EQT Corp (EQT)

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

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

Recent and Significant Events

Midstream Joint Venture Transaction

On December 30, 2024, in connection with the completion of the Midstream Joint Venture Transaction, the Midstream Joint Venture received $3.5 billion of cash consideration, net of certain transaction fees and expenses, from a third-party investor in exchange for a noncontrolling equity interest in the Midstream Joint Venture. We used the proceeds from the Midstream Joint Venture Transaction to repay outstanding borrowings under the Bridge Credit Facility (defined in Note 10 to the Consolidated Financial Statements) and the Term Loan Facility and a portion of outstanding borrowings under EQT's revolving credit facility. Borrowings under the Bridge Credit Facility were used to fund the redemption and repurchase of certain of EQM's senior notes, including pursuant to the EQM Tender Offer (defined in Note 10 to the Consolidated Financial Statements).

NEPA Non-Operated Asset Divestitures and NEPA Gathering System Acquisition

Results of operations for 2024 include the results of our operation of assets received as consideration for the First NEPA Non-Operated Asset Divestiture, which closed on May 31, 2024. Such assets received included the remaining 16.25% equity interest in the NEPA Gathering System (defined in Note 6 to the Consolidated Financial Statements) (which was the sole remaining minority interest following our acquisition of a 33.75% equity interest in the NEPA Gathering System Acquisition (defined in Note 6 to the Consolidated Financial Statements) on April 11, 2024), resulting in our 100% ownership of the NEPA Gathering System. See Note 7 to the Consolidated Financial Statements.

In addition, on December 31, 2024, we completed the Second NEPA Non-Operated Asset Divestiture. See Note 7 to the Consolidated Financial Statements. We used the proceeds from the Second NEPA Non-Operated Asset Divestiture of $1.25 billion, subject to customary post-closing purchase price adjustments and transaction costs, to repay a portion of outstanding borrowings under EQT's revolving credit facility.

Equitrans Midstream Merger

Results of operations for 2024 include the results of our operation of assets acquired in the Equitrans Midstream Merger, which closed on July 22, 2024. Following the completion of the Equitrans Midstream Merger, we own a gathering system with 1,975 miles of gathering lines (including gathering lines owned prior to the Equitrans Midstream Merger) and a transmission and storage system with approximately 950 miles of FERC-regulated, interstate pipelines. See Note 6 to the Consolidated Financial Statements.

For the period from July 22, 2024 through December 31, 2024, our consolidated gathering expense decreased due to our ownership of the gathering and transmission assets acquired in the Equitrans Midstream Merger. Our ownership of such assets will continue to positively impact our Production segment's gathering expense, with a corresponding increase to our Production segment's affiliate transportation and processing expense, which is eliminated in consolidation. This relationship will be prominent for full year 2025 results and beyond.

Tug Hill and XcL Midstream Acquisition

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

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Trends and Uncertainties

On March 4, 2024, we announced our decision to strategically curtail approximately 1.0 Bcfe per day of gross production (the Strategic Curtailment) beginning on February 24, 2024 in response to the low natural gas price environment resulting from warm winter weather and elevated storage inventories. The Strategic Curtailment resulted in total decreased sales volume of 107 Bcfe for 2024. In addition, certain operators of wells in which we have a non-operating working interest also curtailed production in 2024. For 2024, we estimate that our total expected sales volume was negatively impacted by approximately 130 to 140 Bcfe of curtailments, including our Strategic Curtailment of 107 Bcfe and curtailments by certain operators of wells in which we have a non-operating working interest.

Low natural gas prices or volatility in the natural gas market may result in adjustments to our 2025 planned development schedule or the development schedule of non-operated wells in which we have a working interest. Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our 2025 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

In connection with the recent U.S. election and corresponding inauguration of President Trump on January 20, 2025, the President executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the institution of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. A changing regulatory environment could increase our costs to comply with such regulations or make us susceptible to lawsuits or fines for failure to comply with such regulations. Further, tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the price of natural gas, increase the price of supplies and raw materials that we rely on to conduct our business, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

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

Consolidated Results of Operations

Net income attributable to EQT Corporation for 2024 was $231 million, $0.45 per diluted share, compared to $1,735 million, $4.22 per diluted share, for 2023. The decrease was attributable primarily to a lower gain on derivatives, increased depreciation, depletion and amortization, increased other operating expenses and increased net interest expense, partly offset by the gains on the NEPA Non-Operated Asset Divestitures, decreased income tax expense, increased pipeline revenues and decreased transportation and processing expense.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2022.

We did not recast our discussion and analysis of financial condition and results of operations for the year ended December 31, 2022 for our change in reportable segments as such change does not materially change our historic comparative discussion of our financial condition and results of operations for the years ended December 31, 2023 and 2022 included within the 2023 Annual Report. Prior to the Equitrans Midstream Merger, we operated our business as a single segment and did not generate material third-party gathering operating income. Further, in our judgment, we do not believe such a recast is necessary to an understanding of our business, financial condition, changes in financial condition and results of operations. See Note 2 to the Consolidated Financial Statements for financial information by business segment, including our profit and loss metric and capital expenditures for the year ended December 31, 2022 and segment assets as of December 31, 2022.

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

Average Realized Price Reconciliation

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

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

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

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

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Non-GAAP Financial Measures Reconciliation

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

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

(a)For the years ended December 31, 2024 and 2023, composed of net cash settlements received on NYMEX natural gas hedge positions of approximately $1,374 million and $976 million , respectively, and net cash settlements paid on basis and liquids hedge positions of $157 million and $76 million, respectively. Net cash settlements received on derivatives are included in average realized price but may not be included in operating revenues.

