 2020 LTIP.

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

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

Executive performance incentive program awards granted in year 2020 are earned based on:

adjusted well costs;
adjusted free cash flow; and
the level of total shareholder return relative to a predefined peer group.

Executive performance incentive program awards granted in year 2021 are earned based on:

the level of absolute total shareholder return and total shareholder return relative to a predefined peer group.

Executive performance incentive program awards granted in year 2022 are earned based on:

the level of absolute total shareholder return and total shareholder return relative to a predefined peer group; and
the Company's performance in achieving its 2025 net zero Scopes 1 and 2 emissions target.

Executive performance incentive program awards granted in years 2023 and 2024 are earned based on:

the level of absolute total shareholder return and total shareholder return relative to a predefined peer group.

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

The following table summarizes Incentive PSU Programs to be settled in stock and classified as equity awards.


Incentive PSU Programs – Equity Settled	Nonvested Shares	Weighted Average Fair Value			Aggregate Fair Value

Outstanding at December 31, 2021	2,754,648	$	16.08		$	44,281,509
Granted in Period	575,120	29.73		(a)	17,098,318
Granted from Multiplier	162,183	29.45			4,776,289
Vested	(625,563)	29.45			(18,422,830)
Forfeited	(4,398)	13.28			(58,405)
Outstanding at December 31, 2022	2,861,990	16.66			47,674,881
Granted in Period	404,790	38.79			15,701,804
Granted from Multiplier	409,383	6.56			2,685,552
Vested	(1,773,994)	6.56			(11,637,401)
Forfeited	(70,616)	37.59			(2,654,455)
Outstanding at December 31, 2023	1,831,553	28.27			51,770,381
Granted in Period	371,500	40.08			14,889,720
Granted from Multiplier	451,805	23.55			10,640,008
Vested	(1,355,415)	23.55			(31,920,023)
Forfeited	(7,092)	45.94			(325,806)
Outstanding at December 31, 2024	1,292,351	$	34.86		$	45,054,280

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

Total capitalized compensation costs related to the Incentive PSU Programs for the years ended December 31, 2024, 2023 and 2022 were $0.5 million, $0.6 million and $0.6 million, respectively. As of December 31, 2024, $10.2 million and $4.8 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2024 Incentive PSU Program and 2023 Incentive PSU Program, respectively, was expected to be recognized over the remainder of the performance periods.

Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions at grant date:


	Incentive PSU Programs Issued During the Years Ended December 31,
	2024	2023 (a)	2022	2021 (a)	2020 (b)

Risk-free rate	4.35%	4.16%	1.52%	0.18%	1.22%
Volatility factor	48.82%	59.31%	65.38%	72.50%	45.41%
Expected term	3 years	3 years	3 years	3 years	3 years

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

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

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

Restricted Stock Unit Awards

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

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

The total fair value of restricted stock unit equity awards vested during the years ended December 31, 2024, 2023 and 2022 was $155.5 million, $23.5 million and $16.6 million, respectively. Total capitalized compensation costs related to the restricted stock unit equity awards was $9.6 million, $5.7 million and $6.6 million for the years ended December 31, 2024, 2023 and 2022, respectively.

As of December 31, 2024, $44.1 million of unrecognized compensation cost related to nonvested restricted stock unit equity awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.0 year.

The following table summarizes restricted stock unit equity award activity as of December 31, 2024.


Restricted Stock – Equity Settled	Nonvested Shares	Weighted Average Fair Value		Aggregate Fair Value

Outstanding at January 1, 2022	3,104,281	$	12.58	$	39,056,435
Granted	1,288,430	21.65		27,893,331
Vested	(1,368,577)	12.16		(16,644,859)
Forfeited	(97,189)	15.56		(1,512,333)
Outstanding at December 31, 2022	2,926,945	16.67		48,792,574
Granted	953,270	31.88		30,389,954
Vested	(1,544,968)	15.20		(23,482,927)
Forfeited	(117,445)	24.52		(2,879,751)
Outstanding at December 31, 2023	2,217,802	23.82		52,819,850
Granted	982,990	34.54		33,950,507
Vested	(4,861,796)	31.98		(155,480,899)
Conversion of Equitrans Midstream awards	5,175,814	35.88		185,708,206
Forfeited	(90,641)	31.92		(2,893,279)
Outstanding at December 31, 2024	3,424,169	$	33.32	$	114,104,385

Non-Qualified Stock Options

The fair value of the Company's option grants was estimated at the grant date using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the year ended December 31, 2020. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of grant. The dividend yield is based on the dividend yield of EQT common stock at the time of grant. Expected volatilities are based on historical volatility of EQT common stock. The expected term represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. There were no stock options granted in 2024, 2023 and 2022.


