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美國
證券交易委員會
華盛頓特區20549

表格10-Q
 
☒根據1934年證券交易法第13或15(d)條，本季度報告
截至2022年1月31日的季度期2024年9月30日
或者
☐根據1934年證券交易法第13或15（d)條的轉型報告
在交接期從__________到__________

snps-20220131_g1.jpg001-03551

EQT公司
(根據其章程規定的註冊人準確名稱)
賓夕法尼亞州 25-0464690
（設立或組織的其他管轄區域） （內部稅務服務僱主識別號碼）
625 Liberty Avenue, 1700套房。
匹茲堡, 賓夕法尼亞州
15222
，（主要行政辦公地址）(郵政編碼)
 
(412) 553-5700
（註冊人的電話號碼，包括區號）

在法案第12(b)條的規定下注冊的證券：
每一類的名稱交易標的在其上註冊的交易所的名稱
沒有名義價值的普通股EQT請使用moomoo賬號登錄查看New York Stock Exchange

請用複選標記表示註冊者是否：（1）在過去12個月內已經按照1934年證券交易法第13或15（d）條的要求提交了所有要求提交的報告，且（2）在過去90天內一直受到這些提交要求的約束。 是  ☒沒有☐

請用複選標記表示，註冊人是否根據規則405條款(S-t第232.405章)的規定，在過去12個月內(或註冊人要求提交此類文件的較短期間)已電子方式提交了每個交互式數據文件。 是  ☒沒有☐

請通過覈對標記指示註冊者是否爲大型加速申報人、加速申報人、非加速申報人、較小報告公司或新興增長公司。請參閱《交易所法》第120億.2條中對"大型加速申報人"、"加速申報人"、"較小報告公司"和"新興增長公司"的定義。
大型加速報告人☒加速文件提交人☐
非加速文件提交人☐較小的報告公司☐
新興成長公司☐

如果一家新興成長型公司，請在註冊申報中通過複選標記指出是否選擇不使用根據《交易所法》第13(a)條規定提供的任何新的或修訂後的財務會計準則的延長過渡期。☐

通過勾選來指示公司是否爲空殼公司（如《交易所法》第120億2條規定）。 是☐ 否 ☒

截至2024年10月25日，註冊人普通股的發行數量（以千爲單位）爲： 596,684

目錄


目錄
 
 
 
 
 
 


2
目錄

第一部分 財務信息

項目1。財務報表
EQt 公司及其子公司
未經審計的綜合營運狀況報表
三個月之內結束
2020年9月30日		九個月結束
2020年9月30日
 2024202320242023
 (單位: 千美元，每股金額除外)
營業收入：
天然氣、天然氣液體和石油銷售$1,099,752 $1,001,883 $3,293,174 $3,680,566 
衍生品收益66,816 177,906 234,660 1,167,144 
管道、淨營銷服務及其他117,234 6,313 120,748 18,214 
總營收1,283,802 1,186,102 3,648,582 4,865,924 
營業費用：
運輸和加工440,845 554,788 1,529,093 1,592,934 
產量93,842 62,858 273,042 163,963 
運營和維護40,518 4,235 65,824 6,108 
勘探282 447 2,576 2,602 
銷售、一般及行政費用88,470 56,942 228,730 168,999 
折舊、減值和攤銷589,299 446,886 1,542,031 1,230,255 
長期資產出售/交換的損失（收益）10,117 1,511 (309,865)17,814 
租賃權利減值和到期12,095 6,419 58,963 22,290 
其他營業費用290,174 36,209 354,337 69,265 
營業費用總計1,565,642 1,170,295 3,744,731 3,274,230 
營業（虧損）收入(281,840)15,807 (96,149)1,591,694 
（投資）損失收益(34,242)546 (36,674)(5,310)
其他收入(3,960)(132)(23,596)(869)
債務攤銷損失(收益)365 1,089 5,651 (55)
利息費用，淨額158,299 60,427 268,390 146,856 
（虧損）所得稅前收入(402,302)(46,123)(309,920)1,451,072 
所得稅（收益）費用(104,870)(126,853)(124,790)217,975 
淨（虧損）利潤(297,432)80,730 (185,130)1,233,097 
扣除歸屬於非控制股權的淨利潤（損失）3,391 (525)2,688 (80)
歸屬於EQt公司的淨利潤（虧損）$(300,823)$81,255 $(187,818)$1,233,177 
歸屬於EQt公司的普通股每股（虧損）收益  
基本的：    
加權平均普通股股本559,603 383,359 480,354 368,936 
淨利潤（損失）歸屬於EQt公司$(0.54)$0.21 $(0.39)$3.34 
稀釋後的淨利潤（注9）：
    
加權平均普通股股本559,603 416,190 480,354 401,859 
淨利潤（損失）歸屬於EQt公司$(0.54)$0.20 $(0.39)$3.08 

附註是本簡明合併財務報表的組成部分。

3
目錄


EQt 公司及其子公司
綜合損益簡明綜合(虧損)表(未經審計)
三個月之內結束
2020年9月30日		九個月結束
2020年9月30日
 2024202320242023
 （千美元）
淨（虧損）利潤$(297,432)$80,730 $(185,130)$1,233,097 
其他綜合收益，稅後：    
其他離退休福利責任調整，稅後：$13, $15, $39 和 $44
28 57 114 270 
綜合損益(297,404)80,787 (185,016)1,233,367 
少：歸屬於非控制權益的綜合收益（損失）3,391 (525)2,688 (80)
EQt公司可歸屬於綜合(損失)收益$(300,795)$81,312 $(187,704)$1,233,447 

附註是本簡明合併財務報表的組成部分。

4
目錄


EQt 公司及其子公司
簡化聯合資產負債表（未經審計）
2024年9月30日2023年12月31日
 （千美元）
資產  
流動資產：  
現金及現金等價物$88,980 $80,977 
應收賬款（減少應收賬款壞賬準備：$9,135 和 $663)
577,599 823,695 
衍生工具，按公允價值計量251,657 978,634 
應收所得稅92,791 91,414 
預付費用和其他71,265 38,255 
總流動資產1,082,292 2,012,975 
資產：固定資產44,884,752 33,817,169 
減：累計折舊及遞耗12,338,210 10,866,999 
淨固定資產32,546,542 22,950,170 
對MVP聯營企業的投資3,358,346 — 
淨無形資產268,308 22,595 
商譽2,178,236 — 
其他511,865 299,358 
總資產$39,945,589 $25,285,098 
負債和股東權益  
流動負債:  
償還短期債務$400,150 $292,432 
應付賬款1,042,393 1,272,522 
衍生工具，按公允價值計量197,712 186,363 
應計利息189,965 80,520 
其他流動負債283,730 205,003 
流動負債合計2,113,950 2,036,840 
循環信貸借款2,297,000 — 
融資貸款設施借款497,970 1,244,265 
優先票據10,598,428 4,176,180 
應付款項-腦機合作伙伴EQm— 82,236 
延遲所得稅2,746,292 1,904,821 
其他負債和貸項1,203,631 1,059,939 
負債合計19,457,271 10,504,281 
股東權益：  
普通股，否每股面值，
授權股數： 1,280,000和頁面。640,000發行股份： 596,268和頁面。419,896
18,076,243 12,093,986 
保留盈餘2,261,086 2,681,898 
累計其他綜合損失(2,570)(2,684)
總普通股東權益20,334,759 14,773,200 
被合併子公司的非控制權益153,559 7,617 
股東權益總計20,488,318 14,780,817 
負債和所有者權益總額$39,945,589 $25,285,098 
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

5
Table of Contents


EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS (UNAUDITED)
Nine Months Ended September 30,
 20242023
(Thousands)
Cash flows from operating activities:
Net (loss) income$(185,130)$1,233,097 
Adjustments to reconcile net (loss) income to net cash provided by operating activities:  
Deferred income tax (benefit) expense(123,725)227,701 
Depreciation, depletion and amortization1,542,031 1,230,255 
Gain/loss on sale/exchange of long-lived assets and impairments(250,902)40,104 
Income from investments(36,674)(5,310)
Loss (gain) on debt extinguishment5,651 (55)
Share-based compensation expense141,578 38,179 
Distributions from equity method investments11,187 18,073 
Other13,160 12,022 
Gain on derivatives(234,660)(1,167,144)
Net cash settlements received on derivatives1,037,321 625,051 
Net premiums paid on derivatives(41,970)(231,343)
Changes in other assets and liabilities:  
Accounts receivable 331,452 1,122,843 
Accounts payable(122,252)(515,879)
Other current assets(10,150)91,946 
Other items, net(6,220)(165,076)
Net cash provided by operating activities2,070,697 2,554,464 
Cash flows from investing activities:  
Capital expenditures(1,662,112)(1,485,898)
Cash paid for acquisitions(864,242)(2,288,201)
Proceeds from sale/exchange of assets451,906 4,831 
Capital contributions to equity method investments(87,804)(5,000)
Other investing activities(80)159 
Net cash used in investing activities(2,162,332)(3,774,109)
Cash flows from financing activities:  
Proceeds from revolving credit facility borrowings3,578,000 313,000 
Repayment of revolving credit facility borrowings(2,316,000)(313,000)
Proceeds from issuance of debt750,000 1,250,000 
Proceeds from net settlement of Capped Call Transactions (Note 7)93,290 — 
Debt issuance costs(18,854)(5,336)
Repayment and retirement of debt(1,655,706)(1,014,346)
(Premiums paid) discounts received on debt extinguishment(1,543)5,313 
Dividends paid(232,603)(162,567)
Repurchase and retirement of common stock— (201,029)
Net distribution to noncontrolling interest(1,640)(7,322)
Cash paid for taxes to net settle share-based incentive awards(92,492)(41,238)
Other financing activities(2,814)2,276 
Net cash provided by (used in) financing activities99,638 (174,249)
Net change in cash and cash equivalents8,003 (1,393,894)
Cash and cash equivalents at beginning of period80,977 1,458,644 
Cash and cash equivalents at end of period$88,980 $64,750 
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.
See Note 1 for supplemental cash flow information.

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Table of Contents


EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONDENSED CONSOLIDATED EQUITY (UNAUDITED)
 Common Stock  
 SharesAmountRetained EarningsAccumulated Other
Comprehensive Loss (a)		Noncontrolling Interest in
Consolidated Subsidiaries		Total Equity
 (Thousands, except per share amounts)
Balance at July 1, 2023361,654 $9,790,855 $2,217,698 $(2,781)$39,256 $12,045,028 
Comprehensive income, net of tax:
Net income (loss)  81,255  (525)80,730 
Other postretirement benefits liability adjustment, net of tax: $15
57 57 
Dividends ($0.15 per share)
(54,249)(54,249)
Share-based compensation plans56 14,939   14,939 
Convertible Notes settlements1 16 16 
Tug Hill and XcL Midstream Acquisition49,600 2,152,631 2,152,631 
Distribution to noncontrolling interest(5,279)(5,279)
Dissolution of consolidated variable interest entity(25,227)(25,227)
Other911 911 
Balance at September 30, 2023411,311 $11,958,441 $2,245,615 $(2,724)$8,225 $14,209,557 
Balance at July 1, 2024441,597 $12,464,492 $2,655,940 $(2,598)$6,914 $15,124,748 
Comprehensive loss, net of tax:
Net (loss) income  (300,823) 3,391 (297,432)
Other postretirement benefits liability adjustment, net of tax: $13
28 28 
Dividends ($0.1575 per share)
(94,031)(94,031)
Share-based compensation plans2,243 63,143   63,143 
Equitrans Midstream Merger152,428 5,548,608 144,894 5,693,502 
Distribution to noncontrolling interest(1,640)(1,640)
Balance at September 30, 2024596,268 $18,076,243 $2,261,086 $(2,570)$153,559 $20,488,318 

Common shares authorized (in thousands): 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 Condensed Consolidated Financial Statements.

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EQT CORPORATION AND SUBSIDIARIES
STATEMENTS OF CONDENSED CONSOLIDATED EQUITY (UNAUDITED)
 Common Stock
 SharesAmountRetained EarningsAccumulated Other
Comprehensive Loss (a)		Noncontrolling Interest in
Consolidated Subsidiaries		Total Equity
 (Thousands, except per share amounts)
Balance at January 1, 2023365,363 $9,891,890 $1,283,578 $(2,994)$40,854 $11,213,328 
Comprehensive income, net of tax:
Net income (loss)1,233,177 (80)1,233,097 
Other postretirement benefits liability adjustment, net of tax: $44
270 270 
Dividends ($0.45 per share)
(162,567)(162,567)
Share-based compensation plans2,247 5,367 5,367 
Convertible Notes settlements7 98 98 
Repurchase and retirement of common stock(5,906)(91,545)(109,484)(201,029)
Tug Hill and XcL Midstream Acquisition49,600 2,152,631 2,152,631 
Distribution to noncontrolling interest(11,072)(11,072)
Contribution from noncontrolling interest3,750 3,750 
Dissolution of consolidated variable interest entity(25,227)(25,227)
Other911911 
Balance at September 30, 2023411,311 $11,958,441 $2,245,615 $(2,724)$8,225 $14,209,557 
Balance at January 1, 2024419,896 $12,093,986 $2,681,898 $(2,684)$7,617 $14,780,817 
Comprehensive loss, net of tax:
Net (loss) income(187,818)2,688 (185,130)
Other postretirement benefits liability adjustment, net of tax: $39
114 114 
Dividends ($0.4725 per share)
(232,994)(232,994)
Share-based compensation plans3,952 54,751 54,751 
Convertible Notes settlements19,992 285,608 285,608 
Net settlement of Capped Call Transactions93,290 93,290 
Equitrans Midstream Merger152,428 5,548,608 144,894 5,693,502 
Distribution to noncontrolling interest(1,640)(1,640)
Balance at September 30, 2024596,268 $18,076,243 $2,261,086 $(2,570)$153,559 $20,488,318 

Common shares authorized (in thousands): 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 Condensed Consolidated Financial Statements.

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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited) 

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

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

Basis of Presentation. The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all information and notes required by GAAP for complete financial statements. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals unless otherwise disclosed in this Quarterly Report on Form 10-Q) necessary for a fair presentation of the financial position of the Company as of September 30, 2024 and December 31, 2023, the results of its operations and equity for the three and nine month periods ended September 30, 2024 and 2023 and its cash flows for the nine month periods ended September 30, 2024 and 2023. Certain previously reported amounts have been reclassified to conform to the current period 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.

The Condensed Consolidated Balance Sheet at December 31, 2023 has been derived from the audited financial statements at that date. For further information, refer to the Consolidated Financial Statements and accompanying notes in the Company's Annual Report on Form 10-K for the year ended December 31, 2023.

Principles of Consolidation. The Condensed Consolidated Financial Statements include the accounts of EQT and all subsidiaries, ventures and partnerships in which EQT directly or indirectly holds a controlling interest. Intercompany accounts and transactions have been eliminated in consolidation.

Upon the closing of the Equitrans Midstream Merger (defined in Note 12), the Company acquired a controlling 60% interest in Eureka Midstream Holdings, LLC (Eureka Midstream Holdings) and an equity method investment in Mountain Valley Pipeline, LLC (the MVP Joint Venture).

Eureka Midstream Holdings is a joint venture that owns a gathering header pipeline system that is operated by a subsidiary of EQT. Because the Company is the primary beneficiary of Eureka Midstream Holdings, the Company consolidates Eureka Midstream Holdings and records noncontrolling interest in its Condensed Consolidated Financial Statements. See Note 7 for discussion of the revolving credit facility of Eureka Midstream, LLC (Eureka), a wholly-owned subsidiary of Eureka Midstream Holdings.

The MVP Joint Venture is a joint venture formed among a subsidiary of EQT and, as applicable, affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc., AltaGas Ltd. and RGC Resources, Inc. for purposes of constructing and operating the Mountain Valley Pipeline (the MVP) and the MVP Southgate project (MVP Southgate). See Note 8 for further discussion of the MVP Joint Venture, the MVP and MVP Southgate. Because the Company has the ability to exercise significant influence over the MVP Joint Venture but does not have the power to direct the activities that most significantly affect the MVP Joint Venture's economic performance, the Company applies the equity method of accounting to the MVP Joint Venture.


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)



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 Condensed Consolidated Cash Flows.
Nine Months Ended September 30,
20242023
(Thousands)
Cash paid during the period for:
Interest, net of amount capitalized$196,632 $145,787 
Income taxes, net4,850 13,441 
Non-cash activity during the period for:
Equity issued as consideration for acquisition (Notes 12 and 11)
$5,548,608 $2,152,631 
Issuance of EQT common stock for Convertible Notes settlement (Note 7)
285,608 98 
NEPA Non-Operated Asset Divestiture (Note 11)
155,241 — 
Increase in right-of-use assets and lease liabilities, net11,501 25,849 
Increase in asset retirement costs and obligations7,947 5,216 
Capitalization of non-cash equity share-based compensation5,273 4,587 
Investments in nonconsolidated entities17,598 — 
Dissolution of consolidated variable interest entity— 25,227 

Common Stock. 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.

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 fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Company does not expect adoption of ASU 2023-07 to have a material impact on its currently-presented financial statements and related disclosures.

In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures to improve its 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 fiscal years beginning after December 15, 2024. 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.

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 changed the manner in which he allocates resources and measures financial performance 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. Accordingly, the manner in which the Company reports its operations has been changed retrospectively, with certain prior period amounts recast between Production and Gathering.


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)



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 reportable segments and are presented as "Other" along with intersegment eliminations. Water assets acquired in the Equitrans Midstream Merger primarily support the Company's production operations and, as such, have been included in the Company's Production segment.

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

Profit and loss metric with reconciliation to net (loss) income attributable to EQT Corporation for the three months ended September 30, 2024
ProductionGatheringTransmissionOther and intersegment eliminationsEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$1,099,752 $— $— $— $1,099,752 
Gain (loss) on derivatives72,489 (5,673)— — 66,816 
Pipeline, net marketing services and other5,826 276,829 87,384 (252,805)117,234 
Total operating revenues1,178,067 271,156 87,384 (252,805)1,283,802 
Operating expenses:
Transportation and processing693,670 — — (252,825)440,845 
Production93,842 — — — 93,842 
Operating and maintenance— 30,712 9,806 — 40,518 
Exploration282 — — — 282 
Selling, general and administrative (a)62,952 11,366 5,492 8,660 88,470 
Depreciation, depletion and amortization530,745 37,773 17,109 3,672 589,299 
Loss on sale/exchange of long-lived assets9,708 — 409 — 10,117 
Impairment and expiration of leases12,095 — — — 12,095 
Other operating expenses (b)10,206 — — 279,968 290,174 
Total operating expenses1,413,500 79,851 32,816 39,475 1,565,642 
Operating (loss) income$(235,433)$191,305 $54,568 $(292,280)$(281,840)
Reconciliation of profit and loss metric to net (loss) income attributable to EQT Corporation
Loss (income) from investments$1,671 $(597)$(35,616)$300 $(34,242)
Other income(3,488)(128)(75)(269)(3,960)
Loss on debt extinguishment— — — 365 365 
Interest expense, net— — — 158,299 158,299 
(Loss) income before income taxes(233,616)192,030 90,259 (450,975)(402,302)
Income tax benefit— — — (104,870)(104,870)
Net (loss) income(233,616)192,030 90,259 (346,105)(297,432)
Less: Net income (loss) attributable to noncontrolling interests— 3,687 — (296)3,391 
Net (loss) income attributable to EQT Corporation$(233,616)$188,343 $90,259 $(345,809)$(300,823)
(a)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(b)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger. See Note 12.