Business Segment Results of Operations

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

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

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

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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

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

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

Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for 2024 compared to 2023 by approximately $110 million, of which approximately $640 million was attributable to lower average sales price, which was partly offset by approximately $530 million attributable to increased sales volumes. The average sales price decreased for 2024 compared to 2023 due to a lower NYMEX price, partly offset by lower basis spreads and higher NGLs price. Sales volume increased for 2024 compared to 2023 primarily as a result of sales volume increases of 164 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition as well as increases from wells turned-in-line, partly offset by sales volume decreases of 107 Bcfe from the Strategic Curtailment and net decreases of 21 Bcfe due to the First NEPA Non-Operated Asset Divestiture. The increase in sales volume had a favorable impact on per unit costs for 2024 compared to 2023.

Production gain on derivatives. For 2024, we recognized a gain on derivatives of approximately $68 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $377 million due to decreases in NYMEX forward prices, partly offset by decreases in the fair market value of our basis swaps of approximately $309 million. For 2023, we recognized a gain on derivatives of approximately $1,839 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $1,830 million due to decreases in NYMEX forward prices as well as increases in the fair market value of our basis swaps of approximately $9 million.

Transportation and processing

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

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

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

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

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

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

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Selling, general and administrative. Selling, general and administrative expense increased on an absolute basis for 2024 compared to 2023 due primarily to higher legal and professional services costs as well as higher personnel costs due to increased workforce headcount. In addition, we did not recast selling, general and administrative expense for periods prior to the Equitrans Midstream Merger closing date and, upon the Equitrans Midstream Merger closing date, we adjusted our basis for selling, general and administrative expense allocation for multi-segment reporting.

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

(Gain) loss on sale/exchange of long-lived assets. During 2024, we recognized a gain on the First NEPA Non-Operated Asset Divestiture of approximately $299 million and a gain on the Second NEPA Non-Operated Asset Divestiture of approximately $463 million. See Note 7 to the Consolidated Financial Statements. During 2023, we recognized a loss on sale/exchange of long-lived assets of approximately $17 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.

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

Other operating expenses. We recognized approximately $13 million and $9 million of other operating expenses for 2024 and 2023, respectively. Other operating expenses increased for 2024 compared to 2023 due primarily to increased rig release expense and increased legal and environmental reserves, including from settlements, partly offset by proceeds received in 2024 from business interruption insurance claim recoveries. See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses.

GATHERING

(a)For agreements structured with MVCs, includes volumes up to the contractual MVC; volumes in excess of the contractual MVC are reported under volumetric-based services.

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

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

TRANSMISSION

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

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

Other Income Statement Items

Other operating expenses. We recognized $337.2 million and $74.9 million of corporate other operating expenses for 2024 and 2023, respectively. Corporate other operating expenses increased for 2024 compared to 2023 due primarily to transaction costs related to the Equitrans Midstream Merger of $304.8 million and higher legal reserves, partly offset by lower transaction costs related to the Tug Hill and XcL Midstream Acquisition. See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses.

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

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

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

Loss on debt extinguishment. During 2024, we recognized a loss on debt extinguishment of $68.3 million due primarily to premiums and financing costs paid on our redemption and repurchase of certain of EQM's senior notes, including pursuant to the EQM Tender Offer, and non-cash losses related to our write off of the unamortized fair value adjustments of those redeemed and repurchased EQM senior notes and unamortized deferred issuance costs of the Term Loan Facility. See Note 10 to the Consolidated Financial Statements.

Interest expense, net. Net interest expense increased for 2024 compared to 2023 due primarily to interest expense on EQM's senior notes, increased interest expense on our borrowings under EQT's revolving credit facility, interest expense on EQT's 5.750% senior notes issued in January 2024, lower interest income earned on cash on hand and interest expense on Eureka Midstream, LLC's (Eureka) borrowings under its revolving credit facility, partly offset by decreased interest expense from our repayment and repurchase of certain of EQT's senior notes as well as higher capitalized interest from the assets acquired in the Tug Hill and XcL Midstream Acquisition. See Note 10 to the Consolidated Financial Statements.

Income tax expense. See Note 9 to the Consolidated Financial Statements.

Net income (loss) attributable to noncontrolling interests. During 2024, we recognized $11.4 million of net income attributable to noncontrolling interests of Eureka Midstream Holdings, a consolidated joint venture in which we acquired an equity interest as a result of the Equitrans Midstream Merger. Sees Note 1 and 6 to the Consolidated Financial Statements.

Capital Resources and Liquidity

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

Purchase Obligations

We have commitments to pay demand charges under long-term contracts and binding precedent agreements with various pipelines as well as charges for processing capacity to extract heavier liquid hydrocarbons from the natural gas stream. In addition, we have commitments to pay for services related to our operations, including electric hydraulic fracturing services and purchase equipment, materials and sand. See Note 15 to the Consolidated Financial Statements for a summary of aggregated future payments for these commitments.

Unrecognized Tax Benefits

As of December 31, 2024, we had a total reserve for unrecognized tax benefits of $9.0 million and an additional reserve of $60.4 million that was offset against deferred tax assets for general business tax credit carryforwards and net operating losses (NOLs). We settled our consolidated U.S. federal income tax liability with the IRS through 2019 in September 2024. We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities. See Note 9 to the Consolidated Financial Statements for further discussion.

Planned Capital Expenditures and Sales Volume

In 2025, we expect to spend approximately $2.3 billion to $2.5 billion on total capital expenditures. 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 2025 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. In 2025, we expect our sales volume to be 2,175 Bcfe to 2,275 Bcfe.

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Material Cash Requirements

We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 10 to the Consolidated Financial Statements for a summary of such contractual commitments, including maturity dates.

