EQT (EQT) 10-K risk factor changes: FY2022 vs FY2021

- delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from permitting, wastewater disposal, [removed: discharge] [added: emission] of GHGs, and limitations on hydraulic fracturing;

- supply chain disruptions or labor shortage [removed: impacts related to] [added: impacts, including as a result of] the COVID-19 pandemic or other global pandemics;

Our business is subject to all of the inherent hazards and risks normally incidental to drilling for, producing, transporting and storing natural gas, NGLs and oil, such as fires, explosions, slips, landslides, blowouts, and well cratering; pipe and other equipment and system failures; delays imposed by, or resulting from, compliance with regulatory requirements; formations with abnormal or unexpected pressures; shortages of, or delays in, obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; adverse weather conditions, such as freeze offs of wells and pipelines due to cold weather; issues related to compliance with environmental regulations; environmental hazards, such as natural gas leaks, oil and diesel spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of brine, well stimulation and completion fluids, [added: wastewater,] toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater; inadvertent third-party damage to our [removed: assets,] [added: assets;] and natural disasters.

[removed: We also face various] risks or threats to the operation and security of our or third parties' facilities and infrastructure, such as processing plants, compressor stations and pipelines.

Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil [removed: prices,] [added: prices;] the availability and cost of [removed: capital,] [added: capital;] drilling and production [removed: costs,] [added: costs;] the availability of drilling services and [removed: equipment,] [added: equipment;] drilling [removed: results,] [added: results;] lease [removed: expirations, topography,] [added: expirations; topography;] gathering system and pipeline transportation costs and [removed: constraints,] [added: constraints;] access to and availability of [added: sand and] water [added: and corresponding materials] sourcing and distribution systems, [added: including railroads;] coordination with coal [removed: mining,] [added: mining;] regulatory [removed: approvals] [added: approvals;] and other factors.

In addition, [removed: unless] [added: if] production is [added: not] established within the spacing units covering [removed: the] [added: our] undeveloped acres [removed: on which some of] [added: in accordance with] the [removed: potential locations are obtained,] [added: requisite timeframe set forth in the applicable lease,] our leases for such acreage will expire.

Approximately [removed: 10%] [added: 6%] of our net undeveloped acres are subject to leases that could expire over the next three years.

[removed: The likelihood of an impairment of unproved oil and gas properties increases as the] expiration of a lease term approaches and drilling activity has not commenced.

For the years ended December 31, [removed: 2021, 2020] [added: 2022, 2021] and [removed: 2019,] [added: 2020,] we recorded impairment and expiration of leases of [removed: $311.8] [added: $176.6] million, [removed: $306.7] [added: $311.8] million and [removed: $556.4] [added: $306.7] million, respectively.

Our inability to cure any title defects in our leases in a timely and cost-efficient manner may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase [added: our] production and reserves.

Additionally, a failure to effectively and efficiently operate existing wells may cause [added: our] production volume to fall short of our projections.

Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs, equipment, a qualified work force, and adequate capacity for the treatment and recycling or disposal of [removed: waste water] [added: wastewater] generated in our operations, as well as weather conditions, natural gas, NGLs and oil price volatility, regulatory approvals, title and property access problems, geology, equipment failure or accidents and other factors.

Drilling for natural gas and oil can be unprofitable, not only [removed: from] [added: due to] dry wells, but [removed: from] [added: also as a result of] productive wells that perform below expectations or that do not produce sufficient revenues to return a profit.

[removed: Future] [added: Our future] natural gas, NGLs and oil production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable.

Actual future net cash flows from our [removed: properties] [added: reserves] will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the [removed: amount, timing and cost of actual production and changes in governmental regulations or taxation.]

Key assumptions used in our [removed: analyses,] [added: analyses] include, among other things, the intended use of the asset, the anticipated production from reserves, future market prices for natural gas, NGLs and oil, future operating [added: and development] costs, inflation and the anticipated proceeds that may be received upon divestiture if there is a possibility that the asset will be divested prior to the end of its useful life.

The prices for natural gas, NGLs and oil have historically been [removed: volatile,] [added: volatile] and [removed: we expect this volatility to continue] [added: have been particularly volatile] in [removed: the future.][added: recent years.]

[removed: The] [added: Commodity] prices are affected by a number of factors beyond our control, which include:

- prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity [removed: prices;][added: prices (the market price for natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub as a result of the increased production and supply of natural gas in the Northeast United States);]

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of [removed: $23.86] [added: $9.85] per MMBtu to a low of [removed: $2.43] [added: $3.46] per MMBtu [added: between the period] from January 1, [removed: 2021] [added: 2022] through December 31, [removed: 2021,] [added: 2022,] and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of [removed: $85.64] [added: $123.64] per barrel to a low of [removed: $47.47] [added: $71.05] per barrel during the same period.