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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)



Profit and loss metric with reconciliation to net income attributable to EQT Corporation for the three months ended September 30, 2023
ProductionGatheringOther and intersegment eliminationsEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$1,001,883 $— $— $1,001,883 
Gain on derivatives177,906 — — 177,906 
Pipeline, net marketing services and other3,456 42,057 (39,200)6,313 
Total operating revenues1,183,245 42,057 (39,200)1,186,102 
Operating expenses:
Transportation and processing593,988 — (39,200)554,788 
Production62,858 — — 62,858 
Operating and maintenance— 4,235 — 4,235 
Exploration447 — — 447 
Selling, general and administrative (a)56,942 — — 56,942 
Depreciation, depletion and amortization440,360 4,054 2,472 446,886 
Loss on sale/exchange of long-lived assets1,511 — — 1,511 
Impairment and expiration of leases6,419 — — 6,419 
Other operating expenses (b)(621)— 36,830 36,209 
Total operating expenses1,161,904 8,289 102 1,170,295 
Operating income (loss)$21,341 $33,768 $(39,302)$15,807 
Reconciliation of profit and loss metric to net income attributable to EQT Corporation
Loss (income) from investments$424 $(255)$377 $546 
Other income— — (132)(132)
Loss on debt extinguishment— — 1,089 1,089 
Interest expense, net— — 60,427 60,427 
Income (loss) before income taxes20,917 34,023 (101,063)(46,123)
Income tax benefit— — (126,853)(126,853)
Net income20,917 34,023 25,790 80,730 
Less: Net income (loss) attributable to noncontrolling interests149 — (674)(525)
Net income attributable to EQT Corporation$20,768 $34,023 $26,464 $81,255 
(a)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(b)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition (defined in Note 11).


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)



Profit and loss metric with reconciliation to net (loss) income attributable to EQT Corporation for the nine months ended September 30, 2024
ProductionGatheringTransmissionOther and intersegment eliminationsEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$3,293,174 $— $— $— $3,293,174 
Gain (loss) on derivatives240,333 (5,673)— — 234,660 
Pipeline, net marketing services and other2,757 415,491 87,384 (384,884)120,748 
Total operating revenues3,536,264 409,818 87,384 (384,884)3,648,582 
Operating expenses:
Transportation and processing1,914,010 — — (384,917)1,529,093 
Production273,042 — — — 273,042 
Operating and maintenance— 56,018 9,806 — 65,824 
Exploration2,576 — — — 2,576 
Selling, general and administrative (a)180,767 11,366 5,492 31,105 228,730 
Depreciation, depletion and amortization1,470,966 45,282 17,109 8,674 1,542,031 
(Gain) loss on sale/exchange of long-lived assets(310,252)(22)409 — (309,865)
Impairment and expiration of leases58,963 — — — 58,963 
Other operating expenses (b)23,650 — — 330,687 354,337 
Total operating expenses3,613,722 112,644 32,816 (14,451)3,744,731 
Operating (loss) income$(77,458)$297,174 $54,568 $(370,433)$(96,149)
Reconciliation of profit and loss metric to net (loss) income attributable to EQT Corporation
(Income) loss from investments$(371)$(2,109)$(35,616)$1,422 $(36,674)
Other income(17,638)(5,153)(75)(730)(23,596)
Loss on debt extinguishment— — — 5,651 5,651 
Interest expense, net— — — 268,390 268,390 
(Loss) income before income taxes(59,449)304,436 90,259 (645,166)(309,920)
Income tax benefit— — — (124,790)(124,790)
Net (loss) income(59,449)304,436 90,259 (520,376)(185,130)
Less: Net income (loss) attributable to noncontrolling interests— 3,687 — (999)2,688 
Net (loss) income attributable to EQT Corporation$(59,449)$300,749 $90,259 $(519,377)$(187,818)
(a)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(b)Corporate other operating expenses consisted primarily of transaction costs related to the Equitrans Midstream Merger. See Note 12.

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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)



Profit and loss metric with reconciliation to net income (loss) attributable to EQT Corporation for the nine months ended September 30, 2023
ProductionGatheringOther and intersegment eliminationsEQT Corporation
(Thousands)
Operating revenues:
Sales of natural gas, natural gas liquids and oil$3,680,566 $— $— $3,680,566 
Gain on derivatives1,167,144 — — 1,167,144 
Pipeline, net marketing services and other9,675 95,753 (87,214)18,214 
Total operating revenues4,857,385 95,753 (87,214)4,865,924 
Operating expenses:
Transportation and processing1,680,009 — (87,075)1,592,934 
Production163,963 — — 163,963 
Operating and maintenance— 6,108 — 6,108 
Exploration2,602 — — 2,602 
Selling, general and administrative (a)168,999 — — 168,999 
Depreciation, depletion and amortization1,214,882 8,077 7,296 1,230,255 
Loss on sale/exchange of long-lived assets17,814 — — 17,814 
Impairment and expiration of leases22,290 — — 22,290 
Other operating expenses (b)7,645 — 61,620 69,265 
Total operating expenses3,278,204 14,185 (18,159)3,274,230 
Operating income (loss)$1,579,181 $81,568 $(69,055)$1,591,694 
Reconciliation of profit and loss metric to net income (loss) attributable to EQT Corporation
(Income) loss from investments$(2,675)$(4,004)$1,369 $(5,310)
Other income(395)— (474)(869)
Gain on debt extinguishment— — (55)(55)
Interest expense, net— — 146,856 146,856 
Income (loss) before income taxes1,582,251 85,572 (216,751)1,451,072 
Income tax expense— — 217,975 217,975 
Net income (loss)1,582,251 85,572 (434,726)1,233,097 
Less: Net income (loss) attributable to noncontrolling interests1,588 — (1,668)(80)
Net income (loss) attributable to EQT Corporation$1,580,663 $85,572 $(433,058)$1,233,177 
(a)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
(b)Corporate other operating expenses consisted primarily of transaction costs related to the Tug Hill and XcL Midstream Acquisition.



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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)



Assets by segment as of September 30, 2024
ProductionGatheringTransmissionOther and intersegment eliminationsEQT Corporation
(Thousands)
Investment in the MVP Joint Venture$— $— $3,358,346 $— $3,358,346 
Goodwill— — 1,289,759 888,477 2,178,236 
Other segment assets (a)22,890,299 8,187,601 2,962,486 368,621 34,409,007 
Total assets$22,890,299 $8,187,601 $7,610,591 $1,257,098 $39,945,589 
(a)Other segment assets in other and intersegment eliminations includes cash and cash equivalents.

Assets by segment as of September 30, 2023
ProductionGatheringOther and intersegment eliminationsEQT Corporation
(Thousands)
Total assets (a)$23,138,353 $1,167,766 $248,869 $24,554,988 
(a)Total assets in other and intersegment eliminations includes cash and cash equivalents.

The Company did not have an investment in the MVP Joint Venture or goodwill as of September 30, 2023.

Capital expenditures by segment
Three Months Ended September 30,Nine Months Ended
September 30,
2024202320242023
(Thousands)
Capital expenditures:
Production (a)$454,772 $435,646 $1,539,904 $1,366,669 
Gathering (b)79,597 6,941 111,644 11,521 
Transmission10,118 — 10,118 — 
Other13,402 1,998 21,345 8,546 
Total capital expenditures$557,889 $444,585 $1,683,011 $1,386,736 
(a)Production capital expenditures included capital expenditures attributable to the noncontrolling interest in The Mineral Company LLC (a joint venture formed between a subsidiary of EQT and a third-party investor for the purpose of purchasing certain mineral rights in the Appalachian Basin) of approximately $8.5 million for the nine months ended September 30, 2023. The Mineral Company LLC was dissolved in the third quarter of 2023.
(b)Gathering capital expenditures included capital expenditures attributable to the noncontrolling interest in Eureka Midstream Holdings of approximately $1.6 million for both the three and nine months ended September 30, 2024. See Notes 1 and 12.

Intersegment contracts

On February 26, 2020, EQT and certain of its affiliates (such parties, collectively, the EQT Producer) entered into a gas gathering and compression agreement (the Consolidated GGA) with 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. Pursuant to the terms of the Consolidated GGA, among other things, the EQM affiliate agreed to provide gas gathering services to the EQT Producer, and the EQT Producer 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.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)



The Consolidated GGA provides for cash bonus payments (the Henry Hub Cash Bonus) payable by the EQT Producer 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. Such payments are conditioned upon the quarterly average of the NYMEX Henry Hub natural gas settlement price exceeding certain price thresholds. Upon commencement of long-term firm capacity obligations, the MVP In-Service Date occurred on July 1, 2024. See Note 8.

The EQT Producer's derivative liability and any gain or loss realized related to the Henry Hub Cash Bonus are included in the Company's Production segment; the EQM affiliate's derivative asset and any gain or loss realized related to the Henry Hub Cash Bonus are included in the Company's Gathering segment. All balances and gains or losses related to the Henry Hub Cash Bonus have been eliminated in consolidation. As of September 30, 2024 and December 31, 2023, the derivative related to the Henry Hub Cash Bonus had a fair value of approximately $15 million and $48 million, respectively. The fair value of the derivative asset and liability related to the Henry Hub Cash Bonus is based on significant inputs that are interpolated from observable market data and, as such, is 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, natural gas liquids (NGLs) and oil sales contracts, the Company generally considers the delivery of each unit (million British thermal units (MMBtu) or barrel (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 fixed consideration is allocated 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 Condensed 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 recognizes revenue under gathering and transmission and storage contracts when it satisfies certain performance obligations.

The Company provides firm and interruptible gathering and transmission and storage services. 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. Volumetric-based fees, which are charges based on the volume of gas gathered, transported or stored, can also be charged under firm 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.

Gathering and transmission and storage services contracts can be short-term or long-term in duration. Firm and interruptible 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. Firm and interruptible 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.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)



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. 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.

For all of the Company's gathering and transmission and storage services contracts, 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.


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)



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 Condensed Consolidated Operations. Derivative contracts are also outside the scope of ASU 2014-09.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2024202320242023
(Thousands)
Revenues from contracts with customers:
Production:
Sales of natural gas, NGLs and oil
Natural gas sales$938,911 $859,512 $2,791,190 $3,337,600 
NGLs sales139,697 108,205 435,581 274,932 
Oil sales21,144 34,166 66,403 68,034 
Sales of natural gas, NGLs and oil1,099,752 1,001,883 3,293,174 3,680,566 
Gathering:
Pipeline revenues
Firm reservation fee revenues (a)136,752 — 136,752 — 
Volumetric-based fee revenues140,077 42,057 278,739 95,753 
Total276,829 42,057 415,491 95,753 
Transmission:
Pipeline revenues
Firm reservation fee revenues73,034 — 73,034 — 
Volumetric-based fee revenues14,226 — 14,226 — 
Total87,260 — 87,260 — 
Other and intersegment eliminations(252,805)(39,200)(384,884)(87,214)
Total revenues from contracts with customers$1,211,036 $1,004,740 $3,411,041 $3,689,105 
Other sources of revenue:
Gain on derivatives$66,816 $177,906 $234,660 $1,167,144 
Net marketing services and other revenues5,950 3,456 2,881 9,675 
Total other sources of revenue$72,766 $181,362 $237,541 $1,176,819 
Total operating revenues$1,283,802 $1,186,102 $3,648,582 $4,865,924 
(a)Firm reservation fee revenues for the three and nine months ended September 30, 2024 included unbilled revenues supported by MVCs of approximately $1.8 million.

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 $443.3 million and $584.8 million in accounts receivable in the Condensed Consolidated Balance Sheets as of September 30, 2024 and December 31, 2023, respectively.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)



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 September 30, 2024. The table excludes contracts that qualified for the exception to the relative standalone selling price method as of September 30, 2024. The MVP Joint Venture is accounted for as an equity method investment and, as such, its remaining performance obligations have been excluded from the table.
2024 (a)2025202620272028ThereafterTotal
(Thousands)
Gathering firm reservation fees:
Third-party contracts$25,850 $101,137 $92,186 $85,651 $85,651 $457,444 $847,919 
Affiliate contracts22,445 87,075 80,698 80,362 76,670 1,188,383 1,535,633 
Total Gathering firm reservation fees48,295 188,212 172,884 166,013 162,321 1,645,827 2,383,552 
Gathering revenues supported by MVCs:
Third-party contracts21,036 82,257 89,078 80,765 77,014 250,652 600,802 
Affiliate contracts90,630 372,446 397,966 410,621 411,740 2,453,073 4,136,476 
Total Gathering revenues supported by MVCs111,666 454,703 487,044 491,386 488,754 2,703,725 4,737,278 
Transmission firm reservation fees:
Third-party contracts48,754 175,010 174,191 171,750 169,393 980,973 1,720,071 
Affiliate contracts57,415 227,116 225,588 225,588 225,260 1,752,347 2,713,314 
Total Transmission firm reservation fees106,169 402,126 399,779 397,338 394,653 2,733,320 4,433,385 
Total$266,130 $1,045,041 $1,059,707 $1,054,737 $1,045,728 $7,082,872 $11,554,215 
(a)October 1 through December 31.

As of September 30, 2024, the Company had no remaining performance obligations on its natural gas sales contracts with fixed consideration.

Based on total projected contractual revenues, the Company's firm gathering affiliate contracts and firm transmission and storage affiliate contracts had weighted average remaining terms of approximately 13 years and 11 years, respectively, as of September 30, 2024. Based on total projected contractual revenues, the Company's firm gathering third-party contracts and firm transmission and storage third-party contracts had weighted average remaining terms of approximately 12 years and 11 years, respectively, as of September 30, 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.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
The Company does not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of the Company's derivative instruments are recognized in operating revenues in gain on derivatives in the Statements of Condensed 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 Condensed 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 2,574 Bcf of natural gas and 1,464 thousand barrels (Mbbl) of NGLs as of September 30, 2024 and 2,045 Bcf of natural gas and 1,049 Mbbl of NGLs as of December 31, 2023. The open positions at both September 30, 2024 and December 31, 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 September 30, 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 Condensed Consolidated Balance Sheets. As of September 30, 2024, none of the Company's OTC derivative instruments with credit rating risk-related contingent features were in a net liability position. As of December 31, 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 $6.4 million, for which no deposits were required or recorded in the Condensed Consolidated Balance Sheet.

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 Condensed Consolidated Balance Sheets. As of both September 30, 2024 and December 31, 2023, there were no such deposits recorded in the Condensed Consolidated Balance Sheets.


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)
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 Condensed 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 Condensed 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 September 30, 2024 and December 31, 2023, there were $17.5 million and $13.0 million, respectively, of such deposits recorded as current assets in the Condensed 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 Condensed Consolidated Balance SheetsDerivative instruments subject to
master netting agreements		Margin requirements with counterpartiesNet derivative instruments
 (Thousands)
September 30, 2024
Asset derivative instruments, at fair value$251,657 $(152,115)$— $99,542 
Liability derivative instruments, at fair value197,712 (152,115)(17,488)28,109 
December 31, 2023
Asset derivative instruments, at fair value$978,634 $(112,203)$— $866,431 
Liability derivative instruments, at fair value186,363 (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 Condensed 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.


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)
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 Condensed Consolidated Balance SheetsQuoted prices in active
markets for identical assets
(Level 1)		Significant other observable inputs
(Level 2)		Significant unobservable inputs
(Level 3)
 (Thousands)
September 30, 2024
Asset derivative instruments, at fair value$251,657 $41,772 $209,885 $— 
Liability derivative instruments, at fair value197,712 17,402 180,310 — 
December 31, 2023
Asset derivative instruments, at fair value$978,634 $66,302 $912,332 $— 
Liability derivative instruments, at fair value186,363 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 the Term Loan Facility (defined in Note 7) 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 has an investment in a fund (the Investment Fund) that invests in companies developing technology and operating solutions for exploration and production companies. The Company values the Investment Fund using, as a practical expedient, the net asset value provided in the financial statements received from fund managers.

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 September 30, 2024 and December 31, 2023, the Company's senior notes had a fair value of approximately $11.2 billion and $4.9 billion, respectively, and a carrying value of approximately $11.0 billion and $4.5 billion, respectively, inclusive of any current portion. See Note 7 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 12. 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 2 for a discussion of the fair value measurement of the Henry Hub Cash Bonus (which became an intercompany derivative asset and liability upon the closing of the Equitrans Midstream Merger). See Note 11 for a discussion of the fair value measurement of the NEPA Non-Operated Asset Divestiture (defined therein). See Note 12 for a discussion of the fair value measurement of the Equitrans Midstream Merger. See Note 1 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2023 for a discussion of the fair value measurement and any subsequent impairments of the Company's oil and gas properties and other long-lived assets, including impairment and expiration of leases.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
6.    Income Taxes

For the nine months ended September 30, 2024 and 2023, the Company calculated the provision for income taxes by applying an estimate of the annual effective tax rate for the full fiscal year to "ordinary" income or loss (pre-tax income or loss excluding unusual or infrequently occurring items) for the period. There were no material changes to the Company's methodology for determining unrecognized tax benefits during the nine months ended September 30, 2024.

For the nine months ended September 30, 2024 and 2023, the Company recorded income tax (benefit) expense at an effective tax rate of 40.3% and 15.0%, respectively. The Company's effective tax rate for the nine months ended September 30, 2024 was higher compared to the U.S. federal statutory rate primarily as a result of recognition of tax benefits related to higher losses on the Company's state tax-paying entities and the utilization of some its capital loss carryforwards with the capital gain generated from the NEPA Non-Operated Asset Divestiture, which resulted in the release of the associated valuation allowance. The Company's effective tax rate for the nine months ended September 30, 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 benefits related to a rate reduction from a Pennsylvania tax law change enacted in July 2022 and the Tug Hill and XcL Midstream Acquisition.

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Notes to the Condensed Consolidated Financial Statements (Unaudited)
7.    Debt

The table below summarizes the Company's outstanding debt.