Operating Activities

Net cash provided by operating activities was $2,827 million and $3,179 million for 2024 and 2023, respectively. The decrease was due primarily to changes in working capital from movements in the market price for natural gas and timing of payments as well as higher cash operating expenses (including from transaction costs related to the Equitrans Midstream Merger), higher net interest expense and higher share-based compensation expense. Such decreases were partly offset by higher net cash settlements received on derivatives, lower net premiums paid on derivatives, higher cash operating revenues (including from pipeline revenues on assets acquired in the Equitrans Midstream Merger) and higher distributions from equity method investments (including approximately $53 million from our investment in the MVP Joint Venture).

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

Investing Activities

Net cash used in investing activities was $1,580 million and $4,314 million for 2024 and 2023, respectively. The decrease was attributable primarily to the proceeds received from the NEPA Non-Operated Asset Divestitures in 2024 and lower cash paid for acquisitions in 2024 (primarily for the NEPA Gathering System Acquisition) compared to 2023 (primarily for the Tug Hill and XcL Midstream Acquisition), partly offset by increased capital expenditures and capital contributions made to our investment in the MVP Joint Venture of approximately $145 million.

The following table summarizes our capital expenditures by business segment.

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

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

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Financing Activities

Net cash used in financing activities was $1,126 million and $243 million for 2024 and 2023, respectively. For 2024, the primary uses of financing cash flows were our repayment and retirement of debt, repayment of EQM's revolving credit facility, payment of dividends and cash paid for taxes to net settle share-based incentive awards. For 2024, the primary sources of financing cash flows were net proceeds from the sale of units of the Midstream Joint Venture, proceeds from the issuance of EQT's 5.750% senior notes, net borrowings under EQT's revolving credit facility and proceeds from the net settlement of the Capped Call Transactions (defined in Note 10 to the Consolidated Financial Statements). For 2023, the primary uses of financing cash flows were our repayment and retirement of debt, payment of dividends and repurchase and retirement of EQT common stock, and the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings.

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

On February 6, 2025, our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT common stock, payable on March 3, 2025, to shareholders of record at the close of business on February 18, 2025.

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 10 to the Consolidated Financial Statements for discussion of redemptions and repurchases of debt and Note 12 to the Consolidated Financial Statements for discussion of repurchases of EQT common stock.

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 Consolidated Financial Statements for a description of what is deemed investment grade.

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

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

Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our revolving credit facilities, the interest rate on our senior notes with adjustable rates, the rates available on new debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. 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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Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under EQT's revolving credit facility and Eureka's revolving credit facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. EQT's revolving credit facility contains financial covenants that require us to have a total debt to total capitalization ratio no greater than 65%. As of December 31, 2024, we were in compliance with all EQT, Eureka and EQM debt provisions and covenants under our debt agreements.

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

Commodity Risk Management

The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of February 14, 2025. 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.

(a)January 1 through March 31.

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

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

Off-Balance Sheet Arrangements

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

Commitments and Contingencies

See Note 15 to the Consolidated Financial Statements for a discussion of our commitments and contingencies.

Recently Issued Accounting Standards

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

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Critical Accounting Estimates

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

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

Our estimates of proved reserves are reassessed annually using geological, reservoir and production performance data. Reserve estimates are prepared by our engineers and audited by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.

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

We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions. Based on proved reserves as of December 31, 2024, we estimate that a 1% change in proved reserves would decrease or increase 2025 depletion expense by approximately $10 million and $21 million, respectively, based on current production estimates for 2025.

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

Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our Consolidated Financial Statements or tax returns. See Note 1 to the Consolidated Financial Statements for a discussion of significant accounting policies related to income taxes and Note 9 to the Consolidated Financial Statements for a discussion of deferred tax assets, valuation allowances and the amount of financial statement benefit recorded for uncertain tax positions.

We believe income taxes is a "critical accounting estimate" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions. When evaluating whether or not a valuation allowance should be established, we exercise judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of our deferred tax assets will not be realized. To determine whether a valuation allowance is needed, we consider all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income. To determine the amount of financial statement benefit recorded for uncertain tax positions, we consider the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an income tax expense or benefit in our Statements of Consolidated Operations.

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Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid. Changes in our assumptions are sensitive to numerous factors; however, based on income before taxes for the years ended December 31, 2024, 2023 and 2022, we estimate that a 1% change in our effective tax rate would decrease or increase income tax expense by approximately $3 million, $21 million and $23 million, respectively.

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

We believe derivative instruments is a "critical accounting estimate" because our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.

Contingencies and Asset Retirement Obligations. We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies based on our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including historical experience and matter specifics. Estimates are developed in consultation with legal counsel and are based on an analysis of potential results. See Note 15 to the Consolidated Financial Statements.

We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. See Note 1 to the Consolidated Financial Statements.

We believe contingencies and asset retirement obligations is a "critical accounting estimate" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations. If the expected amount and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future periods. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

Business Combinations. Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value. In the third quarter of 2024, we completed the Equitrans Midstream Merger. See Note 6 to the Consolidated Financial Statements for a discussion of the most significant assumptions used to estimate the fair value of the assets acquired and liabilities assumed in the Equitrans Midstream Merger.

We believe business combinations is a "critical accounting estimate" because the valuation of acquired assets and assumed liabilities involves significant judgment about future events. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

Property, Plant and Equipment (Including Gas, NGLs and Oil Producing Properties). We use the successful efforts method of accounting for gas, NGLs and oil producing activities. See Note 1 to the Consolidated Financial Statements for a discussion of the fair value measurement and any impairment of our oil and gas properties and other property, plant and equipment as well as our evaluation of the recoverability of capitalized costs of unproved oil and gas properties.