However, due to the volatility of commodity prices and the multitude of external factors that impact commodity prices, many of which are unknown and unforeseeable, [removed: such as reduced demand as a result of a general economic slowdown related to the COVID-19 pandemic or other global pandemics,] we are unable to predict with certainty future potential movements in the market prices for natural gas, NGLs and oil.

[removed: Accordingly, the] [added: The] success of our plans and strategies could be negatively affected if our projections of future hydrocarbon prices are significantly different from the ultimate actual price.

Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash [removed: flows] [added: flows, financial projections,] and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices.

[removed: In addition, to the] extent we have hedged our current production at prices below the current market price, we will not benefit fully from an increase in the price of natural gas.

In December 2021, we [removed: reaffirmed our commitment to attaining investment grade credit metrics and] outlined a leverage and debt [removed: reduction] [added: retirement] strategy with the goal of [removed: reducing] [added: retiring a significant amount of] our total debt by [removed: $1.5 billion by] the end of 2023 (our Debt [removed: Reduction] [added: Retirement] Plan).

We intend to fund our Debt [removed: Reduction] [added: Retirement] Plan through free cash flow, and have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, which we anticipate will enable us to execute on our Debt [removed: Reduction] [added: Retirement] Plan and other capital allocation strategies; however, there can be no assurance that we will be able to generate sufficient free cash flow to execute our Debt [removed: Reduction] [added: Retirement] Plan on our anticipated timeframe, if at all.

If we are not able to successfully execute our Debt [removed: Reduction] [added: Retirement] Plan or otherwise reduce our total debt to a level we believe appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise [removed: or delay] our shareholder returns strategy or other strategic plans.

The issuance of additional indebtedness would require that a portion of our cash flows from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital [removed: expenditures] [added: expenditures, shareholder returns initiatives] and acquisitions.

As of December 31, [removed: 2021,] [added: 2022,] our senior notes were rated "Ba1" with a [removed: "stable"] [added: "positive"] outlook by Moody's Investors Services (Moody's), [removed: "BB+"] [added: "BBB-"] with a [removed: "positive"] [added: "stable"] outlook by Standard & Poor's Ratings Service (S&P) and [removed: "BB+"] [added: "BBB-"] with a "stable" outlook by Fitch Ratings Service (Fitch).

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 lines of credit, the interest rate on [removed: the Adjustable Rate Notes] [added: our Term Loan Facility] (defined in Note 10 to the Consolidated Financial [removed: Statements),] [added: Statements) 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.

As of December 31, [removed: 2021,] [added: 2022,] we had approximately [removed: $5.5] [added: $5.7] billion of debt outstanding, and we may incur additional indebtedness in the future.

Our debt agreements also require [removed: compliance] [added: us to comply] with certain covenants.

These transactions limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge, and we may be required to post cash collateral or letters of credit with [removed: our hedge counterparties to the extent our liability under the derivative contract exceeds specified thresholds, which would negatively impact our liquidity.]

We have previously sustained losses as a result of certain of our derivative arrangements (including a [added: $4.6 billion loss in 2022 and a] $3.8 billion loss in 2021), and we cannot assure you that we will not do so in the future.

We have allocated a substantial portion of our financial, human capital and other resources to pursuing this strategy, including investing in new technologies and equipment, restructuring our workforce, and pursuing various ESG and [removed: new venture] [added: energy transition] initiatives geared towards enhancing our strategy.

Cyber incidents targeting our digital work environment or other technologies or [removed: natural gas and oil industry systems and] [added: energy] infrastructure may adversely impact our operations.

Our business and the natural gas [removed: and oil] industry in general have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, and the maintenance of our financial and other records has long been dependent upon such technologies.

The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber [added: or other] security [added: or physical threats, and the continuing armed conflict between Russia and Ukraine and associated economic sanctions on Russia may have increased the likelihood of such] threats.

Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to [removed: modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.]

In addition, [removed: at current commodity prices,] [added: due to regulatory and economic constraints,] construction of new pipelines and building of such infrastructure may occur more slowly.

We also face various

A terrorist attack or armed conflict targeting our systems or natural gas infrastructure generally could materially adversely impact our operations.

Growing geopolitical instability and armed conflicts (including the armed conflict between Russia and Ukraine) has resulted in energy infrastructure becoming a more prominent target of attack by terrorists and conflicting countries.