September 30, 2024December 31, 2023
 Principal ValueCarrying Value (a)Principal ValueCarrying Value (a)
 (Thousands)
EQT's revolving credit facility maturing July 23, 2029$1,967,000 $1,967,000 $— $— 
Eureka's revolving credit facility maturing November 13, 2025330,000 330,000 — — 
Term Loan Facility due June 30, 2026 (b)500,000 497,970 1,250,000 1,244,265 
Debentures and senior notes:
EQT's 6.125% notes due February 1, 2025 (b)
— — 601,521 600,389 
EQM's 6.000% notes due July 1, 2025
400,000 400,150 — — 
EQT's 1.75% convertible notes due May 1, 2026 (c)
— — 290,177 286,185 
EQT's 3.125% notes due May 15, 2026
392,915 390,889 392,915 389,978 
EQT's 7.75% debentures due July 15, 2026
115,000 114,088 115,000 113,716 
EQM's 4.125% notes due December 1, 2026
500,000 487,340 — — 
EQM's 7.500% notes due June 1, 2027
500,000 512,554 — — 
EQM's 6.500% notes due July 1, 2027
900,000 917,091 — — 
EQT's 3.90% notes due October 1, 2027
1,169,503 1,166,252 1,169,503 1,165,439 
EQT's 5.700% notes due April 1, 2028
500,000 492,074 500,000 490,376 
EQM's 5.500% notes due July 15, 2028
850,000 846,328 — — 
EQT's 5.00% notes due January 15, 2029
318,494 315,619 318,494 315,121 
EQM's 4.50% notes due January 15, 2029
800,000 764,360 — — 
EQM's 6.375% notes due April 1, 2029
600,000 609,177 — — 
EQT's 7.000% notes due February 1, 2030 (b)
674,800 671,486 674,800 671,020 
EQM's 7.500% notes due June 1, 2030
500,000 537,317 — — 
EQM's 4.75% notes due January 15, 2031
1,100,000 1,042,951 — — 
EQT's 3.625% notes due May 15, 2031
435,165 430,649 435,165 430,141 
EQT's 5.750% notes due February 1, 2034
750,000 742,598 — — 
EQM's 6.500% notes due July 15, 2048
550,000 557,655 — — 
EQT's note payable to EQM (d)— — 88,483 88,483 
Total debt13,852,877 13,793,548 5,836,058 5,795,113 
Less: Current portion of debt (e)400,000 400,150 296,424 292,432 
Long-term debt$13,452,877 $13,393,398 $5,539,634 $5,502,681 
(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 the 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 the carrying value.
(b)Interest rates for the Term Loan Facility and EQT's 7.000% senior notes fluctuate based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Prior to EQT's redemption of all of its outstanding 6.125% senior notes, 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 outstanding debt do not fluctuate.
(c)As of December 31, 2023, the fair value of EQT's 1.75% convertible notes was $768.6 million and was a Level 2 fair value measurement. See Note 5.
(d)As a result of the Equitrans Midstream Merger, EQT's note payable to EQM has been eliminated in consolidation.
(e)As of September 30, 2024, the current portion of debt included EQM's 6.000% senior notes. 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.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
Debt Repayments. The Company repaid, redeemed or repurchased the following debt during the nine months ended September 30, 2024.
Debt TranchePrincipalPremiumsAccrued but Unpaid InterestTotal Cost
(Thousands)
EQM's 4.00% notes due August 1, 2024 (a)
$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, 2026750,000 — 332 750,332 
EQT's 1.75% convertible notes due May 1, 2026
583 — — 583 
Total$1,652,104 $1,178 $19,944 $1,673,226 
(a)EQM's 4.00% senior notes, which were consolidated by the Company as a result of the Equitrans Midstream Merger, were redeemed at maturity.

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 (the Fourth A&R 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 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 Fourth A&R Credit Agreement, among other things, (i) extends the maturity date of the commitments and loans under the 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 Fourth A&R Credit Agreement) or Term SOFR Rate Loans (as defined in the Fourth A&R Credit Agreement). Base Rate Loans are denominated in dollars and bear interest at a Base Rate (as defined in the Fourth A&R 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 Fourth A&R 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.

As of September 30, 2024, the Company had approximately $1 million of letters of credit outstanding under EQT's revolving credit facility and no letters of credit outstanding under Eureka's revolving credit facility. As of December 31, 2023, the Company had approximately $15 million of letters of credit outstanding under EQT's revolving credit facility.

During the three months ended September 30, 2024 and 2023, under EQT's revolving credit facility, the maximum amount of outstanding borrowings was $2,301 million and $158 million, respectively, and the average daily balance was approximately $1,608 million and $28 million, respectively. During the nine months ended September 30, 2024 and 2023, under EQT's revolving credit facility, the maximum amount of outstanding borrowings was $2,301 million and $158 million, respectively, and the average daily balance was approximately $551 million and $9 million, respectively. For each of the three and nine month periods ended September 30, 2024 and 2023, interest under EQT's revolving credit facility was incurred at a weighted average annual interest rate of 6.9%.

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 12. Eureka, a wholly-owned subsidiary of Eureka Midstream Holdings, has a $400 million senior secured revolving credit facility with 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.

For the period beginning on July 22, 2024 and ending on September 30, 2024, under Eureka's revolving credit facility, both the maximum amount of outstanding borrowings and average daily balance was $330 million, and interest was incurred at a weighted average annual interest rate of 8.1%.

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.

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Notes to the Condensed Consolidated Financial Statements (Unaudited)

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 on December 23, 2022, April 25, 2023, January 16, 2024 and July 22, 2024, 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.

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 Fourth A&R Credit Agreement. Pursuant to the Term Loan Agreement, EQT may voluntarily prepay, in whole or in part, borrowings under the Term Loan Facility without premium or penalty but subject to reimbursement of funding losses with respect to prepayment of loans that bear interest based on the Term SOFR Rate (as defined in the Term Loan Agreement). Borrowings under the Term Loan Facility that are repaid may not be re-borrowed.

At EQT's election, the term loans outstanding under the Term Loan Facility bear interest at 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 both the three and nine months ended September 30, 2024, interest under the Term Loan Facility was incurred at a weighted average annual interest rate of 6.9%. For the period beginning on August 21, 2023 and ending on September 30, 2023, interest under the Term Loan Facility was incurred at a weighted average annual interest rate of 7.0%.

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.

As of September 30, 2024, aggregate maturities for EQM's senior notes are zero for the three months ended December 31, 2024, $400 million in 2025, $500 million in 2026, $1,400 million in 2027, $850 million in 2028, $1,400 million in 2029 and $2,150 million thereafter.

EQT's 5.750% Senior Notes. On January 19, 2024, EQT issued $750 million aggregate principal amount of 5.750% senior notes due February 1, 2034. The Company used net proceeds of $742.0 million, composed of the principal amount of $750 million net of capitalized debt issuance costs and underwriters' discount of $8.0 million, and cash on hand to prepay $750 million principal amount of the term loans outstanding under the Term Loan Facility. The covenants of the 5.750% senior notes are consistent with EQT's existing senior unsecured notes.

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%.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
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.

8.    Investment in the MVP Joint Venture

The MVP Joint Venture. Upon the closing of the Equitrans Midstream Merger, the Company acquired an equity method investment in the MVP Joint Venture.

The MVP. The Company owned a 49.2% interest in the MVP as of September 30, 2024 and is the operator of the MVP. The MVP is a 303-mile long, 42-inch diameter natural gas interstate pipeline with a targeted 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. Estimated total project cost of the MVP is approximately $8.1 billion, excluding allowance for funds used during construction.

As of September 30, 2024, the Company had a negative basis difference between the carrying value of its equity method investment and its proportionate share of the MVP's net assets, which are composed of fixed assets. The basis difference is accreted over the life of the fixed assets and presented in income from investments in the Company's Statements of Condensed Consolidated Operations.

In September 2024, the MVP Joint Venture issued a capital call notice for the funding of the MVP project to the Company for $15.2 million, which was paid in October 2024. The capital contributions payable, which is presented in other current liabilities, and corresponding increase to the investment asset are included in the Condensed Consolidated Balance Sheet as of September 30, 2024.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
MVP Southgate. As of September 30, 2024, the Company owned a 47.2% interest in MVP Southgate. MVP Southgate is a contemplated interstate pipeline that was approved by the FERC and 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 an amended project and, among other things, describe certain conditions precedent to the parties' respective obligations regarding MVP Southgate. As amended, the natural gas interstate pipeline would extend approximately 31 miles from the terminus of 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. Completion of the MVP Southgate pipeline is targeted for June 2028. The Company expects to operate the MVP Southgate pipeline.

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 the MVP Southgate project, 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.

9.    (Loss) Income Per Share

The table below provides the computation for basic and diluted (loss) income per share.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2024202320242023
(Thousands, except per share amounts)
Net (loss) income attributable to EQT Corporation – Basic (loss) income available to shareholders$(300,823)$81,255 $(187,818)$1,233,177 
Add back: Interest expense on Convertible Notes, net of tax (a)— 2,042 — 6,117 
Diluted (loss) income available to shareholders$(300,823)$83,297 $(187,818)$1,239,294 
Weighted average common stock outstanding – Basic559,603 383,359 480,354 368,936 
Options, restricted stock, performance awards and stock appreciation rights (a)— 4,398 — 4,606 
Convertible Notes (a)— 28,433 — 28,317 
Weighted average common stock outstanding – Diluted559,603 416,190 480,354 401,859 
(Loss) income per share of common stock attributable to EQT Corporation:
Basic$(0.54)$0.21 $(0.39)$3.34 
Diluted$(0.54)$0.20 $(0.39)$3.08 
(a)In periods when the Company reports a net loss, all options, restricted stock, performance awards and stock appreciation awards, as applicable, are excluded from the calculation of diluted weighted average shares outstanding because of their anti-dilutive effect on loss per share. As a result, for the three and nine months ended September 30, 2024, all such securities of 7.6 million and 6.0 million, respectively, were excluded from potentially dilutive securities because of their anti-dilutive effect on loss per share.

In addition, prior to EQT's redemption of the Convertible Notes, the Company used the if-converted method to calculate the impact of the Convertible Notes on diluted (loss) income per share. For the nine months ended September 30, 2024, such if-converted securities of approximately 0.5 million as well as the related add back of interest expense on the Convertible Notes, net of tax, were excluded from potentially dilutive securities because of their anti-dilutive effect on loss per share.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
10.    Share-based Compensation

In 2024, the Management Development and Compensation Committee of the Company's Board of Directors (the Compensation Committee) adopted the 2024 Incentive Performance Share Unit Program (2024 Incentive PSU Program) under the 2020 Long-Term Incentive Plan. During the nine months ended September 30, 2024, a total of 371,500 share units were granted under the 2024 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, 2024 through December 31, 2026.

During the nine months ended September 30, 2024, the Compensation Committee granted 995,620 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.

In conjunction with the Equitrans Midstream Merger, the Company assumed all outstanding and unvested share-based compensation awards of Equitrans Midstream Corporation (Equitrans Midstream) and converted those assumed awards into 5,175,814 restricted stock unit equity awards that maintained the assumed awards' prior vesting schedules, assuming continued employment through each vesting date.

11.    Acquisitions and Divestitures

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.

NEPA Gathering System Acquisition. The Company operates and has historically owned a 50% interest in 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.

NEPA Non-Operated Asset Divestiture. On May 31, 2024, the Company completed the divestiture (the 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 $522 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 $7 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 $842 million, subject to customary post-closing purchase price adjustments, and included $413 million of property, plant and equipment.

As a result of the NEPA Non-Operated Asset Divestiture, for the nine months ended September 30, 2024, the Company recognized a gain of approximately $312 million in loss (gain) on sale/exchange of long-lived assets in the Statements of Condensed Consolidated Operations, inclusive of an $8 million loss recognized for the three months ended September 30, 2024. The gain was calculated as the carrying value of divested assets less the fair value of consideration received, net of liabilities assumed and divestiture costs incurred of approximately $8 million. Cash proceeds from the NEPA Non-Operated Asset Divestiture were used to partly fund EQT's redemption of its 6.125% senior notes.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
The fair values of the natural gas properties received as consideration for the 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 and operating costs and a weighted average cost of capital.

The fair value of the undeveloped properties received as consideration for the NEPA Non-Operated Asset Divestiture were measured using the guideline transaction method based on inputs that are not observable in the market and, as such, is a Level 3 fair value measurement. Significant inputs include future development plans from a market participant perspective.

The fair value of the interest in the NEPA Gathering System received as consideration for the 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 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 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.

Remaining NEPA Non-Operated Assets Divestiture. On October 29, 2024, the Company entered into an agreement with the Equinor Parties, pursuant to which the Company agreed to sell to the Equinor Parties the Company's remaining, undivided 60% interest in the Company's non-operated natural gas assets in Northeast Pennsylvania. In exchange, the Company will receive from the Equinor Parties $1.25 billion of cash (the Remaining NEPA Non-Operated Assets Divestiture). The Company intends to use the proceeds from the Remaining NEPA Non-Operated Assets Divestiture for repayment of the Company's debt. The Remaining NEPA Non-Operated Assets Divestiture is subject to customary closing adjustments, required regulatory approvals and clearances.

12.    Equitrans Midstream Merger

On July 22, 2024, the Company completed the 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 following the Equitrans Midstream Merger closing date.

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Notes to the Condensed Consolidated Financial Statements (Unaudited)

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 7.

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 three and nine months ended September 30, 2024, the Company recognized $274.6 million and $298.7 million, respectively, of transaction costs related to the Equitrans Midstream Merger within other operating expenses in the Statements of Condensed Consolidated Operations.



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Notes to the Condensed Consolidated Financial Statements (Unaudited)
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 stock685,337 
Settlement of pre-existing relationships(237,662)
Total consideration$5,996,312 
Fair value of assets acquired:
Cash and cash equivalents$58,767 
Accounts receivable, net85,308 
Income tax receivable2,192 
Prepaid expenses and other22,048 
Property, plant and equipment9,387,823 
Investment in the MVP Joint Venture3,222,311 
Net intangible assets250,000 
Other assets240,248 
Noncontrolling interest in consolidated subsidiaries(144,894)
Amount attributable to assets acquired$13,123,803 
Fair value of liabilities assumed:
Current portion of debt$699,837 
Accounts payable65,761 
Accrued interest47,996 
Other current liabilities76,563 
Revolving credit facility borrowings1,035,000 
Senior notes6,273,941 
Deferred income taxes961,894 
Other liabilities and credits144,735 
Amount attributable to liabilities assumed$9,305,727 
Goodwill$2,178,236 


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)
The fair value of Equitrans Midstream's property, plant and equipment, which primarily includes gathering systems, 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 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 Condensed 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 $1.3 billion to synergies expected from the vertical integration of the business, including from the elimination of contracted transportation and processing 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. In addition, the Company attributed $0.9 billion of total goodwill to additional deferred tax liabilities that arose from the differences between the preliminary purchase price allocation based on fair value and tax basis that carried over from Equitrans Midstream to the Company. The Company allocated all of the goodwill from the Equitrans Midstream Merger to the Company's Transmission segment. 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.


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)
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 September 30, 2024.
July 22, 2024 through September 30, 2024
(Thousands)
Loss on derivatives$(5,673)
Pipeline, net marketing services and other110,403 
Total operating revenues$104,730 
Net loss$(159,313)
Less: Net income attributable to noncontrolling interests3,687 
Net loss attributable to EQT Corporation$(163,000)

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.
Nine Months Ended
September 30,
 20242023
(Thousands, except per share amounts)
Pro forma operating revenues:
Pro forma sales of natural gas, NGLs and oil$3,293,174 $3,680,566 
Pro forma gain on derivatives201,228 1,221,557 
Pro forma pipeline, net marketing services and other454,136 456,082 
Pro forma total operating revenues$3,948,538 $5,358,205 
Pro forma net income$19,543 $1,677,891 
Less: Pro forma net income attributable to noncontrolling interests17,696 21,891 
Pro forma net income attributable to EQT Corporation$1,847 $1,656,000 
Pro forma income per share of common stock attributable to EQT Corporation:
Pro forma net income attributable to EQT Corporation – Basic$0.00 $4.49 
Pro forma net income attributable to EQT Corporation – Diluted$0.00 $4.14 


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EQT CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements (Unaudited)
13.    Commitments and Contingencies

Purchase Obligations

The following table summarizes the Company's commitments to pay demand charges under long-term contracts and binding precedent agreements with various pipelines and charges for processing capacity. The table presents the year or years in which such commitments are to be paid as of September 30, 2024 and December 31, 2023.

As of September 30, 2024As of December 31, 2023
 (Billions)
2024 (a)$0.2 $1.8 
20250.8 1.8 
20260.7 1.7 
20270.7 1.7 
20280.6 1.4 
Thereafter4.2 13.6 
Total$7.2 $22.0 
(a)As of September 30, 2024, the noted amount represented commitments payable for the three months ended December 31, 2024; as of December 31, 2023, the noted amount represented commitments payable for the year ended December 31, 2024.

The following table summarizes the Company's commitments to pay for services related to its operations, including electric hydraulic fracturing services, and purchase equipment, materials and sand. The table presents the year or years in which such commitments are to be paid as of September 30, 2024 and December 31, 2023.

As of September 30, 2024As of December 31, 2023
 (Millions)
2024 (a)$60.7 $228.8 
2025194.6 164.5 
2026148.4 138.0 
202788.2 111.0 
202837.9 72.9 
Thereafter— 107.9 
Total$529.8 $823.1 
(a)As of September 30, 2024, the noted amount represented commitments payable for the three months ended December 31, 2024; as of December 31, 2023, the noted amount represented commitments payable for the year ended December 31, 2024.



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Notes to the Condensed Consolidated Financial Statements (Unaudited)
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 loss for such matters when the Company believes that it is probable a liability has been incurred and the amount of the loss can be reasonably estimated. In such cases, if some amount within a range of loss appears to be a better estimate than any other amount within the range, that amount is accrued; however, when no amount within the range is a better estimate than any other amount, the minimum amount in the range is accrued. Any such accruals are adjusted thereafter as appropriate to reflect changed circumstances. In the event the Company determines that (i) it is probable a liability has been incurred but the amount of the loss cannot be reasonably estimated, or (ii) it less likely than probable but is reasonably possible that a liability has been incurred, then the Company is required to disclose the matter in its Annual Report on Form 10-K with any update thereto in this Quarterly Report on Form 10-Q, as applicable, 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 loss or where there is no accrued loss, 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 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 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's 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.


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Notes to the Condensed Consolidated Financial Statements (Unaudited)
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.

See Note 11 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2023 for additional discussion of the Company's commitments and contingencies, including certain other pending legal and regulatory proceedings and other contingent matters. As of September 30, 2024, except as disclosed herein, there have been no material changes to such matters disclosed therein.


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Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Condensed Consolidated Financial Statements and the notes thereto included in this report. Unless the context otherwise indicates, all references in this report to "EQT" are to EQT Corporation and all references in this report to the "Company," "we," "us," or "our" are to EQT Corporation and its consolidated subsidiaries, collectively. For certain industry specific terms used in this Quarterly Report on Form 10-Q, please see "Glossary of Commonly Used Terms, Abbreviations and Measurements" in our Annual Report on Form 10-K for the year ended December 31, 2023.