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We believe the accounting for our property, plant and equipment, including our gas, NGLs and oil producing properties, is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, including future sales prices of natural gas and NGLs, future production costs, the amount of natural gas and NGLs recorded and timing of recoveries, as well as discount and inflation rates. In addition, evaluations of impairment of our other property, plant and equipment also involve significant judgement about future events, including assumptions about future cash flows, discount rates and operating levels. Significant changes in these estimates could result in the costs of our property, plant and equipment, including our proved and unproved properties, not being recoverable, which would require us to recognize impairment. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

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

Intangible Assets. Refer to Notes 1 and 6 to the Consolidated Financial Statements for a discussion of our intangible assets. We evaluate our intangible assets for impairment when indicators of impairment are present.

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

Investments in Unconsolidated Entities. Refer to Notes 1 and 11 to the Consolidated Financial Statements for a discussion of our investments in unconsolidated entities. We evaluate our investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the investment's fair value is less than its carrying value. The recognition of an impairment loss is required if the impairment is considered other than temporary.

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

Goodwill. Goodwill is evaluated for impairment annually as of October 1 or more frequently if indicators of impairment exist. A significant amount of judgement is involved in determining if an indicator of impairment has occurred. Such indicators may include, among others, deterioration in general economic conditions, negative developments in equity and credit markets, adverse changes in the market environments in which we operate, increases in operating costs or other factors that could have a negative effect on earnings and cash flows or a trend of negative or declining cash flows over multiple periods.

We test goodwill for impairment on a qualitative or quantitative basis. When performing a qualitative impairment test, we consider a number of factors in our assessment, such as: general economic conditions, performance equity and credit markets, industry and market conditions, market capitalization, earnings and cash flow trends. When performing a quantitative impairment test, we may use a combination of the income and market approach to estimate the fair value of our reporting units.

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

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

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

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

Consolidated Results of Operations

Net income attributable to EQT Corporation for 2023 was $1,735 million, $4.22 per diluted share, compared to $1,771 million, $4.38 per diluted share, for 2022. The decrease was attributable primarily to decreased sales of natural gas, NGLs and oil, partly offset by a gain on derivatives in 2023 compared to a loss on derivatives in 2022, impairment of the contract asset (discussed in Note 5 to the Consolidated Financial Statements) in 2022, decreased income tax expense and a loss on debt extinguishment in 2022.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2022, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2021.

Results of operations for the period beginning August 22, 2023 through December 31, 2023 include the results of our operation of assets acquired in the Tug Hill and XcL Midstream Acquisition. See Note 6 to the Consolidated Financial Statements for further discussion of the Tug Hill and XcL Midstream Acquisition.

See "Sales Volume and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.

Trends and Uncertainties

Our sales volume and operating expenses on a per Mcfe basis during the first half of 2023 were negatively impacted by fewer wells turned-in-line during 2022 compared to our 2022 planned development schedule due to third-party supply chain constraints. In addition, as a result of third-party supply chain constraints in 2022, we shifted the planned development of approximately 30 wells from 2022 to 2023 (the Rescheduled Wells). All of the Rescheduled Wells were completed and turned-to-sales as of July 2023, resulting in our third quarter 2023 sales volumes returning to our normalized level of production; however, our sales volume during the second half of 2023 was negatively impacted by approximately 13 Bcfe of curtailments (inclusive of non-operated wells in which we have a working interest) principally in response to lower natural gas prices in the Appalachian Basin. Future supply chain constraints or declines in natural gas prices may result in 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. 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 increased rapidly during 2022, and, although the inflation rate decreased through 2023, it still 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.

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While the prices for natural gas, NGLs and oil have historically been volatile, price volatility was especially pronounced during 2022, with natural gas prices peaking in August 2022, then steadily declining into the first half of 2023. The second half of 2023 saw moderate increases in natural gas prices; however, on average, prices in 2023 remained lower than in 2022. We expect commodity prices to be volatile throughout 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.

Additionally, after several years of delays, in the third quarter of 2023, Equitrans Midstream resumed forward construction of the Mountain Valley Pipeline following the approval of federal legislation ratifying and approving all permits and authorizations necessary for the construction and initial operation of the project. The fee structure and various conditions precedent specified in certain of our agreements with Equitrans Midstream, including but not limited to the Consolidated GGA, are tied to the date on which the Mountain Valley Pipeline is placed in service. As a result, the timing of the date on which the Mountain Valley Pipeline is ultimately placed in service, which is outside of our control, could impact our operating results during 2024, including our operating expenses and per unit metrics, average differential and any payments required to settle the Henry Hub Cash Bonus (defined and described in Note 3 to the Consolidated Financial Statements), if required.

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 adjusted operating revenues, a non-GAAP supplemental financial measure. Adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues should not be considered as an alternative to total operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of adjusted operating revenues with total operating revenues, the most directly comparable financial measure calculated in accordance with GAAP.

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

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

(c)Total natural gas and liquids sales, including cash settled derivatives, is also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.

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Non-GAAP Financial Measures Reconciliation

The table below reconciles adjusted operating revenues, a non-GAAP supplemental financial measure, with total operating revenues, its most directly comparable financial measure calculated in accordance with GAAP. 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. Adjusted operating revenues excludes the revenue impacts of changes in the fair value of derivative instruments prior to settlement and net marketing services and other. We use adjusted operating revenues to evaluate earnings trends because, as a result of the measure's exclusion of the often-volatile changes in the fair value of derivative instruments prior to settlement, the measure reflects only the impact of settled derivative contracts. Net marketing services and other consists of the costs of, and recoveries on, pipeline capacity releases, revenues for gathering and processing services provided to third parties and other revenues. Because we consider net marketing services and other to be unrelated to our natural gas and liquids production activities, adjusted operating revenues excludes net marketing services and other. We believe that adjusted operating revenues provides useful information to investors for evaluating period-to-period comparisons of earnings trends.