Natural gas, NGLs and oil related facilities, including those operated by us or our service providers, could be direct targets of physical or cyber attacks, and, if infrastructure integral to our operations is destroyed or damaged, we may experience a significant disruption in our operations.

Any such disruption could materially adversely affect our financial condition, results of operations and cash flows.

Costs for insurance and other security may increase as a result of increased threats, and certain insurance coverage may become more difficult to obtain, if available at all.

The likelihood of an impairment of unproved oil and gas properties increases as the

amount, timing and cost of actual production and changes in governmental regulations or taxation.

See "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our accounting policies and significant assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

We expect commodity price volatility to continue or increase in the future 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.

- national and worldwide economic and political conditions, particularly those in, or affecting, other countries which are significant producers of natural gas and/or oil;

Reduced cash flows could also result in us having to make downward adjustments to our financial projections, such as free cash flow, and could cause us to revise our shareholder returns initiatives, including the amount of dividends paid on our common stock, which could negatively impact the price of our common stock and our ability to access the capital markets.

See "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our accounting policies and significant assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

In addition, to the

A financial crisis or deterioration in general economic, business or geopolitical conditions could materially adversely affect our operations and financial condition.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues (including continued hostilities between Russia and Ukraine), inflation and U.S. Federal Reserve interest rate increases in response thereto, the availability and cost of credit, and slowing of economic growth in the United States and abroad and fears of a recession have contributed and may continue to contribute to increased economic uncertainty and diminished expectations for the global economy.

Global economic conditions, geopolitical issues and inflation have constrained global and domestic supply chains, which has impacted and could in the future continue to impact our ability to develop our reserves in accordance with our drilling and completions schedule.

Additionally, global economic conditions have a significant impact on commodity prices and any stagnation or deterioration in global economic conditions could result in decreased demand and, thus, lower prices for natural gas, NGLs or oil.

Such uncertainty could also result in higher natural gas, NGL and oil prices, which could potentially result in increased inflation worldwide and could negatively impact demand for natural gas, NGLs and oil.

our hedge counterparties to the extent our liability under the derivative contract exceeds specified thresholds, which would negatively impact our liquidity.

modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Because these

Most recently, at COP27, President Biden announced the EPA’s proposed standards to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.

Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement.

On November 11, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.

Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to identify large emissions events, referred to in the proposed rule as “super emitters.” The EPA is expected to issue a final rule by May 2023.

In November 2021, Congress approved a $1 trillion legislative infrastructure package which includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events, and clean energy and transportation investments.

The Inflation Reduction Act also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change, including imposing a fee on a facility’s methane emissions in excess of a specified threshold.

Pennsylvania became a member of RGGI in April 2022, though its membership is currently the subject of legal challenges.

If any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our exploration and production operations.

Most recently, on August 16, 2022, legislation commonly known as the Inflation Reduction Act was signed into law.

Among other things, the Inflation Reduction Act includes a 1% excise tax on corporate stock repurchases, applicable to repurchases made after December 31, 2022, and also a new minimum tax based on book income.

We are in the process of evaluating the potential impacts of the Inflation Reduction Act to us.

While we do not currently expect the Inflation Reduction Act to have a material impact on our financial statements, our analysis of the effect of the Inflation Reduction Act on us is ongoing and incomplete, and it is possible that the Inflation Reduction Act (or implementing regulations and other guidance) could adversely impact our current and deferred federal tax liability.

Additionally, state and local taxing authorities in

conduct, our development programs.

The EPA is undergoing a rulemaking process to redefine the definition of WOTUS which could be impacted by the U.S. Supreme Court's pending decision in *Sackett v.

EPA,* a case regarding the proper test in determining whether wetlands qualify as WOTUS.

A final rule, known as "Rule 1" was announced by the EPA and the Corps in December 2022.

The EPA and the Corps are expected to propose a second rule, known as "Rule 2," further refining Rule 1 by November 2023 and issue a final rule by July 2024.

See "Impairment of Oil and Gas Properties" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

- national and worldwide economic and political conditions;

In addition, the market price for natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub as a result of the increased production and supply of natural gas in the Northeast United States.

The accounting for the Convertible Notes may have a material effect on our reported financial results.

On April 28, 2020, we issued the Convertible Notes (defined in Note 10 to the Consolidated Financial Statements) due May 1, 2026 unless earlier redeemed, repurchased or converted.

In accordance with GAAP, an issuer must separately account for the liability and equity components of certain convertible debt instruments that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer's economic interest cost.