CAUTIONARY STATEMENTS
 
This Quarterly Report on Form 10-Q contains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended (the Securities Act). Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe" and other words of similar meaning, or the negative thereof. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report on Form 10-Q include the matters discussed in the section "Trends and Uncertainties" and expectations of our plans, strategies, objectives and growth and anticipated financial and operational performance, including guidance regarding our strategy to develop our reserves; drilling plans and programs, including availability of capital to complete these plans and programs; total resource potential and drilling inventory duration; projected production and sales volume, including liquified natural gas (LNG) volumes and sales; natural gas prices; changes in basis and the impact of commodity prices on our business; potential future impairments of our assets; projected well costs and capital expenditures; infrastructure programs; the cost, capacity and timing of obtaining regulatory approvals; our ability to successfully implement and execute our operational, organizational, technological and environmental, social and governance (ESG) initiatives, and achieve the anticipated results of such initiatives; projected gathering and compression rates; potential divestitures, acquisitions or other strategic transactions, the timing thereof and our ability to achieve the intended operational, financial and strategic benefits from any such transactions or from any recently completed strategic transactions, including the Equitrans Midstream Merger (defined and discussed in Note 12 to the Condensed Consolidated Financial Statements); the amount and timing of any repayments, redemptions or repurchases of our common stock, outstanding debt securities or other debt instruments; our ability to retire our debt and the timing of such retirements, if any; the projected amount and timing of dividends; projected cash flows and free cash flow, and the timing thereof; liquidity and financing requirements, including funding sources and availability; our ability to maintain or improve our credit ratings, leverage levels and financial profile; our hedging strategy and projected margin posting obligations; the effects of litigation, government regulation and tax position; and the expected impact of changes to tax laws.

The forward-looking statements included in this Quarterly Report on Form 10-Q involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. We have based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently known by us. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond our control. These risks and uncertainties include, but are not limited to, volatility of commodity prices; the costs and results of drilling and operations; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying production forecasts; the quality of technical data; our ability to appropriately allocate capital and other resources among our strategic opportunities; access to and cost of capital; our hedging and other financial contracts; inherent hazards and risks normally incidental to drilling for, producing, transporting and storing natural gas, natural gas liquids (NGLs) and oil; operational risks and hazards incidental to the gathering, transmission and storage of natural gas as well as unforeseen interruptions; cyber security risks and acts of sabotage; availability and cost of drilling rigs, completion services, equipment, supplies, personnel, oilfield services and sand and water required to execute our exploration and development plans, including as a result of inflationary pressures; risks associated with operating primarily in the Appalachian Basin; the ability to obtain environmental and other permits and the timing thereof; construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties related to the development and construction by us or our joint ventures of pipeline and storage facilities and transmission assets and the optimization of such assets; our ability to renew or replace expiring gathering, transmission or storage contracts at favorable rates on a long-term basis or at all; risks relating to our joint venture arrangements; government regulation or action, including regulations pertaining to methane and other greenhouse gas emissions; negative public perception of the fossil fuels industry; increased consumer demand for alternatives to natural gas; environmental and weather risks, including the possible impacts of climate change; risks related to our ability to integrate the operations of Equitrans Midstream Corporation

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Management's Discussion and Analysis of Financial Condition and Results of Operations
(Equitrans Midstream) in a successful manner and in the expected time period and the possibility that any of the anticipated benefits and projected synergies of the Equitrans Midstream Merger will not be realized or will not be realized within the expected time period; and disruptions to our business due to recently completed acquisitions and other significant transactions, including the Equitrans Midstream Merger. These and other risks and uncertainties are described under the "Risk Factors" section in this Quarterly Report on Form 10-Q and under the "Risk Factors" section and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2023, and may be updated by other documents we subsequently file from time to time with the Securities and Exchange Commission (the SEC).

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we do not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

Recent Events

On July 22, 2024, we completed the Equitrans Midstream Merger. As a result of the Equitrans Midstream Merger, we acquired over 2,000 miles of pipeline infrastructure that have extensive overlap and connectivity in our core area of operations, and we became the first large-scale, integrated natural gas producer in the United States. Refer to Note 12 to the Condensed Consolidated Financial Statements.

During the second quarter of 2024, we divested a portion of our non-operated assets in Northeast Pennsylvania (the NEPA Non-Operated Asset Divestiture), as discussed in Note 11 to the Condensed Consolidated Financial Statements. On October 29, 2024, we entered into an agreement to divest the remaining interest in our non-operated assets in Northeast Pennsylvania in exchange for $1.25 billion of cash (the Remaining NEPA Non-Operated Assets Divestiture). We intend to use the proceeds from the Remaining NEPA Non-Operated Assets Divestiture for repayment of our debt. The Remaining NEPA Non-Operated Assets Divestiture is subject to customary closing adjustments, required regulatory approvals and clearances.

Trends and Uncertainties

The Mountain Valley Pipeline

Following receipt of authorization from the Federal Energy Regulatory Commission (the FERC), the Mountain Valley Pipeline (the MVP) entered into service on June 14, 2024. Upon commencement of long-term firm capacity obligations, the MVP In-Service Date (defined in Note 8 to the Condensed Consolidated Financial Statements) occurred on July 1, 2024. Our Production segment is committed to an initial 1.29 billion cubic feet (Bcf) per day of firm capacity on the MVP through June 30, 2044. Accordingly, as a result of the occurrence of the MVP In-Service Date, we expect our Production segment's future (i) transmission expense to increase as a result of the additional contracted capacity and (ii) gathering expense to decrease pursuant to the terms of the Consolidated GGA (defined in Note 2 to the Condensed Consolidated Financial Statements).

The MVP Joint Venture (defined in Note 1 to the Condensed Consolidated Financial Statements) has continued to make restoration efforts with respect to the MVP. Estimated total project cost of the MVP is approximately $8.1 billion, excluding allowance for funds used during construction. Of this amount, $100.4 million was contributed by us following our closing of the Equitrans Midstream Merger, including the $15.2 million payable as of September 30, 2024, which was paid in October 2024.

Curtailments and Commodity Prices

On March 4, 2024, we announced our decision to strategically curtail approximately 1.0 Bcf per day of gross production (the Strategic Curtailment) beginning on February 24, 2024 in response to the low natural gas price environment resulting from warm winter weather and elevated storage inventories. The Strategic Curtailment resulted in total decreased sales volume of 82 billion cubic feet of natural gas equivalents (Bcfe) during the period beginning on February 24, 2024 and ending on June 19, 2024 and 25 Bcfe during the period beginning July 4, 2024 and ending on September 30, 2024. In response to market fundamentals, we expect to continue to strategically curtail our production. Our sales volume guidance assumes 10 to 15 Bcfe of curtailments during the fourth quarter of 2024.


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Management's Discussion and Analysis of Financial Condition and Results of Operations
Continued low natural gas prices may result in further adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest. Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Certain operators of wells in which we have a non-operating working interest also curtailed production in 2024. For the three months ended September 30, 2024, we estimate that our total expected sales volume was negatively impacted by approximately 35 Bcfe of curtailments, including our Strategic Curtailment of 25 Bcfe and curtailments by certain operators of wells in which we have a non-operating working interest. For the nine months ended September 30, 2024, we estimate that our total expected sales volume was negatively impacted by approximately 125 to 130 Bcfe of curtailments, including our Strategic Curtailment of 107 Bcfe and curtailments by certain operators of wells in which we have a non-operating working interest. Adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

The annual inflation rate in the United States remains elevated compared to the rate of inflation over the prior five years. Inflationary pressures have multiple impacts on our business, including increasing our operating expenses and our cost of capital. While the prices for certain of the raw materials and services we use in our operations have generally decreased from the peak prices experienced during 2022, we will not fully realize the benefit of such reduced prices until we enter into new contracts for such materials and services, and inflationary pressures may cause prices to fluctuate. Additionally, certain of our commitments for demand charges under our existing long-term contracts and processing capacity are subject to consumer price index adjustments. Although we believe our scale and supply chain contracting strategy of using multi-year sand and frac crew contracts allows us to maximize capital and operating efficiencies, future increases in the inflation rate will negatively impact our long-term contracts with consumer price index adjustments.

We expect commodity prices to be volatile through 2024 due to macroeconomic uncertainty and geopolitical tensions, including developments pertaining to Russia's invasion of Ukraine and conflicts in the Middle East. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.

Consolidated Results of Operations

Net loss attributable to EQT Corporation for the three months ended September 30, 2024 was $300.8 million, $0.54 per diluted share, compared to net income attributable to EQT Corporation of $81.3 million, $0.20 per diluted share, for the same period in 2023. The change was attributable primarily to increased other operating expenses, increased depreciation, depletion and amortization, a lower gain on derivatives and increased net interest expense, partly offset by decreased transportation and processing expense and increased cash operating revenues, including pipeline revenues, which increased as a result of our operation of assets acquired in the Equitrans Midstream Merger.

Net loss attributable to EQT Corporation for the nine months ended September 30, 2024 was $187.8 million, $0.39 per diluted share, compared to net income attributable to EQT Corporation of $1,233.2 million, $3.08 per diluted share, for the same period in 2023. The change was attributable primarily to lower gain on derivatives, decreased sales of natural gas, NGLs and oil, increased depreciation, depletion and amortization expense, increased other operating expenses, increased net interest expense and increased production expense, partly offset by recognition of an income tax benefit in 2024 compared to an income tax expense in 2023, the gain on the NEPA Non-Operated Asset Divestiture and increased pipeline revenues, which increased as a result of our operation of assets acquired in the Equitrans Midstream Merger.

Results of operations for the three and nine months ended September 30, 2024 include the results of our operation of assets acquired in the Equitrans Midstream Merger, which closed on July 22, 2024. See Note 12 to the Condensed Consolidated Financial Statements.

Results of operations for the nine months ended September 30, 2024 include the results of our operation of assets received as consideration for the NEPA Non-Operated Asset Divestiture, which closed on May 31, 2024. Such assets received included the remaining 16.25% equity interest in the NEPA Gathering System (defined in Note 11 to the Condensed Consolidated Financial Statements) (which was the sole remaining minority interest following our acquisition of a 33.75% equity interest in the NEPA Gathering System Acquisition (defined in Note 11 to the Condensed Consolidated Financial Statements) on April 11, 2024), resulting in our 100% ownership of the NEPA Gathering System. See Note 11 to the Condensed Consolidated Financial Statements.

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Management's Discussion and Analysis of Financial Condition and Results of Operations

In addition, results of operations for the nine months ended September 30, 2024 include the results of our operation of assets acquired in the Tug Hill and XcL Midstream Acquisition (defined in Note 11 to the Condensed Consolidated Financial Statements), which closed on August 22, 2023.

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

See "Business Segment Results of Operations" for a discussion of segment operating revenues and expenses and "Unallocated and Other Income Statement Items" for a discussion of other, unallocated income statement items.

See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures, including by business segment.

Average Realized Price Reconciliation

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

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Management's Discussion and Analysis of Financial Condition and Results of Operations
Three Months Ended
September 30,		Nine Months Ended
September 30,
2024202320242023
(Thousands, unless otherwise noted)
NATURAL GAS
Sales volume (MMcf)547,225 491,472 1,520,574 1,374,527 
NYMEX price ($/MMBtu)$2.15 $2.55 $2.12 $2.68 
Btu uplift0.12 0.13 0.12 0.14 
Natural gas price ($/Mcf)$2.27 $2.68 $2.24 $2.82 
Basis ($/Mcf) (a)$(0.56)$(0.93)$(0.40)$(0.39)
Cash settled basis swaps ($/Mcf)(0.09)0.12 (0.10)(0.08)
Average differential, including cash settled basis swaps ($/Mcf)$(0.65)$(0.81)$(0.50)$(0.47)
Average adjusted price ($/Mcf)$1.62 $1.87 $1.74 $2.35 
Cash settled derivatives ($/Mcf)0.61 0.27 0.75 0.37 
Average natural gas price, including cash settled derivatives ($/Mcf)$2.23 $2.14 $2.49 $2.72 
Natural gas sales, including cash settled derivatives$1,222,498 $1,053,146 $3,786,058 $3,741,247 
LIQUIDS
NGLs, excluding ethane:
Sales volume (MMcfe) (b)22,253 16,629 63,393 41,805 
Sales volume (Mbbl)3,710 2,772 10,566 6,968 
NGLs price ($/Bbl)$35.20 $35.42 $38.18 $35.34 
Cash settled derivatives ($/Bbl)(0.11)(1.10)(0.20)(1.54)
Average NGLs price, including cash settled derivatives ($/Bbl)$35.09 $34.32 $37.98 $33.80 
NGLs sales, including cash settled derivatives$130,140 $95,120 $401,232 $235,509 
Ethane:
Sales volume (MMcfe) (b)9,864 11,528 32,416 29,198 
Sales volume (Mbbl)1,644 1,921 5,403 4,866 
Ethane price ($/Bbl)$5.56 $5.23 $5.97 $5.90 
Ethane sales$9,135 $10,039 $32,237 $28,699 
Oil:
Sales volume (MMcfe) (b)2,072 3,071 6,593 6,814 
Sales volume (Mbbl)345 512 1,099 1,136 
Oil price ($/Bbl)$61.25 $66.75 $60.43 $59.91 
Oil sales$21,144 $34,166 $66,403 $68,034 
Total liquids sales volume (MMcfe) (b)34,189 31,228 102,402 77,817 
Total liquids sales volume (Mbbl)5,699 5,205 17,068 12,970 
Total liquids sales$160,419 $139,325 $499,872 $332,242 
TOTAL
Total natural gas and liquids sales, including cash settled derivatives (c)$1,382,917 $1,192,471 $4,285,930 $4,073,489 
Total sales volume (MMcfe)581,414 522,700 1,622,976 1,452,344 
Average realized price ($/Mcfe)$2.38 $2.28 $2.64 $2.80 
(a)Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with our firm transportation agreements, and the New York Mercantile Exchange (NYMEX) natural gas price.
(b)NGLs, ethane and oil were converted to thousand cubic feet of natural gas equivalents (Mcfe) at a rate of six Mcfe per barrel.
(c)Also referred to in this report as Production adjusted operating revenues, a non-GAAP supplemental financial measure.

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Management's Discussion and Analysis of Financial Condition and Results of Operations
Non-GAAP Financial Measures Reconciliation

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

Production adjusted operating revenues (also referred to in this report as total natural gas and liquids sales, including cash settled derivatives) is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Production adjusted operating revenues is defined as total operating revenues, less the revenue impact of changes in the fair value of derivative instruments prior to settlement and pipeline, net marketing services and other revenues. We believe that Production adjusted operating revenues provides useful information to investors regarding our financial condition and results of operations because it helps facilitate comparisons of operating performance and earnings trends across periods. Production adjusted operating revenues reflects only the impact of settled derivative contracts; thus, the measure excludes the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement. The measure also excludes pipeline, net marketing services and other revenues, which consists of costs of, and recoveries on, pipeline capacity releases and other revenues, because it is unrelated to the revenue from our natural gas and liquids production.
Three Months Ended
September 30,		Nine Months Ended
September 30,
2024202320242023
(Thousands, unless otherwise noted)
Total operating revenues
$1,283,802 $1,186,102 $3,648,582 $4,865,924 
(Deduct) add:
Gain on derivatives(66,816)(177,906)(234,660)(1,167,144)
Net cash settlements received on derivatives288,136 255,804 1,037,321 625,051 
Premiums paid for derivatives that settled during the period(4,971)(65,216)(44,565)(232,128)
Pipeline, net marketing services and other(117,234)(6,313)(120,748)(18,214)
Production adjusted operating revenues, a non-GAAP financial measure
$1,382,917 $1,192,471 $4,285,930 $4,073,489 
Total sales volume (MMcfe)581,414 522,700 1,622,976 1,452,344 
Average realized price ($/Mcfe)$2.38 $2.28 $2.64 $2.80 

Business Segment Results of Operations

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

Prior to the completion of the Equitrans Midstream Merger, we reported our results of operations as a single consolidated segment. As a result of the completion of the Equitrans Midstream Merger, we adjusted our internal reporting structure and our chief operating decision maker changed the manner in which he allocates resources and measures financial performance to incorporate the gathering and transmission assets we acquired in the Equitrans Midstream Merger. Hence, our operations expanded to comprise three discrete segments reflective of our three lines of business of Production, Gathering and Transmission. Accordingly, the manner in which we report our operations has been changed retrospectively, with certain prior period amounts recast between Production and Gathering.

The following sections summarize operating income and certain operational measures by our three reportable segments. We believe this information is useful to investors for evaluating our financial condition, results of operations and trends and uncertainties of our segments. See Note 2 to the Condensed Consolidated Financial Statements for financial information by business segment.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Certain amounts, including cash and cash equivalents, debt, income taxes and other amounts related to our headquarters function as well as amounts related to our energy transition initiatives, are managed on a consolidated basis and, as such, have not been allocated to our reportable segments. Changes to these amounts are discussed under "Other Income Statement Items."

PRODUCTION

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023
Three Months Ended September 30,
20242023Change% Change
(Thousands, unless otherwise noted)
Total sales volume (MMcfe)581,414 522,700 58,714 11.2 
Average daily sales volume (MMcfe/d)6,320 5,682 638 11.2 
Operating revenues:
Sales of natural gas, NGLs and oil$1,099,752 $1,001,883 $97,869 9.8 
Gain on derivatives72,489 177,906 (105,417)(59.3)
Pipeline, net marketing services and other5,826 3,456 2,370 68.6 
Total operating revenues1,178,067 1,183,245 (5,178)(0.4)
Operating expenses:   
Gathering115,599 328,549 (212,950)(64.8)
Transmission250,757 166,572 84,185 50.5 
Processing74,489 59,667 14,822 24.8 
Transportation and processing to affiliate252,825 39,200 213,625 545.0 
Lease operating expense (LOE)54,199 40,083 14,116 35.2 
Production taxes39,643 22,775 16,868 74.1 
Exploration282 447 (165)(36.9)
Selling, general and administrative (a)62,952 56,942 6,010 10.6 
Production depletion529,785 439,613 90,172 20.5 
Other depreciation and depletion960 747 213 28.5 
Loss on sale/exchange of long-lived assets9,708 1,511 8,197 542.5 
Impairment and expiration of leases12,095 6,419 5,676 88.4 
Other operating expenses10,206 (621)10,827 (1,743.5)
Total operating expenses1,413,500 1,161,904 251,596 21.7 
Operating (loss) income$(235,433)$21,341 $(256,774)(1,203.2)
Per Unit ($/Mcfe):
Gathering$0.20 $0.63 $(0.43)(68.3)
Transmission0.43 0.32 0.11 34.4 
Processing0.13 0.11 0.02 18.2 
Transportation and processing to affiliate0.43 0.07 0.36 514.3 
LOE0.09 0.08 0.01 12.5 
Production taxes0.07 0.04 0.03 75.0 
Selling, general and administrative0.11 0.11 — — 
Production depletion0.91 0.84 0.07 8.3 
(a)Prior period selling, general and administrative expense was not recast as the necessary information is not available and the cost to develop such information would be excessive.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Sales volume. Sales volume increased for the three months ended September 30, 2024 compared to the same period in 2023 primarily as a result of sales volume increases of 31 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition and increases from wells turned-in-line, partly offset by sales volume decreases of 25 Bcfe due to the Strategic Curtailment and decreases of 12 Bcfe due to the NEPA Non-Operated Asset Divestiture.

Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil increased for the three months ended September 30, 2024 compared to the same period in 2023 due to increased sales volume and higher average realized price.