Sales Volume and Revenues

Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for 2023 compared to 2022 due to lower average realized price, partly offset by increased sales volume.

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Average realized price decreased for 2023 compared to 2022 due to lower NYMEX and liquids prices, partly offset by favorable cash settled derivatives and favorable differential. The following table presents the composition of net cash settlements that we received (paid) on derivatives.

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

For 2023 and 2022, we paid premiums for derivatives that settled during the period of $322.9 million and $27.6 million, respectively.

Sales volume increased for 2023 compared to 2022 due to sales volume increases of 90 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition, partly offset by sales volume decreases from the natural decline of producing wells and fewer wells turned-in-line during 2022 as a result of third-party supply chain constraints and delays in the development schedule of certain non-operated wells in which we have a working interest.

Gain (loss) on derivatives. For 2023, we recognized a gain on derivatives of $1,838.9 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 the derivative liability related to the Henry Hub Cash Bonus. For 2022, we recognized a loss on derivatives of $4,642.9 million related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices, partly offset by a gain on the derivative liability related to the Henry Hub Cash Bonus.

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Operating Expenses

Gathering. Gathering expense decreased on an absolute basis for 2023 compared to 2022 due primarily to lower gathering rates on certain contracts indexed to price. Gathering expense decreased on a per Mcfe basis for 2023 compared to 2022 due primarily to lower gathering rates on certain contracts indexed to price, which decreased in 2023, as well as the impact of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition, which are wholly owned by us and, therefore, reduce our gathering cost structure.

Transmission. Transmission expense increased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to additional capacity acquired, partly offset by increased credits received from the Texas Eastern Transmission Pipeline.

Processing. Processing expense increased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to processing expenses for the liquids-rich assets acquired in the Tug Hill and XcL Midstream Acquisition as well as inflation of third-party-contracted processing rates.

LOE. LOE increased on an absolute basis for 2023 compared to 2022 due primarily to increased LOE from the assets acquired in the Tug Hill and XcL Midstream Acquisition, partly offset by lower saltwater disposal costs and increased recycling. Saltwater disposal costs and recycle rates were favorably impacted by increased use of our internally developed produced water gathering and storage system, which was placed in service during the fourth quarter of 2022.

Production taxes. Production taxes decreased on an absolute and per Mcfe basis for 2023 compared to 2022 due to lower West Virginia severance taxes due to lower TETCO M2 price and lower Pennsylvania impact fees due to lower NYMEX price, partly offset by higher West Virginia property taxes due to assets acquired in the Tug Hill and XcL Midstream Acquisition and higher rates.

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Selling, general and administrative. Selling, general and administrative expense decreased on an absolute and per Mcfe basis for 2023 compared to 2022 due primarily to lower long-term incentive compensation costs as a result of decreases in awards outstanding and changes in the fair value of awards. Long-term incentive compensation may fluctuate with changes in our stock price and performance conditions.

Depreciation and depletion. Production depletion expense increased on an absolute basis for 2023 compared to 2022 due to increased sales volume, partly offset by a lower annual depletion rate.

Loss (gain) on sale/exchange of long-lived assets. During 2023, we recognized a loss on sale/exchange of long-lived assets of $17.4 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.

Impairment of contract asset. During 2022, we recognized impairment of our contract asset of $214.2 million. See Note 5 to the Consolidated Financial Statements.

Impairment and expiration of leases. During 2023 and 2022, we recognized impairment and expiration of leases of $109.4 million and $176.6 million, respectively, related primarily 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 2023 compared to 2022 due primarily to transaction costs associated with the Tug Hill and XcL Midstream Acquisition, partly offset by decreased legal and environmental reserves, including from settlements. See Note 1 to the Consolidated Financial Statements for a summary of other operating expenses.

Other Income Statement Items

(Income) loss from investments. The change in (income) loss from investments was due primarily to a loss on our sale of our investment in Equitrans Midstream in 2022, partly offset by lower equity earnings recognized on our investment in LMM (defined in Note 1 to the Consolidated Financial Statements).

Dividend and other income. Dividend and other income decreased for 2023 compared to 2022 due primarily to lower dividends received on our investment in the Investment Fund (defined in Note 1 to the Consolidated Financial Statements) as well as dividends received on our investment in Equitrans Midstream in 2022.

Loss on debt extinguishment. During 2022, we recognized a loss on debt extinguishment of $140.0 million due to our repayment and repurchase of debt, including our 3.00% notes due October 1, 2022.

Interest expense, net. Interest expense decreased for 2023 compared to 2022 due primarily to higher interest income earned on cash on hand and lower interest expense on lower revolving credit facility borrowings, partly offset by higher interest expense on debt as a result of the August 2023 draw down of the Term Loan Facility (defined and discussed in Note 8 to the Consolidated Financial Statements) and October 2022 senior notes issuances. The higher interest expense on debt was partly offset by our repayment and repurchase of debt disclosed in Note 8 to the Consolidated Financial Statements.

Income tax expense (benefit). See Note 7 to the Consolidated Financial Statements.

See "Critical Accounting Estimates" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties. See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."

Capital Resources and Liquidity

Although we cannot provide any assurance, we believe cash flows from operating activities and availability under our 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.

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Revolving Credit Facility

We primarily use borrowings under our revolving credit facility to fund working capital needs, timing differences between capital expenditures and other cash uses and cash flows from operating activities, margin deposit requirements on our derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. See Note 8 to the Consolidated Financial Statements for further discussion of our revolving credit facility.