The effect on the accounting for the Convertible Notes is that the equity component is required to be included in additional paid-in capital of shareholders' equity on our Consolidated Balance Sheet, and the value of the equity component is treated as a debt discount for purposes of accounting for the debt component of the Convertible Notes.

Accordingly, we will be required to record a greater amount of non-cash interest expense in current and future periods as a result of the amortization of the discounted carrying value of the Convertible Notes to their face amount over the term of the Convertible Notes.

We will report lower net income (or greater net loss) in our financial results because GAAP requires interest to include both the current period's amortization of the debt discount and the instrument's coupon interest, which could adversely affect our reported or future financial results, the market price of our common stock and the trading price of the Convertible Notes.

In addition, because we have the ability and intent to settle the Convertible Notes, upon conversion, by paying or delivering cash equal to the principal amount of the obligation and common stock for amounts over the principal amount, the shares issuable upon conversion of the Convertible Notes are accounted for using the treasury stock method and, as such, are not included in the calculation of diluted earnings per share except to the extent that the conversion value of the Convertible Notes exceeds their principal amount.

Further, under the treasury stock method, the transaction is accounted for as if the number of shares of common stock that would be necessary to settle such excess are issued.

We cannot be sure that we will be able to continue to demonstrate the ability or intent to settle the Convertible Notes in cash or that the accounting standards will continue to permit the use of the treasury stock method.

If we are unable to use the treasury stock method in accounting for the shares issuable upon conversion of the Convertible Notes, our diluted earnings per share could be adversely affected.

See Note 1 to the Consolidated Financial Statements for a discussion of the new accounting guidance that will be adopted on January 1, 2022 as well as the effects that it will have on the accounting for the Convertible Notes.

Additionally, our operations may be disrupted or impaired if a significant portion of our or our service providers' employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the COVID-19 pandemic.

Further, the Consolidated GGA provides for a reduced fee structure for the gathering and compression fees charged by EQM; however this new fee structure does not take effect until the Mountain Valley Pipeline's in-service date.

There can be no assurance that the in-service date of the Mountain Valley Pipeline will not be delayed, or that the project will not be cancelled entirely, which would consequently delay, possibly indefinitely, the effective date of the fee reductions contemplated in the Consolidated GGA.

Neither Equitrans Midstream nor EQM is under any obligation to renegotiate their contracts with us, including the Consolidated GGA, in the event of a prolonged depressed commodity price environment or if the Mountain Valley Pipeline's in-service date is delayed.

We have recorded in our Consolidated Balance Sheet a contract asset of $410 million representing the estimated fair value of the rate relief provided by the Consolidated GGA that would be realized beginning with the Mountain Valley Pipeline’s in-service date.

We review the contract asset for indications of impairment when events or circumstances indicate the carrying value may not be recoverable.

Future delays in the Mountain Valley Pipeline's in-service date may affect our ability to fully realize the value we recorded as a contract asset for the rate relief associated with the Consolidated GGA, which could adversely affect our results of operations in future periods.

Separately, there have also been several instances of proposed legislation at the federal level which seek to impose a fee on methane emissions.

Most recently, in November 2021, the U.S. House of Representatives passed a budget reconciliation bill known as the Build Back Better Act.

The version of the bill approved by the House includes a provision that would impose charges on oil and gas facilities for their methane emissions.

Under the bill, the EPA would levy "methane fees" starting at $900 per ton in 2023, increasing to $1,200 in 2024 and then $1,500 in 2025 and each year thereafter.

The fee would apply to each ton of methane emissions in excess of 0.20% of the gas sold by the facility.

The bill is currently under review by the U.S. Senate, and it is unclear at this time as to what the final terms of any proposed methane fee may be.

Additionally, to the extent a fee on methane and/or carbon emissions is approved at the federal level, we, the utilities that purchase our natural gas, and/or the consumers of our natural gas and other hydrocarbons may bear increased costs associated with such fees, which may lead to an increase in our operating costs and/or a decrease in the demand for our produced hydrocarbons.

In September 2020, the EQB approved promulgation of the RGGI regulation, and a public comment period and hearings regarding the regulation commenced at the end of 2020.

In September 2021, Pennsylvania’s Independent Regulatory Review Commission adopted a regulation approving Pennsylvania’s participation in RGGI; however, in October 2021 the Pennsylvania Senate approved a resolution to block the state's participation in RGGI, and such resolution was subsequently approved by the Pennsylvania House in December 2021.

On January 10, 2022, Governor Wolf vetoed the Senate's resolution, and as a result, it is likely that Pennsylvania will join RGGI in 2022 unless the Pennsylvania legislature overrides the Governor's veto by the vote of two-thirds of the members of each of the Pennsylvania House and Senate.