Average realized price increased for the three months ended September 30, 2024 compared to the same period in 2023 due to favorable cash settled NYMEX derivatives and favorable average differential, partly offset by lower NYMEX price. The following table presents the composition of net cash settlements received on derivatives.
Three Months Ended
September 30,
20242023
(Thousands)
Net cash settlements received on NYMEX natural gas hedge positions$339,283 $199,042 
Net cash settlements (paid) received on basis and liquids hedge positions(51,147)56,762 
Net cash settlements received on derivatives$288,136 $255,804 

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

For the three months ended September 30, 2024 and 2023, we paid premiums of $5.0 million and $65.2 million, respectively, for derivatives that settled during the period.

Gain on derivatives. For the three months ended September 30, 2024 and 2023, we recognized a gain on derivatives of $72.5 million and $177.9 million related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices.

Gathering. Gathering expense decreased on an absolute and per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the NEPA Non-Operated Asset Divestiture.

Transmission. Transmission expense increased on an absolute and per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to additional contracted capacity, including on the MVP, which commenced long-term firm capacity obligations on July 1, 2024.

Processing. Processing expense increased on an absolute and per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to increased volumes from the development of liquids-rich areas and increased processing expense from the liquids-rich assets acquired in the Tug Hill and XcL Midstream Acquisition.

Transportation and processing to affiliate. Affiliate transportation and processing expense increased on an absolute and per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the NEPA Non-Operated Asset Divestiture. In addition, affiliate transportation and processing expense increased on a per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due to our Gathering segment's ownership of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023.

LOE. LOE increased on an absolute and per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to increased LOE from the water assets acquired in the Equitrans Midstream Merger and the assets acquired in the Tug Hill and XcL Midstream Acquisition.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Production taxes. Production taxes increased on an absolute and per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to increased West Virginia property tax expense from the assets acquired in the Tug Hill and XcL Midstream Acquisition as well as increased severance tax expense from increased sales volume.

Selling, general and administrative. Selling, general and administrative expense increased on an absolute basis for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to higher personnel costs due to increased workforce headcount, including as a result of the Equitrans Midstream Merger.

Depreciation and depletion. Production depletion expense increased on an absolute and per Mcfe basis for the three months ended September 30, 2024 compared to the same period in 2023 due to increased sales volume and higher annual depletion rate.

Loss (gain) on sale/exchange of long-lived assets. During the three months ended September 30, 2024, we recognized a loss on the NEPA Non-Operated Asset Divestiture of approximately $8.0 million. See Note 11 to the Condensed Consolidated Financial Statements.

Impairment and expiration of leases. During the three months ended September 30, 2024 and 2023, we recognized impairment and expiration of leases related to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.

Other operating expenses. Other operating expenses increased for the three months ended September 30, 2024 compared to the same period in 2023 due primarily to increased legal and environmental reserves.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

Nine Months Ended September 30,
20242023Change% Change
(Thousands, unless otherwise noted)
Total sales volume (MMcfe)1,622,976 1,452,344 170,632 11.7 
Average daily sales volume (MMcfe/d)5,923 5,320 603 11.3 
Operating revenues:
Sales of natural gas, NGLs and oil$3,293,174 $3,680,566 $(387,392)(10.5)
Gain on derivatives240,333 1,167,144 (926,811)(79.4)
Pipeline, net marketing services and other2,757 9,675 (6,918)(71.5)
Total operating revenues3,536,264 4,857,385 (1,321,121)(27.2)
Operating expenses:   
Gathering721,891 954,304 (232,413)(24.4)
Transmission597,578 473,651 123,927 26.2 
Processing209,624 164,979 44,645 27.1 
Transportation and processing to affiliate384,917 87,075 297,842 342.1 
LOE144,956 102,226 42,730 41.8 
Production taxes128,086 61,737 66,349 107.5 
Exploration2,576 2,602 (26)(1.0)
Selling, general and administrative (a)180,767 168,999 11,768 7.0 
Production depletion1,468,644 1,212,498 256,146 21.1 
Other depreciation and depletion2,322 2,384 (62)(2.6)
(Gain) loss on sale/exchange of long-lived assets(310,252)17,814 (328,066)(1,841.6)
Impairment and expiration of leases58,963 22,290 36,673 164.5 
Other operating expenses23,650 7,645 16,005 209.4 
Total operating expenses3,613,722 3,278,204 335,518 10.2 
Operating (loss) income$(77,458)$1,579,181 $(1,656,639)(104.9)
Per Unit ($/Mcfe):
Gathering$0.44 $0.66 $(0.22)(33.3)
Transmission0.37 0.33 0.04 12.1 
Processing0.13 0.11 0.02 18.2 
Transportation and processing to affiliate0.24 0.06 0.18 300.0 
LOE0.09 0.07 0.02 28.6 
Production taxes0.08 0.04 0.04 100.0 
Selling, general and administrative0.11 0.12 (0.01)(8.3)
Production depletion0.90 0.83 0.07 8.4 
(a)Prior period selling, general and administrative expense was not recast as the necessary information is not available and the cost to develop such information would be excessive.

Sales volume. Sales volume increased for the nine months ended September 30, 2024 compared to the same period in 2023 primarily as a result of sales volume increases of 155 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition and increases from wells turned-in-line, partly offset by sales volume decreases of 107 Bcfe due to the Strategic Curtailment and decreases of 17 Bcfe due to the NEPA Non-Operated Asset Divestiture.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for the nine months ended September 30, 2024 compared to the same period in 2023 due to lower average realized price, partly offset by increased sales volume.

Average realized price decreased for the nine months ended September 30, 2024 compared to the same period in 2023 due to lower NYMEX price and lower East Coast basis spreads, partly offset by favorable cash settled NYMEX derivatives and higher NGLs price. The following table presents the composition of net cash settlements received on derivatives.
Nine Months Ended
September 30,
20242023
(Thousands)
Net cash settlements received on NYMEX natural gas hedge positions$1,195,411 $738,047 
Net cash settlements paid on basis and liquids hedge positions(158,090)(112,996)
Net cash settlements received on derivatives$1,037,321 $625,051 

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

For the nine months ended September 30, 2024 and 2023, we paid premiums of $44.6 million and $232.1 million, respectively, for derivatives that settled during the period.

Gain on derivatives. For the nine months ended September 30, 2024, we recognized a gain on derivatives of $240.3 million related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices. For the nine months ended September 30, 2023, we recognized a gain on derivatives of $1,167.1 million related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices, partly offset by a loss on our Production segment's derivative liability related to the Henry Hub Cash Bonus (defined in Note 2 to the Condensed Consolidated Financial Statements).

Gathering. Gathering expense decreased on an absolute and per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the NEPA Non-Operated Asset Divestiture.

Transmission. Transmission expense increased on an absolute and per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to additional contracted capacity, including on the MVP, which commenced long-term firm capacity obligations on July 1, 2024, as well as credits received in 2023 from the Texas Eastern Transmission pipeline.

Processing. Processing expense increased on an absolute and per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to increased processing expense from the liquids-rich assets acquired in the Tug Hill and XcL Midstream Acquisition.

Transportation and processing to affiliate. Affiliate transportation and processing expense increased on an absolute and per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the NEPA Non-Operated Asset Divestiture. In addition, affiliate transportation and processing expense also increased on a per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due to our Gathering segment's ownership of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023.

LOE. LOE increased on an absolute and per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to increased LOE from the assets acquired in the Tug Hill and XcL Midstream Acquisition.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Production taxes. Production taxes increased on an absolute and per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to increased West Virginia property tax expense from the assets acquired in the Tug Hill and XcL Midstream Acquisition and higher price as well as increased severance tax expense from increased sales volume.

Selling, general and administrative. Selling, general and administrative expense increased on an absolute basis for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to higher personnel costs due to increased workforce headcount, including as a result of the Equitrans Midstream Merger, and higher legal and professional services costs.

Depreciation and depletion. Production depletion expense increased on an absolute and per Mcfe basis for the nine months ended September 30, 2024 compared to the same period in 2023 due to increased sales volume and higher annual depletion rate.

Loss (gain) on sale/exchange of long-lived assets. During the nine months ended September 30, 2024, we recognized a gain on the NEPA Non-Operated Asset Divestiture of approximately $312 million. See Note 11 to the Condensed Consolidated Financial Statements. During the nine months ended September 30, 2023, we recognized a loss on exchange of long-lived assets of $17.8 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.

Impairment and expiration of leases. During the nine months ended September 30, 2024 and 2023, we recognized impairment and expiration of leases related to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.

Other operating expenses. Other operating expenses increased for the nine months ended September 30, 2024 compared to the same period in 2023 due primarily to increased rig release expense and increased legal and environmental reserves.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
GATHERING

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023

Three Months Ended September 30,
20242023Change% Change
(Thousands, unless otherwise noted)
Gathered volume (British thermal unit (BBtu)/d):
Firm capacity5,450 — 5,450 100 
Volumetric-based services4,293 666 3,627 545 
Total gathered volume9,743 666 9,077 1,363 
Operating revenues:
Loss on derivatives$(5,673)$— $(5,673)100 
Firm reservation fee revenues (a)136,752 — 136,752 100 
Volumetric-based fee revenues (b)140,077 42,057 98,020 233 
Total operating revenues271,156 42,057 229,099 545 
Operating expenses:
Operating and maintenance30,712 4,235 26,477 625 
Selling, general and administrative (c)11,366 — 11,366 100 
Depreciation37,773 4,054 33,719 832 
Total operating expenses79,851 8,289 71,562 863 
Operating income$191,305 $33,768 $157,537 467 
(a)Firm reservation fee revenues for the three months ended September 30, 2024 included unbilled revenues supported by minimum volume commitments (MVCs) of approximately $1.8 million.
(b)For agreements structured with MVCs, includes volumes up to the contractual MVC; volumes in excess of the contractual MVC are reported under volumetric-based services.
(c)Prior period selling, general and administrative expense was not recast as the necessary information is not available and the cost to develop such information would be excessive.

Gathering revenues and expenses increased for the three months ended September 30, 2024 compared to the same period in 2023 primarily from the gathering assets acquired in the Equitrans Midstream Merger during the third quarter of 2024 and in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023. Prior to the close of the Equitrans Midstream Merger, we did not own gathering assets that provided firm gathering services.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

Nine Months Ended September 30,
20242023Change% Change
(Thousands, unless otherwise noted)
Gathered volume (BBtu/d):
Firm capacity5,450 — 5,450 100 
Volumetric-based services4,059 654 3,405 521 
Total gathered volume9,509 654 8,855 1,354 
Operating revenues:
Loss on derivatives$(5,673)$— $(5,673)100 
Firm reservation fee revenues (a)136,752 — 136,752 100 
Volumetric-based fee revenues (b)278,739 95,753 182,986 191 
Total operating revenues409,818 95,753 314,065 328 
Operating expenses:
Operating and maintenance56,018 6,108 49,910 817 
Selling, general and administrative (c)11,366 — 11,366 100 
Depreciation45,282 8,077 37,205 461 
Gain on sale/exchange of long-lived assets(22)— (22)100 
Total operating expenses112,644 14,185 98,459 694 
Operating income$297,174 $81,568 $215,606 264 
(a)Firm reservation fee revenues for the nine months ended September 30, 2024 included unbilled revenues supported by MVCs of approximately $1.8 million.
(b)For agreements structured with MVCs, includes volumes up to the contractual MVC; volumes in excess of the contractual MVC are reported under volumetric-based services.
(c)Prior period selling, general and administrative expense was not recast as the necessary information is not available and the cost to develop such information would be excessive.

Gathering revenues and expenses increased for the nine months ended September 30, 2024 compared to the same period in 2023 primarily from the gathering assets acquired in the Equitrans Midstream Merger during the third quarter of 2024 and in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023. Prior to the close of the Equitrans Midstream Merger, we did not own gathering assets that provided firm gathering services.

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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
TRANSMISSION

Prior to the close of the Equitrans Midstream Merger on July 22, 2024, we did not have transmission or storage assets.

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023

Three Months Ended
September 30, 2024
(Thousands, unless otherwise noted)
Transmission pipeline throughput (BBtu/d):
Firm capacity (a)3,595 
Interruptible capacity12 
Total transmission pipeline throughput3,607 
Average contracted firm transmission reservation commitments (BBtu/d)4,454 
Operating revenues:
Firm reservation fee revenues$73,034 
Volumetric-based fee revenues:14,226 
Other revenues124 
Total operating revenues87,384 
Operating expenses:
Operating and maintenance9,806 
Selling, general and administrative5,492 
Depreciation13,900 
Amortization of intangible assets3,209 
Loss on sale/exchange of long-lived assets409 
Total operating expenses32,816 
Operating income$54,568 
(a)Includes all volumes associated with firm capacity contracts, including volumes in excess of firm capacity.

Other Income Statement Items

Other operating expenses. Corporate other operating expenses increased for both the three and nine months ended September 30, 2024 compared to the same periods in 2023 due primarily to transaction costs related to the Equitrans Midstream Merger of $274.6 million and $298.7 million for the three and nine months ended September 30, 2024, respectively, partly offset by lower transaction costs related to the Tug Hill and XcL Midstream Acquisition. In addition, during the nine months ended September 30, 2024, litigation reserves increased compared to the same period in 2023.

Total transaction costs related to the Equitrans Midstream Merger recognized during the three months ended September 30, 2024 included severance and other termination benefits and stock-based compensation costs of $161.0 million, of which $58.6 million was cash and $102.4 million was non-cash.

(Income) loss from investments. Income from investments increased for both the three and nine months ended September 30, 2024 compared to the same period in 2023 due primarily to equity earnings from our investment in the MVP Joint Venture, partly offset by a decrease in the fair value of our investment in the Investment Fund (defined in Note 5 to the Condensed Consolidated Financial Statements).


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Management's Discussion and Analysis of Financial Condition and Results of Operations
Other income. Other income increased during the three months ended September 30, 2024 due to dividends received from our investment in the Investment Fund. During the nine months ended September 30, 2024, we received proceeds from insurance claim recoveries of $19.1 million related to the assets acquired in the Tug Hill and XcL Midstream Acquisition.

Loss (gain) on debt extinguishment. During the nine months ended September 30, 2024, we recognized a loss on debt extinguishment of $5.7 million primarily as a result of our prepayment of a portion of the Term Loan Facility (defined in Note 7 to the Condensed Consolidated Financial Statements) as well as our redemption of EQT's 6.125% senior notes.

Interest expense, net. Interest expense, net increased for the three months ended September 30, 2024 compared to the same periods in 2023 due primarily to interest expense on EQM Midstream Partners, LP's (EQM) senior notes (which we consolidate as a result of the Equitrans Midstream Merger), increased interest expense on our borrowings under EQT's revolving credit facility, interest expense on EQT's 5.750% senior notes issued in January 2024 and lower interest income earned on cash on hand, partly offset by decreased interest expense from our repayment and repurchase of certain of our senior notes, decreased interest expense on the Term Loan Facility due to our partial prepayment in January 2024 as well as higher capitalized interest from the assets acquired in the Tug Hill and XcL Midstream Acquisition.

Interest expense, net increased for the nine months ended September 30, 2024 compared to the same periods in 2023 due primarily to interest expense on EQM's senior notes, lower interest income earned on cash on hand, interest expense on EQT's 5.750% senior notes issued in January 2024, increased interest expense on our borrowings under EQT's revolving credit facility and increased interest expense on our borrowings under the Term Loan Facility, partly offset by decreased interest expense from our repayment and repurchase of certain of our senior notes as well as higher capitalized interest from the assets acquired in the Tug Hill and XcL Midstream Acquisition.

See Note 7 to the Condensed Consolidated Financial Statements.

Income tax (benefit) expense. See Note 6 to the Condensed Consolidated Financial Statements.

Net income (loss) attributable to noncontrolling interests. During the three and nine months ended September 30, 2024, we recognized net income attributable to noncontrolling interests of Eureka Midstream Holdings, LLC (Eureka Midstream Holdings), a consolidated joint venture in which we acquired an equity interest as a result of the Equitrans Midstream Merger. See Note 1 to the Condensed Consolidated Financial Statements.

Capital Resources and Liquidity

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

Planned Capital Expenditures and Sales Volume. Following the completion of the Equitrans Midstream Merger, we revised our estimated total capital expenditures for the fourth quarter of 2024 to $630 million to $730 million. We expect to fund our capital expenditures with cash generated from operations and, if required, borrowings under EQT's revolving credit facility. Because we are the operator of a high percentage of our developed acreage, the amount and timing of certain of our capital expenditures is largely discretionary. We could choose to defer a portion of our planned 2024 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; and drilling, completion and acquisition costs. In addition, our gathering and transmission businesses are capital intensive, requiring significant investment to develop new facilities and maintain and upgrade existing operations.

We expect our sales volume, including expected curtailments, to be 555 Bcfe to 605 Bcfe for the fourth quarter of 2024.
 
Material Cash Requirements. We have contractual commitments under our debt agreements, including interest payments and principal repayments. As a result of the Equitrans Midstream Merger, EQM became an indirect wholly-owned subsidiary of EQT. See Note 7 to the Condensed Consolidated Financial Statements for further discussion of EQM's senior notes.

In addition, we expect to make total capital contributions to the MVP Joint Venture in the fourth quarter of 2024 of approximately $70 million to $80 million.

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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations

Operating Activities. Net cash provided by operating activities was $2,071 million for the nine months ended September 30, 2024 compared to $2,554 million for the same period in 2023. The decrease was due primarily to higher cash operating expenses (including increased transaction costs related to the Equitrans Midstream Merger), unfavorable timing of working capital payments, lower cash operating revenues and higher net interest expense, partly offset by higher net cash settlements received on derivatives and lower net premiums paid on derivatives.

Our cash flows from operating activities are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. For a discussion of potential commodity market risks, refer to "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position" in our Annual Report on Form 10-K for the year ended December 31, 2023.

Investing Activities. Net cash used in investing activities was $2,162 million for the nine months ended September 30, 2024 compared to $3,774 million for the same period in 2023. The decrease was attributable primarily to lower cash paid for the Equitrans Midstream Merger and the NEPA Gathering System Acquisition in 2024 compared to cash paid for the Tug Hill and XcL Midstream Acquisition in 2023 as well as the proceeds received from the NEPA Non-Operated Asset Divestiture, partly offset by increased capital expenditures.

The following tables summarize our capital expenditures.
Three Months Ended
September 30,		Nine Months Ended
September 30,
 2024202320242023
 (Millions)
Production:
Reserve development (a)$371 $355 $1,283 $1,147 
Land and lease (b)37 41 105 101 
Other production infrastructure16 17 57 49 
Capitalized interest, capitalized overhead and other31 23 95 70 
Total Production455 436 1,540 1,367 
Gathering (c)80 7 112 12 
Transmission10 — 10 — 
Other corporate items13 2 21 8 
Total capital expenditures558 445 1,683 1,387 
Add (deduct): Non-cash items (d)11 59 (21)99 
Total cash capital expenditures$569 $504 $1,662 $1,486 
(a)Capital expenditures for reserve development included capital expenditures for water infrastructure of $28.9 million and $7.7 million for the three months ended September 30, 2024 and 2023, respectively, and $58.7 million and $26.4 million for the nine months ended September 30, 2024 and 2023, respectively.
(b)Capital expenditures for land and lease included capital expenditures attributable to noncontrolling interest in The Mineral Company LLC of approximately $8.5 million for the nine months ended September 30, 2023. The Mineral Company LLC was dissolved in the third quarter of 2023.
(c)Gathering capital expenditures included capital expenditures attributable to noncontrolling interest in Eureka Midstream Holdings of approximately $1.6 million for both the three and nine months ended September 30, 2024.
(d)Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures, transfers to or from inventory as assets are completed or assigned to a project and capitalized share-based compensation costs. The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Financing Activities. Net cash provided by financing activities was $100 million for the nine months ended September 30, 2024 compared to net cash used in financing activities of $174 million for the same period in 2023. For the nine months ended September 30, 2024, the primary sources of financing cash flows were our net borrowings under EQT's revolving credit facility, proceeds from the issuance of EQT's 5.750% senior notes and proceeds from the net settlement of the Capped Call Transactions (defined in Note 7 to the Condensed Consolidated Financial Statements), and the primary uses of financing cash flows were our repayment and retirement of debt, repayment of EQM's revolving credit facility and payment of dividends. For the nine months ended September 30, 2023, the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings, and the primary uses of financing cash flows were our repayment and retirement of debt, repurchase and retirement of EQT common stock and payment of dividends.