Known Contractual and Other Obligations; Planned Capital Expenditures

Purchase Obligations. We have commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines, some of which extend up to 20 years or longer. We have entered into agreements to release some of our capacity under these long-term contracts, subject to certain conditions that are currently unsatisfied. We also have commitments for processing capacity in order to extract heavier liquid hydrocarbons from the natural gas stream. In addition, we have commitments to pay for services and materials related to our operations, which primarily include minimum volume commitments to obtain water services and electric hydraulic fracturing services and commitments to purchase equipment, materials and sand. See Note 11 to the Consolidated Financial Statements for further discussion, including details regarding aggregate future payments for these items.

Contractual Commitments. We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 8 to the Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments.

Unrecognized Tax Benefits. As discussed further in Note 7 to the Consolidated Financial Statements, as of December 31, 2023, we had a total reserve for unrecognized tax benefits of $8.5 million and an additional reserve of $77.0 million that was offset against deferred tax assets for general business tax credit carryforwards and net operating losses (NOLs). We settled our consolidated U.S. federal income tax liability with the IRS through 2017 in January of 2023. We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities.

Planned Capital Expenditures and Sales Volume. In 2024, we expect to spend approximately $2.15 billion to $2.35 billion in total capital expenditures. We expect to fund our capital expenditures with cash generated from operations and, if required, borrowings under our 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 2024, we expect our sales volume to be 2,200 Bcfe to 2,300 Bcfe.

Operating Activities

Net cash provided by operating activities was $3,179 million and $3,466 million for 2023 and 2022, respectively. The decrease in 2023 compared to 2022 was due primarily to lower cash operating revenues, partly offset by net cash settlements received on derivatives in 2023 compared to net cash settlements paid on derivatives in 2022, favorable changes in working capital driven by declining accounts receivable and lower margin postings.

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

Investing Activities

Net cash used in investing activities was $4,314 million and $1,422 million for 2023 and 2022, respectively. The increase in 2023 compared to 2022 was attributable primarily to cash paid for the Tug Hill and XcL Midstream Acquisition in 2023 and increased capital expenditures.

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The following table summarizes our capital expenditures.

(a)Includes capital expenditures for water infrastructure of $35.9 million and $44.5 million for 2023 and 2022, respectively.

(b)Capital expenditures attributable to noncontrolling interests were $8.5 million and $12.8 million for 2023 and 2022, respectively.

(c)Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures and capitalized share-based compensation costs. The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual.

Financing Activities

Net cash used in financing activities was $243 million and $699 million for 2023 and 2022, respectively. For 2023, the primary uses of financing cash flows were repayment and retirement of debt, payment of dividends and repurchase and retirement of EQT Corporation common stock, and the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings. For 2022, the primary uses of financing cash flows were repayment and retirement of debt, repurchase and retirement of EQT Corporation common stock and payment of dividends, and the primary source of financing cash flows was proceeds from the issuance of debt.

See Note 8 to the Consolidated Financial Statements for further discussion of our debt and borrowings under our revolving credit facility and the Term Loan Facility, including discussion of events that occurred subsequent to December 31, 2023.

On February 8, 2024, our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT Corporation common stock, payable on March 1, 2024, to shareholders of record at the close of business on February 20, 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 8 to the Consolidated Financial Statements for discussion of redemptions and repurchases of debt and Note 9 to the Consolidated Financial Statements for discussion of repurchases of EQT Corporation common stock.

Security Ratings and Financing Triggers

The table below reflects the credit ratings and rating outlooks assigned to our debt instruments as of December 31, 2023. 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 independent 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 3 to the Consolidated Financial Statements for a description of what is deemed investment grade.

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Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our revolving credit facility, the interest rate on the Term Loan Facility and 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. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties.

Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under our 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. Our 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 December 31, 2023, we were in compliance with all debt provisions and covenants under our debt agreements.

See Note 8 to the Consolidated Financial Statements for a discussion of borrowings under our 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 February 9, 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.

(a)January 1 through March 31.

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

See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 3 to the Consolidated Financial Statements for further discussion of our hedging program.

Off-Balance Sheet Arrangements

As of December 31, 2023, we did not have any material off-balance sheet arrangements other than the commitments described in Note 11 to the Consolidated Financial Statements.

Commitments and Contingencies

See Note 11 to the Consolidated Financial Statements for a discussion of our commitments and contingencies.

Recently Issued Accounting Standards

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

Critical Accounting Estimates

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

Accounting for Gas, NGLs and Oil Producing Activities. We use the successful efforts method of accounting for our oil and gas producing activities. See Note 1 to the Consolidated Financial Statements for a discussion of the fair value measurement and any subsequent impairments of our proved and unproved oil and gas properties and other long-lived assets as well as evaluation of the recoverability of capitalized costs of unproved oil and gas properties.

We believe accounting for natural gas, NGLs and oil producing activities is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, such as future sales prices of natural gas and NGLs and future production costs, as well as the amount of natural gas and NGLs recorded and timing of recoveries. Significant changes in these estimates could result in the costs of our proved and unproved properties not being recoverable; therefore, we would be required to recognize impairment. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

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

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

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Our estimates of proved reserves are reassessed annually using geological, reservoir and production performance data. Reserve estimates are prepared by our engineers and audited by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.

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

We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions. Based on proved reserves as of December 31, 2023, we estimate that a 1% change in proved reserves would decrease or increase 2024 depletion expense by approximately $15 million and $27 million, respectively, based on current production estimates for 2024.

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

Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our Consolidated Financial Statements or tax returns. See Note 1 to the Consolidated Financial Statements for a discussion of significant accounting policies related to income taxes and Note 7 to the Consolidated Financial Statements for a discussion of deferred tax assets, valuation allowances and the amount of financial statement benefit recorded for uncertain tax positions.

We believe income taxes are "critical accounting estimates" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an expense or benefit in income tax expense in our Statements of Consolidated Operations. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

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

We believe derivative instruments are "critical accounting estimates" because our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.