	Year Ended December 31, 2020

Risk-free interest rate	1.10		%
Dividend yield	—		%
Volatility factor	60.00		%
Expected term	4 years
Number of Options Granted	1,000,000
Weighted Average Grant Date Fair Value	$	1.61

The total intrinsic value of options exercised during the years ended December 31, 2024, 2023 and 2022 was $0.7 million, $1.4 million and $20.2 million, respectively.

The following table summarizes option activity as of December 31, 2024.


Non-Qualified Stock Options	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value

Outstanding at January 1, 2024	1,523,536	$	18.75
Expired	(193,726)	46.21
Exercised	(134,474)	37.91
Outstanding and Exercisable at December 31, 2024	1,195,336	$	12.14	2.3 years	$	40,604,986

Stock Appreciation Rights

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

The awards were accounted for as liability awards and, as such, compensation expense was recorded based on the fair value of the awards as remeasured at the end of each reporting period. Assumptions at grant date are indicated in the table below. The risk-free rate was based on the U.S. Treasury yield curve in effect at the reporting date. The dividend yield was based on the dividend yield of EQT common stock at the reporting date. Expected volatilities were based on a 50-50 blend of the expected term-matched historical volatility as of the valuation date and the weighted-average implied volatility from thirty days prior to the valuation date. The expected term represents the period of time between the valuation date and the midpoint of the exercise window.


	2020 Stock Appreciation Rights

Risk-free interest rate	0.30		%
Dividend yield	—		%
Volatility factor	67.50		%
Expected term	3.28 years
Number of Stock Appreciation Rights Granted	1,240,000
Weighted Average Grant Date Fair Value	$	2.61
Total Intrinsic Value of Exercises	$	—

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

Non-employee Directors' Share-Based Awards

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

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

2025 Awards

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

Effective in 2025, the Compensation Committee granted 1,111,480 restricted stock unit equity awards that follow a three-year graded vesting schedule commencing with the date of grant, assuming continued employment through each vesting date. The share total includes the Company's "equity-for-all" program, instituted in 2021, pursuant to which the Company grants equity awards to all permanent employees.

14. Leases

The Company leases drilling rigs, facilities (including a water storage facility), vehicles and drilling and compression equipment.

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

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

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

The following table summarizes the Company's lease costs.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Operating lease costs	$	41,991	$	26,755	$	19,922
Finance lease costs	5,546		2,414		1,716
Variable and short-term lease costs	33,475		24,151		13,726
Total lease costs (a)	$	81,012	$	53,320	$	35,364

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

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

For the Company's operating leases, as of December 31, 2024, 2023 and 2022, the weighted average remaining term was 3.4 years, 1.6 years and 1.8 years, respectively, and the weighted average discount rate was 5.3%, 4.7% and 4.5%, respectively. For the Company's finance leases, as of December 31, 2024, 2023 and 2022, the weighted average remaining term was 6.8 years, 3.8 years and 3.3 years, respectively, and the weighted average discount rate was 5.1%, 4.8% and 3.9%, respectively.

The Company records its right-of-use assets in other assets and the current and noncurrent portions of its lease liabilities in other current liabilities and other liabilities and credits, respectively, in the Consolidated Balance Sheets. The following table summarizes the Company's right-of-use assets and lease liabilities.


	December 31,
	2024		2023

	(Thousands)
Right-of-Use Assets
Operating	$	60,496	$	42,338
Finance	34,803		6,494
Total right-of-use assets	$	95,299	$	48,832

Lease Liabilities
Current lease liabilities
Operating	$	36,275	$	43,891
Finance	5,603		2,489
Total current lease liabilities	41,878		46,380
Noncurrent lease liabilities
Operating	29,391		8,443
Finance	29,263		3,754
Total noncurrent lease liabilities	58,654		12,197
Total lease liabilities	$	100,532	$	58,577

The following table summarizes the Company's lease payment obligations as of December 31, 2024.


	Operating		Finance		Total

	(Thousands)
2025	$	38,592	$	7,192	$	45,784
2026	8,289		6,420		14,709
2027	7,623		6,057		13,680
2028	6,480		4,806		11,286
2029	5,804		4,523		10,327
Thereafter	5,207		12,126		17,333
Total lease payment obligations	71,995		41,124		113,119
Less: Imputed interest	6,329		6,258		12,587
Present value of lease liabilities	$	65,666	$	34,866	$	100,532

15. Commitments and Contingencies

Purchase Obligations

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

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

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

Legal and Regulatory Proceedings

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

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

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

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

Additionally, following the filing of the Securities Class Action complaint, several other lawsuits were filed in the United States District Court for the Western District of Pennsylvania and the Court of Common Pleas of Allegheny County, Pennsylvania by certain shareholders of EQT against EQT and certain former executives and current and former board members of EQT asserting substantially the same allegations as those raised in the Securities Class Action. These matters are currently pending, the majority of which have been stayed pending a ruling on dispositive motions in the Securities Class Action.