See Note 7 to the Condensed Consolidated Financial Statements for further discussion of our debt and borrowings under EQT's revolving credit facility and the Term Loan Facility. See Notes 1 and 7 to the Condensed Consolidated Financial Statements for discussion of borrowings under the revolving credit facility of Eureka Midstream, LLC (Eureka), a wholly-owned subsidiary of Eureka Midstream Holdings.

On October 10, 2024, our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT common stock, payable on December 2, 2024, to shareholders of record at the close of business on November 6, 2024.

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

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

The table below reflects the credit ratings and rating outlooks assigned to EQT's debt instruments as of September 30, 2024.
Rating agency Senior notes Outlook
Moody's Investor Service (Moody's)Baa3Negative
Standard and Poor's Ratings Service (S&P)BBB– Negative
Fitch Ratings Service (Fitch)BBB–Stable

The table below reflects the credit ratings and rating outlooks assigned to EQM's debt instruments as of September 30, 2024.
Rating agency Senior notes Outlook
Moody's Investor Service (Moody's)Ba2Stable
Standard and Poor's Ratings Service (S&P)BBB– Negative
Fitch Ratings Service (Fitch)BB+Stable
 
Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under EQT's and Eureka's revolving credit facilities, the interest rate on the Term Loan Facility, the interest rate on EQT's senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our over the counter (OTC) derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties.


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. EQT's revolving credit facility and the Term Loan Facility contain financial covenants that require us to have a total debt to total capitalization ratio no greater than 65%. As of September 30, 2024, we were in compliance with all EQT, Eureka and EQM debt provisions and covenants under our debt agreements.

See Note 7 to the Condensed Consolidated Financial Statements for a discussion of borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility.

Commodity Risk Management

The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of October 25, 2024. The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.
Q4 2024 (a)Q1 2025Q2 2025Q3 2025Q4 2025
Hedged Volume (MMDth)377 332 336 281 281 
Hedged Volume (MMDth/d)4.1 3.7 3.7 3.1 3.1 
Swaps – Short
Volume (MMDth)304 250 290 281 95 
Avg. Price ($/Dth)$3.18 $3.49 $3.11 $3.26 $3.27 
Calls – Long
Volume (MMDth)13 — — — — 
Avg. Strike ($/Dth)$3.20 $— $— $— $— 
Calls – Short
Volume (MMDth)91 188 46 — 137 
Avg. Strike ($/Dth)$4.23 $4.19 $3.48 $— $5.49 
Puts – Long
Volume (MMDth)73 82 46 — 186 
Avg. Strike ($/Dth)$3.54 $3.19 $2.83 $— $3.30 
Option Premiums
Cash Settlement of Deferred Premiums (millions)$— $— $— $— $(45)
(a)October 1 through December 31.

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

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


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EQT CORPORATION AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition and Results of Operations
Commitments and Contingencies

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We evaluate our legal proceedings, including litigation and regulatory and governmental investigations and inquiries, on a regular basis and accrue a liability for such matters when we believe 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 we determine that (i) a loss is probable but the amount of the loss cannot be reasonably estimated, or (ii) a loss is less likely than probable but is reasonably possible, then we are required to disclose the matter in our Annual Report on Form 10-K with any update thereto in this Quarterly Report on Form 10-Q, as applicable, although we are not required to accrue such loss.

When able, we determine 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 our 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.

See Note 13 to the Condensed Consolidated Financial Statements herein and Note 11 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2023 for discussions of our commitments and contingencies, including certain pending legal and regulatory proceedings and other contingent matters.

Additionally, in the normal course of business, we are subject to various other pending and threatened legal proceedings in which claims for monetary damages or other relief are asserted. We do 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 our financial position, results of operations or liquidity.

Critical Accounting Estimates
 
Our critical accounting estimates, including a discussion regarding the estimation uncertainty and the impact that our critical accounting estimates have had, or are reasonably likely to have, on our financial condition or results of operations, are described in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section of our Annual Report on Form 10-K for the year ended December 31, 2023 and have been updated below. The application of our critical accounting estimates may require us to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. We use historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.

Goodwill. Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business.

Goodwill is evaluated for impairment at least annually or whenever events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We use a combination of an income and market approach to estimate the fair value of our reporting units.

We believe goodwill is a "critical accounting estimate" because the valuation of a reporting unit involves significant judgment and is sensitive to changes in assumptions, including changes in our stock price, weighted-average cost of capital, terminal growth rates and industry multiples. Changes to assumptions could materially affect the estimated fair value of our reporting units and the resulting conclusion on impairment could materially affect our results of operations and financial position. In addition, future assumptions and estimates may materially differ from current assumptions and estimates.


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Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk and Derivative Instruments. Our primary market risk exposure is the volatility of future prices for natural gas and NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Prolonged low, or significant, extended declines in, natural gas and NGLs prices could adversely affect, among other things, our development plans, which would decrease the pace of development and the level of our proved reserves and, similarly, could adversely affect timing of development of additional reserves and production that is accessible by our pipeline and storage assets and limit growth in, or may reduce the demand for, and usage of, our gathering or transmission and storage services. Price declines and sustained periods of low natural gas and NGLs prices could also have an adverse effect on the creditworthiness of our gathering and transmission and storage customers and related ability to pay firm reservation fees under long-term contracts. Increases in natural gas and NGLs prices may be accompanied by, or result in, increased well drilling costs, increased production taxes, increased LOE, increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels. In addition, to the extent we have hedged our production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas, and, depending on our then-current credit ratings and the terms of our hedging contracts, we may be required to post additional margin with our hedging counterparties.

The overall objective of our hedging program is to protect our cash flows from undue exposure to the risk of changing commodity prices. Our use of derivatives is further described in Note 4 to the Condensed Consolidated Financial Statements and "Commodity Risk Management" under "Capital Resources and Liquidity" in Item 2. Our OTC derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of those institutions is regularly monitored. We primarily enter into derivative instruments to hedge forecasted sales of production. We also enter into derivative instruments to hedge basis. Our use of derivative instruments is implemented under a set of policies approved by our management-level Hedge and Financial Risk Committee and is reviewed by our Board of Directors.

For derivative commodity instruments used to hedge our forecasted sales of production, which are at, for the most part, NYMEX natural gas prices, we set policy limits relative to the expected production and sales levels that are exposed to price risk. We have an insignificant amount of financial natural gas derivative commodity instruments for trading purposes.

The derivative commodity instruments we use are primarily swap, collar and option agreements. These agreements may require payments to, or receipt of payments from, counterparties based on the differential between two prices for the commodity. We use these agreements to hedge our NYMEX and basis exposure. We may also use other contractual agreements when executing our commodity hedging strategy.

We monitor price and production levels on a continuous basis and adjust quantities hedged as warranted.

A hypothetical decrease of 10% in the NYMEX natural gas price on September 30, 2024 and December 31, 2023 would increase the fair value of our natural gas derivative commodity instruments by approximately $440 million and $204 million, respectively. A hypothetical increase of 10% in the NYMEX natural gas price on September 30, 2024 and December 31, 2023 would decrease the fair value of our natural gas derivative commodity instruments by approximately $434 million and $482 million, respectively. For purposes of this analysis, we applied the 10% change in the NYMEX natural gas price on September 30, 2024 and December 31, 2023 to our natural gas derivative commodity instruments as of September 30, 2024 and December 31, 2023 to calculate the hypothetical change in fair value. The change in fair value was determined using a method similar to our normal process for determining derivative commodity instrument fair value described in Note 5 to the Condensed Consolidated Financial Statements.

The above analysis of our derivative commodity instruments does not include the offsetting impact that the same hypothetical price movement may have on our physical sales of natural gas. The portfolio of derivative commodity instruments held to hedge our forecasted produced natural gas approximates a portion of our expected physical sales of natural gas; therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held to hedge our forecasted production associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on our physical sales of natural gas, assuming that the derivative commodity instruments are not closed in advance of their expected term and the derivative commodity instruments continue to function effectively as hedges of the underlying risk.

If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.

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Interest Rate Risk. Changes in market interest rates affect the amount of interest we earn on cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility. In addition, changes in Eureka's Consolidated Leverage Ratio (defined in 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, governing Eureka's revolving credit facility (the Eureka Credit Agreement)) as a result on Eureka's liquidity needs, operating results or distributions to its member affect the interest rate Eureka pays on borrowings under its revolving credit facility. None of the interest we pay on our senior notes fluctuates based on changes to market interest rates. A 1% increase in interest rates for the borrowings under EQT's revolving credit facility, Eureka's revolving credit facility and the Term Loan Facility during the nine months ended September 30, 2024 would have increased interest expense by approximately $9.7 million.

Interest rates for EQT's revolving credit facility, the Term Loan Facility and EQT's 7.000% senior notes fluctuate based on changes to the credit ratings assigned to EQT's senior notes by Moody's, S&P and Fitch. Prior to EQT's redemption of all of EQT's outstanding 6.125% senior notes, 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 our other outstanding senior notes do not fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch. For a discussion of credit rating downgrade risk, see "Risk Factors – Our operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms" in our Annual Report on Form 10-K for the year ended December 31, 2023. Changes in interest rates affect the fair value of our fixed rate debt. See Note 7 to the Condensed Consolidated Financial Statements for further discussion of our debt and Note 5 to the Condensed Consolidated Financial Statements for a discussion of fair value measurements, including the fair value measurement of our debt.

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

Approximately 54%, or $210 million, of our OTC derivative contracts outstanding at September 30, 2024 had a positive fair value. Approximately 86%, or $912 million, of our OTC derivative contracts outstanding at December 31, 2023 had a positive fair value.

As of September 30, 2024, we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts. During the three months ended September 30, 2024, we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure. We monitor market conditions that may impact the fair value of our derivative contracts.

We are exposed to the risk of nonperformance by credit customers on physical sales of natural gas, NGLs and oil. Revenues and related accounts receivable from our operations are generated primarily from the sale of our produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States and Canada. We also contract with certain processors to market a portion of our NGLs on our behalf.

As of September 30, 2024, no one lender of the large group of financial institutions in the syndicate for either EQT's revolving credit facility or the Term Loan Facility held more than 10% of the financial commitments thereunder. In addition, as of September 30, 2024, no one lender of the large group of financial institutions in the syndicate for Eureka's revolving credit facility held more than 13% of the financial commitments thereunder. The large syndicate group and relatively low percentage of participation by each lender are expected to limit our exposure to disruption or consolidation in the banking industry.


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Item 4.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and our principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. During the third quarter of 2024, we completed the Equitrans Midstream Merger and began integrating the acquired assets into our internal control over financial reporting. We will continue to evaluate and monitor our internal control over financial reporting and will continue to evaluate the operating effectiveness of related key controls.

Except as noted above, there were no changes in our internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.    Legal Proceedings
 
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us. While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. We accrue legal and other direct costs related to loss contingencies when actually incurred. We have established reserves in amounts that we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any pending matter involving us will not materially affect our financial position, results of operations or liquidity.

Environmental Proceedings

Pratt Storage Field Matter, Morgan Township, Pennsylvania. On October 31, 2018, a gas explosion occurred in Morgan Township, Greene County, Pennsylvania (the Pratt Incident). Following the explosion, the Pennsylvania Department of Environmental Protection (PADEP), the Pennsylvania Public Utilities Commission and the Pipeline and Hazardous Materials Safety Administration of the Department of Transportation (PHMSA) began investigating the Pratt Incident. In October 2019, the PADEP notified Equitrans Midstream that it was required to submit an investigation report pursuant to the state's gas migration regulations due to the Pratt Incident's proximity to Equitrans, L.P.'s (a subsidiary of Equitrans Midstream) Pratt Storage Field assets. Equitrans Midstream, while disputing the applicability of the regulations, submitted a report to the PADEP in May 2020. In September 2020, the PADEP responded to Equitrans Midstream's investigation report with a request for additional information. Equitrans Midstream responded to the September 2020 request. Over the next several months, Equitrans Midstream provided responses to the PADEP's continuing information requests. The PADEP issued a final report and closed its investigation in August 2022, and we do not expect further inquiry from the PADEP on this matter.

On October 23, 2023, Equitrans, L.P. received permission from the FERC to plug and abandon the well in the Pratt Storage Field that was the subject of the PADEP's investigation of the Pratt Incident. On October 22, 2024, Equitrans, L.P. received from the FERC an extension until January 31, 2025 to complete plugging and abandonment of the well. Additionally, Equitrans Midstream is continuing to defend in a civil litigation related to the Pratt Incident.


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On October 30, 2023, Equitrans, L.P. received a criminal complaint from the State Attorney General's Office charging Equitrans, L.P. with violations of the Clean Streams Law (the Pratt Complaint). As a result of the Equitrans Midstream Merger, we indirectly assumed Equitrans Midstream's and Equitrans, L.P.'s defense against the Pratt Complaint and matters related to the Pratt Incident. We intend to fully assert Equitrans Midstream's and Equitrans, L.P.'s rights and defenses to the claims raised in the Pratt Complaint. The Pratt Complaint carries the possibility of a monetary sanction, that if imposed could result in a fine in excess of $300,000; however, we expect that the resolution of this matter will not have a material adverse impact on our financial condition, results of operations or liquidity.

Rager Mountain Storage Field Venting, Jackson Township, Pennsylvania. On November 6, 2022, Equitrans Midstream became aware of natural gas venting from one of the storage wells, well 2244, at Equitrans, L.P.'s Rager Mountain natural gas storage facility (the Rager Mountain Facility), located in Jackson Township, a remote section of Cambria County, Pennsylvania. Venting at the Rager Mountain Facility was halted on November 19, 2022. Since the time of the incident, the PADEP has concluded its investigation and PHMSA and other investigators are continuing to conduct civil and criminal investigations of the incident, and Equitrans Midstream has been cooperating in such investigations. On December 7, 2022, Equitrans Midstream and Equitrans, L.P. each separately received an order from the PADEP alleging, in connection with earth disturbance activities undertaken to halt the venting of natural gas from well 2244, (i) in the case of the order received by Equitrans Midstream, violations of Pennsylvania's Clean Streams Law and requiring certain remedial actions and (ii) in the case of the order received by Equitrans, L.P., violations of Pennsylvania's 2012 Oil and Gas Act, Clean Streams Law and Solid Waste Management Act and requiring certain remedial actions. On December 8, 2022, the PADEP submitted a compliance order to Equitrans, L.P. relating to certain alleged violations of law with respect to wells at the Rager Mountain Facility and the venting of natural gas, including from well 2244. The December 8, 2022 order also prohibited Equitrans, L.P. from injecting natural gas into the storage wells at the Rager Mountain Facility. Equitrans Midstream and Equitrans, L.P. disputed aspects of the applicable orders, and on January 5, 2023, Equitrans Midstream and Equitrans, L.P., as applicable, appealed each of the orders to the Commonwealth of Pennsylvania Environmental Hearing Board. Equitrans, L.P. and the PADEP entered into a Stipulation of Settlement on April 12, 2023 that, among other things, resulted in the PADEP rescinding its December 8, 2022 order and Equitrans, L.P. withdrawing its appeal of such order.

On October 5, 2023, Equitrans, L.P. received a notice of violation (NOV) from the PADEP's Bureau of Air Quality Management for the release of uncontrolled hydrocarbons to the atmosphere during the Rager Mountain Facility incident. On April 8, 2024, the PADEP's Bureau of Air Quality Management executed a Consent Assessment of Civil Penalty that settled the October 5, 2023 NOV and included an agreed upon civil penalty of $350,000, which was paid in full by Equitrans Midstream on April 15, 2024.

On April 4, 2024, (i) Equitrans, L.P. and the PADEP entered into a Stipulation of Settlement, that, among other things, resulted in the PADEP deeming the December 8, 2022 orders to Equitrans Midstream and Equitrans, L.P. administratively closed and (ii) the PADEP issued a Civil Penalty Assessment (CPA) in the amount of $764,000, of which $549,500 was reimbursement of PADEP's expenses. The CPA closed the outstanding NOVs issued by the PADEP's Office of Oil and Gas Management related to the Rager Mountain Facility incident. Equitrans Midstream paid the civil penalty pursuant to the CPA in full on April 8, 2024.

On December 29, 2022, the PHMSA issued Equitrans Midstream a Notice of Proposed Safety Order that included proposed remedial requirements related to the Rager Mountain Facility incident, including, but not limited to, completing a root cause analysis, and subsequently, on May 26, 2023, the PHMSA issued a consent order to Equitrans Midstream requiring the completion of a root cause analysis and a remedial work plan and providing that Equitrans Midstream may not resume injection operations at the Rager Mountain Facility until authorized by the PHMSA. In August 2023, Equitrans Midstream submitted a root cause analysis to the PHMSA and later submitted a remedial work plan and injection plan seeking authority to resume injections at the Rager Mountain Facility using all wells in the facility except three, which remained disconnected from the storage field. On October 2, 2023, the PHMSA approved Equitrans Midstream's injection plan and Equitrans Midstream restarted injections at the Rager Mountain Facility on October 5, 2023, subject to certain pressure restrictions and other requirements in the PHMSA consent agreement. On November 16, 2023, the PHMSA issued a letter to Equitrans Midstream approving Equitrans Midstream's request to remove all pressure restrictions at the Rager Mountain Facility. On May 30, 2024, the PHMSA approved resuming operations for one of the three remaining wells excluded from the injection plan.

As a result of the Equitrans Midstream Merger, we indirectly assumed Equitrans Midstream's and Equitrans, L.P.'s defense and responses to matters related to the Rager Mountain Facility incident. We plan to continue working with the PHMSA, pursuant to the consent order between PHSMA and Equitrans Midstream, regarding the remaining two disconnected wells at the Rager Mountain Facility. If additional penalties are pursued and ultimately imposed related to the Rager Mountain Facility incident, the penalties, individually and/or in the aggregate, may exceed $300,000; however, we expect that the resolution of this matter will not have a material adverse impact on our financial condition, results of operations or liquidity.


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Item 1A. Risk Factors

There are no material changes to the risk factors previously disclosed in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2023 other than those listed below.