Business Combinations. Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value. In the third quarter of 2023, we completed the Tug Hill and XcL Midstream Acquisition, and in the third quarter of 2021, we completed the Alta Acquisition (defined and discussed in Note 6 to the Consolidated Financial Statements). See Note 6 to the Consolidated Financial Statements for a discussion of the most significant assumptions used to estimate the fair value of the assets acquired and liabilities assumed.

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We believe business combinations are "critical accounting estimates" because the valuation of acquired assets and assumed liabilities involves significant judgment about future events. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

Contingencies and Asset Retirement Obligations. We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies based on our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including historical experience and matter specifics. Estimates are developed in consultation with legal counsel and are based on an analysis of potential results. See Note 11 to the Consolidated Financial Statements.

We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. See Note 1 to the Consolidated Financial Statements.

We believe contingencies and asset retirement obligations are "critical accounting estimates" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations. If the expected amount and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future periods. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.

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

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

Consolidated Results of Operations

Net income attributable to EQT Corporation for 2022 was $1,771 million, $4.38 per diluted share, compared to net loss attributable to EQT Corporation for 2021 of $1,143 million, $3.54 per diluted share. The change was attributable primarily to increased sales of natural gas, NGLs and oil, partly offset by income tax expense, greater loss on derivatives, the impairment of our contract asset (discussed in Note 5 to the Consolidated Financial Statements), increased transportation and processing expense and increased loss on debt extinguishment.

Net loss attributable to EQT Corporation for 2021 was $1,143 million, $3.54 per diluted share, compared to net loss attributable to EQT Corporation for 2020 of $959 million, $3.68 per diluted share. The change was attributable primarily to the loss on derivatives, increased depreciation and depletion, increased transportation and processing and the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements) recognized in 2020, partly offset by increased sales of natural gas, NGLs and oil, the income from investments, higher income tax benefit and the gain on sale/exchange of long-lived assets.

Results of operations for 2022 and for the period beginning July 21, 2021 and ending December 31, 2021 include the results of our operation of assets acquired in the Alta Acquisition. See Note 6 to the Consolidated Financial Statements for further discussion.

See "Sales Volume and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures.

Trends and Uncertainties

Our sales volume and operating expenses for 2022 were negatively impacted by fewer wells turned-in-line and adjustments to our planned development schedule as a result of third-party supply chain constraints. Strong underlying well performance and field optimization helped mitigate the impacts to 2022 sales volume; however, supply chain constraints may continue to impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

The annual inflation rate in the United States was particularly high during 2022, and many analysts anticipate inflation will remain elevated through 2023. Inflationary pressures have multiple impacts on our business, including increasing our operating expenses and our cost of capital. Furthermore, 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.

Additionally, while the prices for natural gas, NGLs and oil have historically been volatile, price volatility was especially pronounced during 2022. The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu between the period from January 1, 2022 through December 31, 2022, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $123.64 per barrel to a low of $71.05 per barrel during the same period. We expect commodity price volatility to continue or increase throughout 2023 due to rising macroeconomic uncertainty and geopolitical tensions, including the Russian invasion of Ukraine, which began in February 2022 and has put upward pressure on natural gas and oil prices. Our revenue, profitability, rate of growth, 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.

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 adjusted operating

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revenues, a non-GAAP supplemental financial measure. Adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues should not be considered as an alternative to total operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of adjusted operating revenues with total operating revenues, the most directly comparable financial measure calculated in accordance with GAAP.

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

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

(c)Total natural gas and liquids sales, including cash settled derivatives, is also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.

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Non-GAAP Financial Measures Reconciliation

The table below reconciles adjusted operating revenues, a non-GAAP supplemental financial measure, with total operating revenues, its most directly comparable financial measure calculated in accordance with GAAP. 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. Adjusted operating revenues excludes the revenue impacts of changes in the fair value of derivative instruments prior to settlement and net marketing services and other. We use adjusted operating revenues to evaluate earnings trends because, as a result of the measure's exclusion of the often-volatile changes in the fair value of derivative instruments prior to settlement, the measure reflects only the impact of settled derivative contracts. Net marketing services and other consists of the costs of, and recoveries on, pipeline capacity releases, revenues for gathering services provided to third parties and other revenues. Because we consider net marketing services and other to be unrelated to our natural gas and liquids production activities, adjusted operating revenues excludes net marketing services and other. We believe that adjusted operating revenues provides useful information to investors for evaluating period-to-period comparisons of earnings trends.

Sales Volume and Revenues

Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil increased for 2022 compared to 2021 due to a higher average realized price and increased sales volume.

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Average realized price for 2022 compared to 2021 increased due to higher NYMEX prices and higher liquids prices, partly offset by unfavorable cash settled derivatives and unfavorable differential. For 2022 and 2021, we paid $5,927.7 million and $2,091.0 million, respectively, of net cash settlements on derivatives, which are included in average realized price but may not be included in operating revenues.

Sales volume increased primarily as a result of sales volume increases from the assets acquired in the Alta Acquisition, partly offset by natural decline of producing wells and fewer wells turned-in-line. Sales volume for 2022 was negatively impacted by fewer wells turned-in-line as a result of third-party supply chain constraints. Supply chain constraints and inflationary pressures may continue to impact our future operating revenues. The assets which we intend to acquire in the pending Tug Hill and XcL Midstream Acquisition, which is subject to regulatory approvals, are currently producing approximately 800 MMcfe per day of sales volume, 20% of which is liquids sales volume.

Loss on derivatives. For 2022 and 2021, we recognized a loss on derivatives of $4,642.9 million and $3,775.0 million, respectively, related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices.