Following the commencement of the Securities Class Action, the parties engaged in fact and expert discovery. In June 2024, the discovery phase of the Securities Class Action was completed. On June 27, 2024, the parties to the Securities Class Action participated in a mediation (the Mediation), which did not result in resolution. A trial date for the Securities Class Action has not been determined.

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

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

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

Other Matters. In addition to the matters described above, the Company, in the normal course of business, is subject to various other pending and threatened legal proceedings in which claims for monetary damages or other relief are asserted. The Company does not anticipate, at the present time, that the ultimate aggregate liability, if any, arising out of such other legal proceedings will have a material adverse effect on the Company’s financial position, results of operations or liquidity.

16. Concentrations of Credit Risk

Revenues and related accounts receivable from the Company's Production segment operations are generated primarily from the sale of produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through the Company's transportation portfolio, including markets in the Gulf Coast, Midwest and Northeast United States and Canada. The Company also contracts with certain processors to market a portion of NGLs on behalf of the Company. The Company is not dependent on any single customer and believes that the loss of any one customer would not have an adverse effect on the Company's ability to sell its natural gas, NGLs and oil.

As of December 31, 2024 and 2023, approximately 96% and 93%, respectively, of the Company's sales of natural gas, NGLs and oil accounts receivable balances represented amounts due from non-end users. The Company manages the credit risk of sales to non-end users by limiting its dealings with only non-end users that meet the Company's criteria for credit and liquidity strength and by regularly monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a non-end user for that non-end user to meet the Company's credit criteria. The Company did not experience any significant defaults on sales of natural gas to non-end users during the years ended December 31, 2024, 2023 and 2022.

The Company is exposed to credit loss in the event of nonperformance by counterparties to its derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company's OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as the financial industry as a whole. The Company uses various processes and analyses to monitor and evaluate its credit risk exposures, including monitoring current market conditions and counterparty credit fundamentals. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions primarily with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.

As of December 31, 2024, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts. During the year ended December 31, 2024, the Company made no adjustments to the fair value of its derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company's established fair value procedure. The Company monitors market conditions that may impact the fair value of its derivative contracts.

Revenues and related accounts receivable from the Company's Gathering and Transmission segments operations are generated predominantly from the transportation of natural gas in Pennsylvania and West Virginia. The Company is not dependent on any single third-party customer and believes that the loss of any one customer would not have an adverse effect on the Company's ability to generate revenues through its gathering, transmission and storage services.

17. Natural Gas Producing Activities (Unaudited)

The following supplementary information presents a summary of the results of natural gas and oil activities in accordance with the successful efforts method of accounting for production activities.

Production Costs

The following tables present total aggregate capitalized costs and costs incurred related to natural gas, NGLs and oil production activities.


	December 31,
	2024		2023

	(Thousands)
Capitalized costs
Proved properties	$	31,986,473	$	30,471,164
Unproved properties	1,563,440		2,039,431
Total capitalized costs	33,549,913		32,510,595
Less: Accumulated depreciation and depletion	12,489,317		10,734,099
Net capitalized costs	$	21,060,596	$	21,776,496


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Costs incurred (a)
Property acquisition:
Proved properties (b)	$	410,805	$	4,142,621	$	82,276
Unproved properties (c)	98,007		575,130		113,523
Exploration	2,735		3,330		3,438
Development	1,848,000		1,782,428		1,298,665

(a)Amounts for all years presented exclude costs for facilities, information technology and other corporate items. In addition, amounts for 2024 exclude midstream assets. Amounts for 2023 and 2022 include costs for midstream assets.

(b)Amounts in 2024 include $267.7 million and $74.7 million for wells and leases, respectively, received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $2,522.3 million, $757.6 million and $719.6 million for wells, midstream assets and leases, respectively, acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $40.5 million for leases acquired in the 2022 Asset Acquisition. See Note 6.

(c)Amounts in 2024 include $10.8 million for unproved properties received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $523.0 million for unproved properties acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $17.1 million for unproved properties acquired in the 2022 Asset Acquisition. See Note 6.