Risks Related to Gathering Segment and Transmission Segment Operations

We are subject to numerous operational risks and hazards incidental to the gathering, transmission and storage of natural gas, as well as unforeseen interruptions.

Our business operations are subject to the inherent hazards and risks normally incidental to the gathering, transmission and storage of natural gas. These operating risks, some of which we have experienced and/or could experience in the future, include but are not limited to:

•aging infrastructure and mechanical or structural problems;
•security risks, including cybersecurity;
•pollution and other environmental risks;
•operator error;
•failure of equipment, facilities or new technology;
•damage to pipelines, wells and storage assets, facilities, equipment, environmental controls and surrounding properties, and pipeline blockages or other operational interruptions, caused or exacerbated by natural phenomena, weather conditions, acts of sabotage, vandalism and terrorism;
•inadvertent damage from construction, vehicles, and farm and utility equipment;
•uncontrolled releases of natural gas and other hydrocarbons or of fresh, mixed or produced water, or other hazardous materials;
•leaks, migrations or losses of natural gas as a result of issues regarding pipeline and/or storage equipment or facilities and, including with respect to storage assets, as a result of undefined boundaries, geologic anomalies, limitations in then-applied industry-standard testing methodologies, operational practices (including as a result of regulatory requirements), natural pressure migration and wellbore migration or other factors relevant to such storage assets;
•ruptures, fires, leaks and explosions; and
•other hazards that could also result in personal injury and loss of life, pollution to the environment and suspension of operations.

Any such events, certain of which we have experienced, and any of which we may experience in the future, could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment or interruption, which could be significant, to our operations, regulatory investigations and penalties or other sanctions and substantial losses to us and could have a material adverse effect on our business, financial condition, results of operations, and liquidity, particularly if the event is not fully covered by insurance. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. Accidents or other operating risks have resulted, and in the future could result, in loss of service available to our customers. Customer impacts arising from service interruptions on segments of our systems and/or our assets have included and/or may include, without limitation and as applicable, curtailments, limitations on our ability to satisfy customer contractual requirements, obligations to provide reservation charge credits to customers and solicitation of our existing customers by third parties for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to retain customers and negatively impact our business, financial condition, results of operations, and liquidity.


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Expanding our business by constructing new midstream assets subjects us to construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties that are beyond our control.

The development and construction by us or our joint ventures of pipeline and storage facilities and the optimization of such assets involve numerous construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties that are beyond our control, require the expenditure of significant amounts of capital and expose us to risks. Those risks include, but are not limited to: (i) physical construction conditions, such as topographical, or unknown or unanticipated geological, conditions and impediments; (ii) construction site access logistics; (iii) crew availability and productivity and ability to adhere to construction workforce drawdown plans; (iv) adverse weather conditions; (v) project opposition, including delays caused by landowners, advocacy groups or activists opposed to our projects and/or the natural gas industry through lawsuits or intervention in regulatory proceedings; (vi) environmental protocols and evolving regulatory or legal requirements and related impacts therefrom, including additional costs of compliance; (vii) the application of time of year or other regulatory restrictions affecting construction, (viii) failure to meet customer contractual requirements; (ix) environmental hazards; (x) vandalism; (xi) the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof, including as a result of inflation); (xii) issues regarding availability of or access to connecting infrastructure; and (xiii) the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained, including by reason of judicial hostility or activism). Risks inherent in the construction of these types of projects, such as unanticipated geological conditions, challenging terrain in certain of our construction areas and severe or continuous adverse weather conditions, have adversely affected, and in the future could adversely affect, project timing, completion and cost, as well as increase the risk of loss of human life, personal injuries, significant damage to property or environmental pollution. Most notably, certain of these risks have been realized in the construction of the MVP project, including construction-related risks and adverse weather conditions, and such risks or other risks may be realized in the future which may further adversely affect the timing and/or cost of the MVP and the MVP Southgate project.

Given such risks and uncertainties, our midstream projects or those of our joint ventures may not be completed on schedule, within budgeted cost or at all. As a further example, public participation, including by pipeline infrastructure opponents, in the review and permitting process of projects, through litigation or otherwise, has previously introduced, and in the future can introduce, uncertainty and adversely affect project timing, completion and cost. See also Item 1A., "Risk Factors – The regulatory approval process for the construction of new transmission assets is very challenging, and, as demonstrated with the MVP pipeline, has resulted in significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and/or judicial authorities in pending or potential proceedings relevant to the development of midstream assets, particularly any litigation instituted in the Fourth Circuit, such as regarding the MVP Southgate project and/or expansions or extensions of the MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations, including as may be necessary to complete certain projects in a timely manner or at all, or our ability to achieve the expected investment returns on the projects." Further, civil protests regarding environmental justice and social issues or challenges in project permitting processes related to such issues, including proposed construction and location of infrastructure associated with fossil fuels, poses an increased risk and may lead to increased litigation, legislative and regulatory initiatives and review at federal, state, tribal and local levels of government or permitting delays that can prevent or delay the construction of such infrastructure and realization of associated revenues.

Additionally, construction expenditures on projects generally occur over an extended period, yet we will not receive revenues from, or realize any material increases in cash flow as a result of, the relevant project until it is placed into service. Moreover, our cash flow from a project may be delayed or may not meet our expectations, including as a result of taxes which could potentially be calculated based on excess expenditures, inclusive of maintenance, incurred during extended court-driven construction delays. Furthermore, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize or is delayed beyond our expectations. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return. Such issues in respect of the construction of midstream assets could adversely affect our business, financial condition, results of operations and liquidity.


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The regulatory approval process for the construction of new transmission assets is very challenging, and, as demonstrated with the MVP pipeline, has resulted in significantly increased costs and delayed targeted in-service dates, and decisions by regulatory and/or judicial authorities in pending or potential proceedings relevant to the development of midstream assets, particularly any litigation instituted in the Fourth Circuit, such as regarding the MVP Southgate project and/or expansions or extensions of the MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations, including as may be necessary to complete certain projects in a timely manner or at all, or our ability to achieve the expected investment returns on the projects.

Certain of our projects require regulatory approval from federal, state and/or local authorities prior to and/or in the course of construction, including any extensions from, expansions of or additions to our and the MVP Joint Venture's gathering, transmission and storage systems, as applicable. The approval process for certain projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to exploration and production, transmission and gathering activities and associated environmental impacts, and the increasingly negative public perception regarding, and opposition to, the oil and gas industry, including major pipeline projects like the MVP and MVP Southgate. Further, regulatory approvals and authorizations, even when obtained, have increasingly been subject to judicial challenge by activists requesting that issued approvals and authorizations be stayed and vacated.

Accordingly, authorizations needed for our or the MVP Joint Venture's projects, including any expansion of the MVP project and the MVP Southgate project or other extensions, may not be granted or, if granted, such authorizations may include burdensome or expensive conditions or may later be stayed or revoked or vacated, as was repeatedly the case with the construction of the MVP project, particularly in respect of litigation in the Fourth Circuit. Significant delays in the regulatory approval process for projects, as well as stays and losses of critical authorizations and permits, should they be experienced, have the potential to significantly increase costs, delay targeted in-service dates and/or affect operations for projects (among other adverse effects), as has happened with the MVP and the originally contemplated MVP Southgate projects and could occur in the future in the case of authorizations required for our or the MVP Joint Venture's current or future projects, including in respect of developing expansions or extensions, such as expansion of the MVP project and the MVP Southgate project.

Any such adverse developments and uncertainties could adversely affect our ability, and/or, as applicable, the ability for the MVP Joint Venture and its owners, including us, to achieve expected investment returns, adversely affect our willingness or ability and/or that of our joint venture partners to continue to pursue projects, and/or cause impairments, including to our equity investment in the MVP Joint Venture.

We have experienced and may further experience increased opposition with respect to our and the MVP Joint Venture's projects from activists in the form of lawsuits, intervention in regulatory proceedings and otherwise, which could result in adverse impacts to our business, financial condition, results of operations and liquidity. In particular, opponents were successful in past challenges with respect to the MVP project and certain challenges with respect to MVP project authorizations remain outstanding. Opposition is ongoing regarding the MVP Southgate project and is expected for future projects, including any expansions of the MVP. If ongoing or future challenges are successful, it could result in significant, adverse impacts to our business, financial condition, results of operations and liquidity. Such opposition has made it increasingly difficult to complete projects and place them in service and, following any in-service, may also affect operations or affect extensions and/or expansions of projects. Further, such opposition and/or adverse court rulings and regulatory determinations may have the effect of increasing the timeframe on necessary agency action to address actual or perceived concerns in prior adverse court rulings, or may have the effect of increasing the risk that at a future point joint venture partners may elect not to continue to pursue or fund a project, which could, absent additional project sponsors, significantly imperil the ability to complete the project. See also Item 1A., "Risk Factors – We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management's time and our resources. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests and these joint ventures are subject to many of the same risks to which we are subject." Challenges to our projects could adversely affect our business (including by increasing the possibility of investor activism), financial condition, results of operations, and liquidity.


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Increased competition from other companies that provide gathering, transmission and storage of natural gas, or from alternative fuel or energy sources, could negatively impact demand for our services, which could adversely affect our financial results.

Our ability to renew or replace existing contracts or add new contracts at rates sufficient to maintain or grow our Gathering segment and Transmission segment revenues and cash flows could be adversely affected by the activities of our midstream competitors. Our midstream systems compete primarily with other interstate and intrastate pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may be better positioned to compete, including if the midstream industry moves towards greater consolidation. Some of these competitors may expand or construct gathering systems, transmission and storage systems that would create additional competition for the services we provide to our customers. In addition, certain of our customers have developed or acquired their own gathering infrastructure, and may acquire or develop gathering, transmission or storage infrastructure in the future, which could have a negative impact on the demand for our services depending on the location of such systems relative to our assets and our producer customers' drilling plans, commodity prices, existing contracts and other factors.

The policies of the FERC promoting competition in natural gas markets continue to have the effect of increasing the natural gas transmission and storage options for our customer base. As a result, in the future we could experience "turnback" of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored on our systems or, in cases where we do not have long-term firm contracts, could force us to lower our transmission or storage rates.

Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and, increasingly, renewable and alternative energy. Increases, whether driven by legislation, regulation or consumer preferences, in the availability and demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy relative to natural gas based on price and other factors) could adversely affect our producer customers and lead to a reduction in demand for our natural gas gathering, transmission and storage services.

In addition, competition, including from renewable and alternative energy, could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers and/or additional volumes from existing customers as we seek to maintain and expand our business, which could have a material adverse effect on our business, financial condition, results of operations, and liquidity.

We may not be able to renew or replace expiring gathering, transmission or storage contracts at favorable rates, on a long-term basis or at all, and disagreements have occurred and may arise with contractual counterparties on the interpretation of existing or future contractual terms.

One of our exposures to market risk occurs at the time our existing gathering, transmission and storage contracts expire and are subject to renegotiation and renewal. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with existing customers or other customers. We may be unable to do so on favorable commercial terms, if at all. Further, we also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. The extension or renewal of existing contracts and entry into new contracts depends on a number of factors beyond our control, including, but not limited to: (i) the level of existing and new competition to provide services to our markets; (ii) macroeconomic factors affecting natural gas economics for our current and potential customers; (iii) the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; (iv) the extent to which the customers in our markets are willing to contract on a long-term basis or require capacity on our systems; (v) customers' existing and future downstream commitments; and (vi) the effects of federal, state or local regulations on the contracting practices of our customers and us. Additionally, disagreements may arise with contractual counterparties on the interpretation of contractual provisions, including during the negotiation, for example, of contract amendments required to be entered into upon the occurrence of specified events.


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Any failure to extend or replace a significant portion of our existing contracts or to extend or replace our significant contracts, or extending or replacing contracts at unfavorable or lower rates or with lower or no associated firm reservation fee revenues, or other disadvantageous terms relative to the prior contract structure, or disagreements or disputes on the interpretation of existing or future contractual terms, could have a material adverse effect on our business, financial condition, results of operations, and liquidity.

We may not be able to increase our customer throughput and resulting revenue due to competition and other factors, which could limit our ability to grow our Gathering segment and Transmission segment.

Our ability to increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from producers' existing contractual obligations to competitors, the location of our assets relative to those of competitors for existing or potential producer customers (or such producer customers' own midstream assets), takeaway capacity constraints out of the Appalachian Basin, commodity prices, producers' optionality in utilizing our (relative to third-party) systems to fill downstream commitments, and the extent to which we have available capacity when and where shippers require it. To the extent that we lack available capacity on our systems for volumes, or we cannot economically increase capacity, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation and capacity constraints, as well as commodity prices, may, as has occurred in the past, adversely affect the degree to which natural gas production occurs in the Appalachian Basin, and relatedly the degree to which our systems are utilized.

Our efforts to attract new customers or larger commitments from existing customers may be adversely affected by our desire to provide services pursuant to long-term firm contracts and contracts with MVCs. Our potential customers may prefer to obtain services under other forms of contractual arrangements which could require volumetric exposure or potentially direct commodity exposure, and we may not be willing to agree to such other forms of contractual arrangements.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport or process natural gas or do not accept deliveries of natural gas from us, our business, financial condition, results of operations, and liquidity could be adversely affected.

We depend on third-party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage systems. For example, our storage system and the MVP Joint Venture's transmission system interconnect, as applicable, with the following third-party interstate pipelines: Transcontinental Gas Pipe Line Company, LLC, East Tennessee Natural Gas, Texas Eastern, Eastern Gas Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company, Rockies Express Pipeline LLC, National Fuel Gas Supply Corporation and ET Rover Pipeline, LLC, as well as multiple distribution companies. Similarly, our gathering systems have multiple delivery interconnects to multiple interstate pipelines. In the event that our or the MVP Joint Venture's access to such systems is impaired (or any third-party refuses to accept our or any of the MVP Joint Venture's deliveries), our or the MVP Joint Venture's operations could be adversely affected, resulting in adverse economic impact to us or the MVP Joint Venture.

Because we do not own these third-party pipelines or facilities, their continuing operation and access requirements are not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our or the MVP Joint Venture's ability to operate efficiently and ship natural gas to end markets could be restricted, as has occurred in the past. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, and liquidity.


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A substantial majority of the services we provide on our transmission and storage system are subject to long-term, fixed-price "negotiated rate" contracts that are subject to limited or no adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts, we could be unable to achieve the expected investment return under such contracts, and/or our business, financial condition, results of operations, and liquidity could be adversely affected.

It is possible that costs to perform services under "negotiated rate" contracts could exceed the negotiated rates we have agreed to with our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, and liquidity. Under FERC policy, a regulated service provider and a customer may mutually agree to a "negotiated rate," and that contract must be filed with and accepted by the FERC. As of December 31, 2023, approximately 97% of the contracted firm transmission capacity on our system was subscribed under such "negotiated rate" contracts. Unless the parties to these "negotiated rate" contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could be caused by inflation, greenhouse gas emission cost (such as carbon taxes, fees, or assessments) or other factors relating to the specific facilities being used to perform the services.

We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management's time and our resources. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests and these joint ventures are subject to many of the same risks to which we are subject.

We have entered into several joint ventures primarily pertaining to the construction and operation of certain midstream infrastructure, including the MVP Joint Venture and Eureka Midstream Holdings, and may in the future enter into additional joint venture arrangements with third parties, including in respect of any expansion of the MVP. Joint venture arrangements may restrict our operational and corporate flexibility. Joint venture arrangements and dynamics can also divert management and operating resources in a manner that is disproportionate to our ownership percentage in such ventures. Because we do not control all of the decisions of our joint ventures or joint venture partners, it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture's best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing that we fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not act in a manner that we believe would be in our or the joint venture's best interests, may elect not to support further pursuit of projects, and/or may not satisfy their financial obligations to the joint venture. The loss of joint venture partner support in further pursuing or funding a project may, and would in the case of the MVP project, significantly adversely affect the ability to complete the project. In addition, such joint ventures are subject to many of the same risks to which we are subject.

Significant portions of our assets have been in service for several decades. There could be unknown events or conditions, or increased maintenance or repair expenses and downtime, associated with our assets that could have a material adverse effect on our business, financial condition, results of operations, and liquidity.

Significant portions of our transmission and storage system have been in service for several decades. The age and condition of these systems has contributed to, and could result in, adverse events, or increased maintenance or repair expenditures, and downtime associated with increased maintenance and repair activities, as applicable. Any such adverse events or any significant increase in maintenance and repair expenditures or downtime, or related loss of revenue, due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, and liquidity. See also Item 1A., "Risk Factors – We and our joint ventures may incur significant costs and liabilities as a result of performance of our pipeline and storage integrity management programs and compliance with increasingly stringent safety regulation."


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We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations and future development.

We do not own all of the land on which our pipelines, storage systems and facilities have been constructed, and we have been, and in the future could be, subject to more onerous terms, and/or increased costs or delays, in attempting (or by virtue of the need to attempt) to acquire or to maintain use rights to land. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines and other facilities on land owned by third parties and governmental agencies for a specific period of time or in a manner in which certain facts could give rise to the presumption of the abandonment of the pipeline or other facilities. As has been the case in the past, if we were to be unsuccessful in negotiating or renegotiating rights-of-way or easements, we might have to institute condemnation proceedings on our FERC-regulated assets, the potential for which may have a negative effect on the timing and/or terms of FERC action on a project's certification application and/or the timing of any authorized activities, or relocate our facilities for non-regulated assets. The FERC has announced a policy that would presumptively stay the effectiveness of certain future construction certificates, which may limit when we are able to exercise condemnation authority. It is possible that the U.S. Congress may amend Section 7 of the NGA to codify the FERC's presumptive stay or otherwise limit, modify, or remove the ability to utilize condemnation. It is also possible that a court may limit, modify or remove an operator's ability to utilize condemnation under Section 7 of the NGA. A loss of rights-of-way, lease or easements or a relocation of our non-regulated assets could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Additionally, even when we own an interest in the land on which our pipelines, storage systems and facilities have been constructed, agreements with correlative rights owners have caused us to, and in the future may require that we, relocate pipelines and facilities or shut in storage systems and facilities to facilitate the development of the correlative rights owners' estate, or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.

Our and the MVP Joint Venture's natural gas gathering, transmission and storage services, as applicable, are subject to extensive regulation by federal, state and local regulatory authorities. Changes in or additional regulatory measures adopted by such authorities, and related litigation, could have a material adverse effect on our business, financial condition, results of operations, and liquidity.

Our and the MVP Joint Venture's interstate natural gas transmission and storage operations, as applicable, are regulated by the FERC under the NGA and the Natural Gas Policy Act of 1978 (NGPA) and the regulations, rules and policies promulgated under those and other statutes. Our and the MVP Joint Venture's FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to our customers. The FERC's authority extends to a variety of matters relevant to our operations.