Net marketing services and other. Net marketing services and other decreased for 2022 compared to 2021 due primarily to a decrease in the liquids uplift realized on gas purchased at the wellhead from other operators, partly offset by an increase in third-party gathering revenues recognized on the midstream assets acquired in the Alta Acquisition.

Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil increased for 2021 compared to 2020 due to increased sales volume and a higher average realized price.

Sales volume increased primarily as a result of sales volume increases of 170 Bcfe from the assets acquired in the Alta Acquisition, sales volume increases of 127 Bcfe from the assets acquired in the Chevron Acquisition (defined in Note 6 to the Consolidated Financial Statements), prior year sales volume decreases of 46 Bcfe from the 2020 Strategic Production Curtailments and sales volume increases as a result of the Reliance Asset Acquisition (defined in Note 6 to the Consolidated Financial Statements) and from wells turned in-line during 2021, partly offset by sales volume decreases of 9 Bcfe from the 2020 Divestiture (defined in Note 8 to the Consolidated Financial Statements).

The 2020 Strategic Production Curtailments refers to our strategic decisions to temporarily curtail certain 2020 production. In May 2020, we temporarily curtailed approximately 1.4 Bcf per day of gross production, equivalent to approximately 1.0 Bcf per day of net production. In July 2020, we began a moderated approach to bring back on-line the curtailed production. In September 2020, we curtailed approximately 0.6 Bcf per day of gross production, equivalent to approximately 0.4 Bcf per day of net production. In October 2020, we began a phased approach to bring back on-line the curtailed production, which was completed in November 2020.

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Average realized price increased due to higher NYMEX prices and higher liquids prices, partly offset by lower cash settled derivatives and unfavorable differential. For 2021 and 2020, we paid $2,091.0 million and received $897.2 million, respectively, of net cash settlements on derivatives, which are included in average realized price but may not be included in operating revenues.

(Loss) gain on derivatives. For 2021 and 2020, we recognized a loss of $3,775.0 million and a gain of $400.2 million, respectively, on derivatives. The loss for 2021 was related primarily to decreases in the fair market value of our NYMEX swaps and options due to increases in NYMEX forward prices. The gain for 2020 was related primarily to increases in the fair market value of our NYMEX swaps and options due to decreases in NYMEX forward prices.

Net marketing services and other. Net marketing services and other increased for 2021 compared to 2020 due primarily to the liquids uplift realized on gas purchased at the wellhead from other operators and third-party gathering revenues recognized on the midstream assets acquired in the Alta Acquisition.

Operating Expenses

Gathering. Gathering expense increased on an absolute basis for 2022 compared to 2021 due primarily to increased sales volume from the assets acquired in the Alta Acquisition and higher gathering rates on certain contracts indexed to price, partly offset by lower expense as a result of less utilization of lower overrun rates as part of the Consolidated GGA (defined and discussed in Note 5 to the Consolidated Financial Statements) due to the natural decline of producing wells and fewer wells turned-in-line. Gathering expense increased on a per Mcfe basis for 2022 compared to 2021 due primarily to higher gathering rates on certain contracts indexed to price and less utilization of lower overrun rates as part of the Consolidated GGA due to the natural decline of producing wells and fewer wells turned-in-line, partly offset by the lower gathering rate structure on the assets acquired in the Alta Acquisition.

Transmission. Transmission expense increased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to higher rates on and lower credits received from the Texas Eastern Transmission Pipeline, additional capacity acquired in the Alta Acquisition and additional capacity acquired on the Rockies Express Pipeline in September 2021.

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Processing. Processing expense increased on an absolute basis for 2022 compared to 2021 due to increased volumes that require processing as a result of increased development of liquids-rich areas.

LOE. LOE increased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to additional lease operating costs as a result of the Alta Acquisition and higher salt water disposal costs.

Production taxes. Production taxes increased on an absolute and per Mcfe basis for 2022 compared to 2021 due to increased West Virginia severance taxes, which resulted primarily from higher prices, and increased Pennsylvania impact fees, which resulted from additional wells spud in 2022, including those acquired in the Alta Acquisition, higher prices and inflation.

Exploration. Exploration expense decreased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to our purchase of seismic data in 2021 following the completion of the Alta Acquisition.

Selling, general and administrative. Selling, general and administrative expense increased on an absolute and per Mcfe basis for 2022 compared to 2021 due primarily to higher long-term incentive compensation costs as a result of changes in the fair value of awards and increased labor costs driven by an increase in the number of our total permanent employees. Long-term incentive compensation may fluctuate with changes in our stock price and performance conditions.

Depreciation and depletion. Production depletion expense decreased on an absolute and per Mcfe basis for 2022 compared to 2021 due to a lower annual depletion rate.

(Gain) loss/impairment on sale/exchange of long-lived assets. During 2022 and 2021, we recognized a gain on sale/exchange of long-lived assets of $8.4 million and $21.1 million, respectively, related primarily to changes in the fair value of the Contingent Consideration (defined and discussed in Note 8 to the Consolidated Financial Statements) from the 2020 Divestiture.

Impairment of contract and other assets. During 2022, we recognized impairment of our contract asset of $214.2 million as discussed in Note 5 to the Consolidated Financial Statements.

Impairment and expiration of leases. During 2022 and 2021, we recognized impairment and expiration of leases of $176.6 million and $311.8 million, respectively, related to impairment and expiration of leases that we no longer expect to develop based on our development plan.

Other operating expenses. Other operating expenses for 2022 of $57.3 million were attributable primarily to changes in legal and environmental reserves including settlements as well as transaction costs associated with the Tug Hill and XcL Midstream Acquisition. Other operating expenses for 2021 of $70.1 million were attributable primarily to transaction costs associated with the Alta Acquisition and Chevron Acquisition. See Note 1 to the Consolidated Financial Statements for a summary of other operating expenses.

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