Results of Operations for Producing Activities

The following table presents the results of operations related to natural gas, NGLs and oil production.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Sales of natural gas, NGLs and oil	$	4,934,366	$	5,044,768	$	12,114,168
Transportation and processing	1,915,616		2,157,260		2,116,976
Production	377,007		254,700		300,985
Operating and maintenance	37,951		—		—
Exploration	2,735		3,330		3,438
Depreciation and depletion	2,016,670		1,732,142		1,665,962
(Gain) loss on sale/exchange of long-lived assets	(764,431)		17,445		(8,446)
Impairment and expiration of leases	97,368		109,421		176,606
Income tax expense	316,377		187,463		1,987,323
Results of operations from producing activities, excluding corporate overhead	$	935,073	$	583,007	$	5,871,324

Reserve Information

Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.

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

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

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

For all tables presented, NGLs and oil were converted at a rate of one Mbbl to approximately six million cubic feet (MMcf).


	Years Ended December 31,
	2024	2023	2022

	(MMcfe)
Natural gas, NGLs and oil
Proved developed and undeveloped reserves:
Balance at January 1	27,596,694	25,002,589	24,961,499
Revision of previous estimates	(1,079,677)	(1,402,039)	(654,618)
Purchase of hydrocarbons in place	413,040	2,600,667	141,038
Sale of natural gas in place	(1,562,849)	—	—
Extensions, discoveries and other additions	3,125,620	3,411,750	2,494,713
Production	(2,228,159)	(2,016,273)	(1,940,043)
Balance at December 31	26,264,669	27,596,694	25,002,589
Proved developed reserves:
Balance at January 1	19,558,176	17,513,645	17,218,655
Balance at December 31	18,804,929	19,558,176	17,513,645
Proved undeveloped reserves:
Balance at January 1	8,038,518	7,488,944	7,742,844
Balance at December 31	7,459,740	8,038,518	7,488,944


	Years Ended December 31,
	2024	2023	2022

	(MMcf)
Natural gas
Proved developed and undeveloped reserves:
Balance at January 1	25,795,134	23,824,887	23,523,665
Revision of previous estimates	(917,676)	(1,461,305)	(432,315)
Purchase of natural gas in place	395,423	2,012,159	141,038
Sale of natural gas in place	(1,562,849)	—	—
Extensions, discoveries and other additions	2,921,638	3,326,736	2,434,543
Production	(2,086,441)	(1,907,343)	(1,842,044)
Balance at December 31	24,545,229	25,795,134	23,824,887
Proved developed reserves:
Balance at January 1	18,186,432	16,541,017	16,152,083
Balance at December 31	17,440,191	18,186,432	16,541,017
Proved undeveloped reserves:
Balance at January 1	7,608,702	7,283,870	7,371,582
Balance at December 31	7,105,038	7,608,702	7,283,870


	Years Ended December 31,
	2024	2023	2022

	(Mbbl)
NGLs
Proved developed and undeveloped reserves:
Balance at January 1	285,345	186,141	225,792
Revision of previous estimates	(24,332)	11,558	(33,955)
Purchase of NGLs in place	2,529	90,604	—

Extensions, discoveries and other additions	30,391	13,592	9,610
Production	(22,025)	(16,550)	(15,306)
Balance at December 31	271,908	285,345	186,141
Proved developed reserves:
Balance at January 1	218,523	154,921	169,781
Balance at December 31	217,786	218,523	154,921
Proved undeveloped reserves:
Balance at January 1	66,822	31,220	56,011
Balance at December 31	54,122	66,822	31,220


	Years Ended December 31,
	2024	2023	2022

	(Mbbl)
Oil
Proved developed and undeveloped reserves:
Balance at January 1	14,915	10,142	13,846
Revision of previous estimates	(2,669)	(1,680)	(3,095)
Purchase of oil in place	407	7,481	—

Extensions, discoveries and other additions	3,606	577	418
Production	(1,595)	(1,605)	(1,027)
Balance at December 31	14,664	14,915	10,142
Proved developed reserves:
Balance at January 1	10,101	7,183	7,981
Balance at December 31	9,669	10,101	7,183
Proved undeveloped reserves:
Balance at January 1	4,814	2,959	5,865
Balance at December 31	4,995	4,814	2,959

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

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

The change in reserves during the year ended December 31, 2023 resulted from the following:

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

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

Conversions of 1,365 Bcfe of proved undeveloped reserves to proved developed reserves.
Extensions, discoveries and other additions of 2,495 Bcfe, which exceeded 2022 production of 1,940 Bcfe. Extensions, discoveries and other additions included an increase of 2,077 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2022 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan and 418 Bcfe from converting unproved reserves to proved developed reserves.
Negative revisions of 1,625 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking as a result of development schedule changes, driven largely by third-party impacts, which have pushed planned completion dates into a future period from when originally planned.
Positive revisions to proved undeveloped locations of 518 Bcfe due primarily to changes in ownership interests.
Positive revisions of 356 Bcfe primarily from proved developed locations as a result of positive curve revisions.
Positive revisions of 96 Bcfe from higher pricing that impacted well economics.
Purchase of hydrocarbons in place of 141 Bcfe from the 2022 Asset Acquisition described in Note 6.