Pursuant to the NGA, existing interstate transmission and storage rates, terms and conditions of service, and contracts may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases, changes to terms and conditions of service and contracts proposed by a regulated interstate pipeline may be protested and such actions can be delayed and may ultimately be rejected by the FERC. As of the filing of this Quarterly Report on Form 10-Q, we and the MVP Joint Venture currently hold authority from the FERC to charge and collect (i) "recourse rates," which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) "discount rates," which are rates below the "recourse rates" and above a minimum level, (iii) "negotiated rates," which involve rates that may be above or below the "recourse rates," provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2023, approximately 97% of our contracted firm transmission capacity was subscribed to by customers under negotiated rate agreements under our tariff, rather than recourse, discount or market-based rate contracts. There can be no guarantee that we or the MVP Joint Venture will be allowed to continue to operate under such rates or rate structures for the remainder of those assets' operating lives. Customers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our or the MVP Joint Venture's rates offered to customers or the terms and conditions of service included in our tariffs. Neither we nor the MVP Joint Venture have an agreement in place that would prohibit customers from challenging our or the MVP Joint Venture's rates or tariffs. Any successful challenge against rates charged for our or the MVP Joint Venture's transmission and storage services, as applicable, could have a material adverse effect on our business, financial condition, results of operations, and liquidity.


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Any changes to the FERC's policies regarding the natural gas industry may have an impact on us, including the FERC's approach to pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities. The FERC and U.S. Congress may continue to evaluate changes in the NGA or new or modified FERC regulations or policies that may impact our or the MVP Joint Venture's operations and affect our or the MVP Joint Venture's ability to construct new facilities and the timing and cost of such new facilities, as well as the rates charged to our or the MVP Joint Venture's customers and the services provided.

Our and the MVP Joint Venture's significant construction projects generally require review by multiple governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency's delay in the issuance of, or refusal to issue, authorizations or permits, issuance of such authorizations or permits with unanticipated conditions, or the loss of a previously-issued authorization or permit, for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate (as has been the case with our MVP project). Such delays, refusals, losses of permits, or resulting modifications to projects, certain of which we have experienced with respect to the MVP project and the originally contemplated MVP Southgate project, could materially and negatively impact the revenues and costs expected from these projects or cause us or our joint venture partners to abandon planned projects.

Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.5 million (adjusted periodically for inflation) per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes.

In addition, future federal, state or local legislation or regulations under which we or the MVP Joint Venture will operate may have a material adverse effect on our business, financial condition, results of operations, and liquidity.

We and our joint ventures may incur significant costs and liabilities as a result of performance of our pipeline and storage integrity management programs and compliance with increasingly stringent safety regulation.

The U.S. Department of Transportation, acting through PHMSA, and certain state agencies certificated by PHMSA, have adopted regulations requiring pipeline operators to develop an integrity management program for transmission pipelines located where a leak or rupture could impact high population sensitive areas (also known as High Consequence Areas) and newly defined Moderate Consequence Areas, and an integrity management program for storage wells, unless the operator effectively demonstrates by a prescriptive risk assessment that these operational assets have mitigated risks that could affect these predefined areas, as applicable. The regulations require operators, including us, to perform ongoing assessments of pipeline and storage integrity; identify and characterize applicable threats to pipeline segments and storage wells that could impact population sensitive areas; confirm maximum allowable operating pressures; maintain and improve processes for data collection, integration and analysis; repair and remediate facilities as necessary; and implement preventive and mitigating actions. In addition to population sensitive areas, PHMSA has recently adopted regulations extending existing design, operation and maintenance, and reporting requirements to onshore gathering pipelines in rural areas. Finally, new PHMSA regulations require operators of certain transmission pipelines to assess their integrity management and maintenance practices, comply with enhanced corrosion control and mitigation timelines, and follow new requirements for pipeline inspections following an extreme weather event or natural disaster.

The cost and financial impact of compliance will vary and depend on factors such as the number and extent of maintenance determined to be necessary as a result of the application of our integrity management programs, and such costs and financial impact could have a material adverse effect on us. Further, our pipeline and storage integrity management programs depend in part on inspection tools and methodologies developed, maintained, enhanced and applied, and certain testing conducted, by certain third parties, many of which are widely utilized within the natural gas industry. Advances in these tools and methodologies could identify potential and/or additional integrity issues for our assets. Consequently, we may incur additional costs and expenses to remediate those newly identified or potential issues, and we may not have the ability to timely comply with applicable laws and regulations. Additionally, pipeline and storage safety laws and regulations are subject to change and failures to comply with pipeline and storage safety laws and regulations, including changes in such laws and regulations or interpretations thereof that result in more stringent or costly safety standards, could have a material adverse effect on us.


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We may, and joint ventures of which we are the operator could, as is the case with the MVP Joint Venture, become subject to consent orders and agreements relating to integrity matters. Failure to comply with any such consent order or agreements could have adverse effects on our business.

Risks Related to the Equitrans Midstream Merger

We incurred significant indebtedness as a result of the Equitrans Midstream Merger, and any future indebtedness, as well as the restrictions under our and our subsidiaries' debt agreements, could adversely affect our operating flexibility, business, financial condition, results of operations, and liquidity.

As a result of the Equitrans Midstream Merger, we incurred additional indebtedness under EQT's revolving credit facility, and the outstanding debt under Eureka's revolving credit facility and the outstanding senior notes issued by EQM were consolidated by the Company. See Note 7 to the Condensed Consolidated Financial Statements for a discussion of EQT's revolving credit facility, Eureka's revolving credit facility and the outstanding senior notes issued by EQM. Eureka's revolving credit facility contains various covenants and restrictive provisions that limit Eureka's ability to, among other things: incur or guarantee additional debt, make distributions on or redeem or repurchase membership units, incur or permit liens on assets, enter into certain types of transactions with affiliates, enter into burdensome agreements, subject to certain specified exceptions, enter into certain mergers or acquisitions; and, dispose of all or substantially all of their respective assets.

Additionally, under Eureka's revolving credit facility, Eureka is required to maintain a Consolidated Leverage Ratio (as defined in the Eureka Credit Agreement) of not more than 4.75 to 1.00 (or not more than 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions). As of the end of any fiscal quarter, Eureka may not permit the ratio of Consolidated EBITDA (as defined in the Eureka Credit Agreement) for the four fiscal quarters then ending to Consolidated Interest Charges (as defined in the Eureka Credit Agreement) to be less than 2.50 to 1.00. Eureka's revolving credit facility also contains certain events of default, including the occurrence of a change of control (as defined in the Eureka Credit Agreement). Events beyond the control of Eureka (including changes in general economic and business conditions) may affect the ability of Eureka to meet and comply with their respective financial obligations and covenants.

The provisions of our and our subsidiaries' debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of these debt agreements could result in an event of default, which could enable creditors to, subject to the terms and conditions of the applicable agreement, declare any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and in turn our shareholders could experience a partial or total loss of their investments. EQT's revolving credit facility, Eureka's revolving credit facility, the Term Loan Facility and certain of EQT's and EQM's senior notes each contain a cross default provision that applies to a default related to any other indebtedness the applicable borrower may have with an aggregate principal amount in excess of a specified threshold as set forth in the applicable debt documents.

Our and our subsidiaries' levels of debt could have important consequences to us, including that our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms; our funds available for operations, future business opportunities and dividends to our shareholders may be reduced by that portion of our cash flow required to make interest payments on our or our subsidiaries' debt; we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our and our subsidiaries' current, or our or our subsidiaries' future respective debts, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. Further, we view de-levering our business as a critical strategic objective given that leverage levels affect the manner in which we may pursue strategic and organic initiatives, our ability to respond to market and competitive pressures, and the competition for investment capital. Our ability to de-lever and the pace thereof will depend on our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, as well as the MVP Joint Venture's ability to execute on project-level financing, some of which are beyond our control.


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If our operating results are not sufficient to service our and our subsidiaries' current, or our or our subsidiaries' future indebtedness, as applicable, or our operating results affect our ability to comply with covenants in our debt agreements, we may be forced to take actions such as seeking modifications to the terms of our debt agreements, including providing guarantees, pledging assets as collateral, reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity or debt capital. We may not be able to timely effect any of these actions on satisfactory terms or at all. Further, if our operating results are not sufficient to enable de-levering or affect the pace of de-levering, or if MVP project-level financing is not realized, the manner in which we may pursue strategic and organic initiatives, address market and competitive pressures, and compete for investment capital may be adversely affected, absent additional actions to de-lever, which may not be available to us on satisfactory terms or at all.

Our and our subsidiaries' current indebtedness and the additional debt we and/or our subsidiaries will incur in the future for, among other things, working capital, repayment of existing indebtedness, capital expenditures, capital contributions to joint ventures, including the MVP Joint Venture, acquisitions or operating activities may adversely affect our liquidity and therefore our ability to pay dividends to our shareholders.

In addition, our and our subsidiaries' level of indebtedness may be viewed negatively by credit rating agencies, our or our subsidiaries' credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise our shareholder returns strategy or other strategic plans. Changes in our or our subsidiaries' credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on EQT's revolving credit facility, Eureka's revolving credit facility, the Term Loan Facility and EQT's senior notes with adjustable rates, the rates available on new long-term debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

We may not achieve the anticipated benefits of the Equitrans Midstream Merger, and the Equitrans Midstream Merger may disrupt our current plans or operations.

There can be no assurance that we will be able to successfully integrate Equitrans Midstream and the anticipated benefits of the transaction may not be realized fully or at all or may take longer to realize than expected. If the combined company is not able to realize the anticipated benefits expected from the transaction within the anticipated timing or at all, the combined company's business, financial condition and operating results may be adversely affected, the combined company's earnings per share may be diluted, the accretive effect of the Equitrans Midstream Merger may decrease or be delayed and the share price of the combined company may be negatively impacted. The integration of the two companies has required and will continue to require significant time and focus from management and could result in performance shortfalls as a result of the diversion of management's attention to such integration efforts. Difficulties in integrating Equitrans Midstream into our company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated synergies on the anticipated timeline. Potential difficulties that may be encountered in the integration process include, among others, complexities associated with managing a larger, more complex, integrated business; potential unknown liabilities and unforeseen expenses associated with Equitrans Midstream; and inconsistencies between the two company's standards, controls, procedures and policies. In addition, our business may be negatively impacted if we are unable to effectively manage our expanded operations.

We are expected to continue to incur significant transaction costs in connection with the Equitrans Midstream Merger, which may be in excess of those anticipated by us.

We have incurred and are expected to continue to incur a number of non-recurring costs associated with the Equitrans Midstream Merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial and could have an adverse effect on our financial condition and operating results. For the three and nine months ended September 30, 2024, we recognized $274.6 million and $298.7 million, respectively, of transaction costs related to the Equitrans Midstream Merger. Of this amount, for the three months ended September 30, 2024, we recognized severance and other termination benefits and stock-based compensation costs of $161.0 million.


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Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

We did not repurchase any equity securities registered under Section 12 of the Exchange Act during the third quarter of 2024.

On December 13, 2021, we announced that our Board of Directors approved a share repurchase program (the Share Repurchase Program) authorizing us to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $1 billion, excluding fees, commissions and expenses. On September 6, 2022, we announced that our Board of Directors approved a $1 billion increase to the Share Repurchase Program, pursuant to which approval we are authorized to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses. Repurchases under the Share Repurchase Program may be made from time to time in amounts and at prices we deem appropriate and will be subject to a variety of factors, including the market price of our common stock, general market and economic conditions, applicable legal requirements and other considerations. The Share Repurchase Program was originally scheduled to expire on December 31, 2023; however, on April 26, 2023, we announced that our Board of Directors approved a one-year extension of the Share Repurchase Program. As a result of such extension, the Share Repurchase Program will expire on December 31, 2024, but it may be suspended, modified or discontinued at any time without prior notice. As of September 30, 2024, we had purchased shares for an aggregate purchase price of $622.1 million, excluding fees, commissions and expenses, under the Share Repurchase Program since its inception, and the approximate dollar value of shares that may yet be purchased under the Share Repurchase Program is $1.4 billion.

Item 5.    Other Information

During the three months ended September 30, 2024, none of our directors or "officers" (as such term is defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" (as each term is defined in Item 408(a) of Regulation S-K).

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Item 6.    Exhibits
Exhibit No.DescriptionMethod of Filing
Amended and Restated Purchase Agreement, dated December 23, 2022, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation.Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on December 27, 2022.
First Amendment to Amended and Restated Purchase Agreement, dated April 21, 2023, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation.Incorporated herein by reference to Exhibit 2.2 to Form 8-K (#001-3551) filed on August 22, 2023.
Second Amendment to Amended and Restated Purchase Agreement, dated August 21, 2023, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation.Incorporated herein by reference to Exhibit 2.3 to Form 8-K (#001-3551) filed on August 22, 2023.
Agreement and Plan of Merger, dated March 10, 2024, among EQT Corporation, Humpty Merger Sub Inc., Humpty Merger Sub LLC and Equitrans Midstream Corporation.Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on March 11, 2024.
Restated Articles of Incorporation of EQT Corporation (as amended through November 13, 2017).Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on November 14, 2017.
Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective May 1, 2020).Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on May 4, 2020.
Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective July 23, 2020).Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on July 23, 2020.
Articles of Amendment to the Restated Articles of Incorporation of EQT Corporation (effective July 18, 2024).Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on July 18, 2024.
Amended and Restated Bylaws of EQT Corporation (as amended through December 12, 2023).Incorporated herein by reference to Exhibit 3.2 to Form 8-K (#001-3551) filed on December 12, 2023.
Amendment to Amended and Restated Bylaws of EQT Corporation (effective July 18, 2024).Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-3551) filed on July 22, 2024.
Indenture, dated August 1, 2014, among EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, the subsidiaries of EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee.Incorporated herein by reference to Exhibit 4.1 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on August 1, 2014.
Second Supplemental Indenture, dated November 4, 2016, between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 4.125% Senior Notes due 2026 were issued.Incorporated herein by reference to Exhibit 4.2 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on November 4, 2016.
Fourth Supplemental Indenture, dated June 25, 2018, between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 5.500% Senior Notes due 2028 were issued.Incorporated herein by reference to Exhibit 4.4 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on June 25, 2018.

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Exhibit No.DescriptionMethod of Filing
Fifth Supplemental Indenture, dated June 25, 2018, between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 6.500% Senior Notes due 2048 were issued.Incorporated herein by reference to Exhibit 4.6 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on June 25, 2018.
Indenture, dated June 18, 2020, between EQM Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 6.000% Senior Notes due 2025 and 6.500% Senior Notes due 2027 were issued.Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on June 18, 2020.
Indenture, dated January 8, 2021, between EQM Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which EQM Midstream Partners, LP’s 4.50% Senior Notes due 2029 and 4.75% Senior Notes due 2031 were issued.Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on January 8, 2021.
Indenture, dated June 7, 2022, between EQM Midstream Partners, LP and U.S. Bank Trust Company, National Association, as trustee, pursuant to which EQM Midstream Partners, LP’s 7.500% Senior Notes due 2027 and 7.500% Senior Notes due 2030 were issued.Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on June 7, 2022.
Indenture, dated February 26, 2024, between EQM Midstream Partners, LP and U.S. Bank Trust Company, National Association, as trustee, pursuant to which EQM Midstream Partners, LP’s 6.375% Senior Notes due 2029 were issued.Incorporated herein by reference to Exhibit 4.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on February 26, 2024.
Fourth Amended and Restated Credit Agreement, dated July 22, 2024, among EQT Corporation, PNC Bank, National Association, as Administrative Agent, Swing Line Lender and L/C Issuer, and the other lenders party thereto.Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on July 22, 2024.
Fourth Amendment to Credit Agreement, dated July 22, 2024, among EQT Corporation, PNC Bank, National Association, as Administrative Agent, and the other lenders party thereto.Incorporated herein by reference to Exhibit 10.2 to Form 8-K (#001-3551) filed on July 22, 2024.
Second Amendment to the EQT Corporation 2020 Long-Term Incentive Plan.Incorporated herein by reference to Exhibit 10.3 to Form 8-K (#001-3551) filed on July 22, 2024.
Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated as of April 6, 2018, by and among MVP Holdco, LLC, US Marcellus Gas Infrastructure, LLC, WGL Midstream MVP LLC (formerly WGL Midstream, Inc.), Con Edison Gas Pipeline and Storage, LLC, RGC Midstream, LLC and Mountain Valley Pipeline, LLC. Specific items in this exhibit have been redacted, as marked by three asterisks [***], because confidential treatment for those items has been granted by the SEC. The redacted material has been separately filed with the SEC.Incorporated herein by reference to Exhibit 10.1 to EQM Midstream Partners, LP's Form 10-Q/A (#001-35574) for the quarter ended March 31, 2018.
First Amendment to Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated as of February 5, 2020, by and among MVP Holdco, LLC, US Marcellus Gas Infrastructure, LLC, WGL Midstream MVP LLC (formerly WGL Midstream, Inc.), Con Edison Gas Pipeline and Storage, LLC, RGC Midstream, LLC and Mountain Valley Pipeline, LLC.Incorporated herein by reference to Exhibit 10.21(b) to Equitrans Midstream Corporation's Form 10-K (#001-38629) for the year ended December 31, 2019.

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Exhibit No.DescriptionMethod of Filing
Equitrans Midstream Corporation Amended and Restated Directors' Deferred Compensation Plan.Incorporated herein by reference to Exhibit 10.18 to Equitrans Midstream Corporation’s Form 10-Q (#001-38629) for the quarter ended March 31, 2020.
Form of Equitrans Midstream Corporation Director Participant Award Agreement.Incorporated herein by reference to Exhibit 10.10 to Equitrans Midstream Corporation’s Form 10-Q (#001-38629) for the quarter ended March 31, 2019.
Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam.Incorporated herein by reference to Exhibit 10.9 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on November 13, 2018.
First Amendment, dated February 20, 2023, to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam.Incorporated herein by reference to Exhibit 10.15(b) to Equitrans Midstream Corporation’s Form 10-K (#001-38629) for the year ended December 31, 2022.
Second Amendment, effective September 6, 2023, to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated November 13, 2018, between Equitrans Midstream Corporation and Thomas F. Karam.Incorporated herein by reference to Exhibit 10.3 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on September 7, 2023.
Transition Agreement, dated September 6, 2023, between Equitrans Midstream Corporation and Thomas F. Karam.Incorporated herein by reference to Exhibit 10.1 to Equitrans Midstream Corporation’s Form 8-K (#001-38629) filed on September 7, 2023.
Separation Agreement and General Release, dated August 14, 2024, between EQT Corporation and Thomas F. Karam.Filed herewith as Exhibit 10.06(e).
Rule 13(a)-14(a) Certification of Principal Executive Officer.Filed herewith as Exhibit 31.01.
Rule 13(a)-14(a) Certification of Principal Financial Officer.Filed herewith as Exhibit 31.02.
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer.Furnished herewith as Exhibit 32.
101Interactive Data File.Filed herewith as Exhibit 101.
104Cover Page Interactive Data File.Formatted as Inline XBRL and contained in Exhibit 101.

+ Certain schedules and similar attachments to this exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. EQT Corporation agrees to provide a copy of any omitted schedule or attachment to the Securities and Exchange Commission or its staff upon request.

** Management contract or compensatory arrangement.

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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 EQT CORPORATION
 (Registrant)
  
  
 By:/s/ Jeremy T. Knop
 Jeremy T. Knop
 
Chief Financial Officer
 Date:  October 30, 2024


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