Standardized Measure of Discounted Future Cash Flow

Management cautions that the standardized measure of discounted future net cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

The following table summarizes estimated future net cash flows from natural gas and oil reserves.


	December 31,
	2024		2023		2022

	(Thousands)
Future cash inflows (a)	$	44,871,509	$	52,916,665	$	140,032,653
Future production costs (b)	(18,979,056)		(24,357,033)		(22,801,652)
Future development costs	(4,352,890)		(4,298,372)		(3,244,211)
Future income tax expenses	(4,445,354)		(5,230,629)		(26,375,241)
Future net cash flow	17,094,209		19,030,631		87,611,549
10% annual discount for estimated timing of cash flows	(9,095,069)		(9,768,282)		(47,547,025)
Standardized measure of discounted future net cash flows	$	7,999,140	$	9,262,349	$	40,064,524

(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines. Reserves were computed using average first-day-of-the-month closing prices for the prior twelve months less regional adjustments. Regional adjustments were calculated using historical average realized prices received in the Appalachian Basin. NGLs pricing was calculated using average first-day-of-the-month closing prices for the prior twelve months for NGLs components, adjusted using the regional component makeup of proved NGLs.


	December 31,
	2024		2023		2022
Natural gas for NYMEX ($/MMBtu)	$	2.130	$	2.637	$	6.357
Less regional adjustments ($/MMBtu)	0.741		1.029		1.094
Natural gas price ($/Mcf)	1.468		1.700		5.543
NGLs price ($/Bbl)	29.28		28.44		38.66
Oil for West Texas Intermediate (WTI) ($/Bbl)	76.32		78.21		94.14
Less regional adjustments ($/Bbl)	16.87		14.35		17.31
Oil price ($/Bbl)	59.45		63.86		76.83

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

Holding production and development costs constant, an increase in NYMEX price of $0.10 per Dth for natural gas, an increase in WTI price of $10 per barrel for NGLs and an increase in WTI price of $10 per barrel for oil would result in a change in the December 31, 2024 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,184 million, $1,128 million and $73 million, respectively.

The following table summarizes the changes in the standardized measure of discounted future net cash flows.


	Years Ended December 31,
	2024		2023		2022

	(Thousands)
Net sales and transfers of natural gas and oil produced	$	(2,603,792)	$	(2,632,808)	$	(9,696,207)
Net changes in prices, production and development costs	(1,237,271)		(48,739,248)		35,353,172
Extensions, discoveries and improved recovery, net of related costs	464,496		6,347,387		1,798,851
Development costs incurred	1,432,315		1,296,380		902,925
Net purchase of minerals in place	269,453		2,131,567		280,233
Net sale of minerals in place	(692,019)		—		—
Revision of previous estimates	(263,191)		(2,768,922)		(299,423)
Accretion of discount	926,235		4,006,452		1,728,112
Net change in income taxes	411,999		9,190,460		(7,233,051)
Timing and other	28,566		366,557		(51,212)
Net (decrease) increase	(1,263,209)		(30,802,175)		22,783,400
Balance at January 1	9,262,349		40,064,524		17,281,124
Balance at December 31	$	7,999,140	$	9,262,349	$	40,064,524

Following the completion of the Equitrans Midstream Merger as described in Note 6, the Company updated certain of its cost assumptions for estimating its proved reserves to reflect the Company's ownership of the assets acquired in the Equitrans Midstream Merger and the elimination of the gathering, transportation and water service costs from the pre-existing contractual relationships between the Company and Equitrans Midstream, which are treated as intercompany transactions on a consolidated basis. Similarly, the Company updated certain of its future cost assumptions to include the additional expenses required to build and maintain the acquired midstream assets, which are needed to transport the Company's produced gas to the first liquid sales point. Lastly, following the completion of the Midstream Joint Venture Transaction as discussed in Note 8, the Company updated certain of its future cost assumptions to account for changes in the noncontrolling interest ownership of the assets owned by the Midstream Joint Venture. The Company believes that the methodology used in developing these assumptions best reflects the current economic conditions affecting the Company's reserves and gives consideration to the Company's ownership interest in its midstream assets.

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