The most significant potential tax law changes that could impact us include increases in the regular income tax rate, a new minimum tax based on net income, a new excise tax on stock repurchases, the repeal of expensing intangible drilling costs or percentage depletion, the repeal of like-kind exchange tax deferral rules on real property and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities.

Most recently, in November 2021, the U.S. House passed the Build Back Better Act, which includes some, but not all, of these proposals.

The bill is currently under review by the U.S. Senate, and, it is unclear at this time, what, if any, changes to the tax laws applicable to us will be enacted.

In 2010, Congress adopted the Dodd-Frank Act, which established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market.

The Dodd-Frank Act required the CFTC, the SEC and certain federal agencies that regulate the banking and insurance sectors (Prudential Regulators) to promulgate rules and regulations implementing the legislation.

Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivative activities.

Although some of the rules necessary to implement the Dodd-Frank Act have yet to be adopted, the CFTC, the SEC and Prudential Regulators have issued numerous rules, including the End-User Exception, which exempts certain "end-users" from having to comply with mandatory clearing, a Margin Rule mandating margining for certain uncleared swaps, and a Position Limits Rule imposing federal position limits on certain futures contracts relating to energy products, including natural gas.

We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception.

As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with such rule.

Net loss attributable to EQT Corporation for 2021 was [removed: $1,156] [added: $1,143] million, [removed: $3.58] [added: $3.54] per diluted share, compared to net loss attributable to EQT Corporation for 2020 of [removed: $967] [added: $959] million, [removed: $3.71] [added: $3.68] per diluted share.

The change was attributable primarily to the loss on [removed: derivatives not designated as hedges,] [added: 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 [removed: the first quarter of] 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.

See Note [removed: 6] [added: 13] to the Consolidated Financial Statements for [removed: further] [added: a] discussion of [removed: the Alta Acquisition, Chevron Acquisition] [added: our commitments] and [removed: Reliance Asset Acquisition.][added: contingencies.]

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 [removed: revenues, a non-GAAP supplemental financial measure.]

| | | | Years Ended December 31, | | | | | | | | | [added: | | | | | |]

| | | | [added: 2022 | | | | | |] 2021 | | | | | | 2020 | | |

| | | | (Thousands, unless otherwise noted) | | | | | | | | | [added: | | | | | |]

| NATURAL GAS | | | | | | | | | | | | [added: | | | | | |]

| Sales volume (MMcf) | | | [added: 1,842,044 | | | | | |] 1,746,317 | | | | | | 1,418,774 | | |

| NYMEX price ($/MMBtu) | | | $ | [added: 6.64 | | | | | $ |] 3.97 | | | | | $ | 2.09 | |

| Btu uplift | | | [added: 0.35 | | | | | |] 0.20 | | | | | | 0.11 | | |

| Natural gas price ($/Mcf) | | | $ | [added: 6.99 | | | | | $ |] 4.17 | | | | | $ | 2.20 | |

| Basis ($/Mcf) (a) | | | $ | [added: (0.77) | | | | | $ |] (0.63) | | | | | $ | (0.47) | |

| Cash settled basis swaps [removed: not designated as hedges] ($/Mcf) | | | [added: (0.02) | | | | | |] (0.07) | | | | | | 0.05 | | |

| Average differential, including cash settled basis swaps ($/Mcf) | | | $ | [added: (0.79) | | | | | $ |] (0.70) | | | | | $ | (0.42) | |

| Average adjusted price ($/Mcf) | | | $ | [added: 6.20 | | | | | $ |] 3.47 | | | | | $ | 1.78 | |

| Cash settled derivatives [removed: not designated as hedges] ($/Mcf) | | | [added: (3.20) | | | | | |] (1.09) | | | | | | 0.59 | | |

| Average natural gas price, including cash settled derivatives ($/Mcf) | | | $ | [added: 3.00 | | | | | $ |] 2.38 | | | | | $ | 2.37 | |

| Natural gas sales, including cash settled derivatives | | | $ | [added: 5,529,963 | | | | | $ |] 4,153,221 | | | | | $ | 3,359,583 | |

| LIQUIDS | | | | | | | | | | | | [added: | | | | | |]

| NGLs, excluding ethane: | | | | | | | | | | | | [added: | | | | | |]

| Sales volume (MMcfe) (b) | | | [added: 56,735 | | | | | |] 64,202 | | | | | | 44,702 | | |

| Sales volume (Mbbl) | | | [added: 9,456 | | | | | |] 10,700 | | | | | | 7,451 | | |

| [removed: Price] [added: NGLs price] ($/Bbl) | | | $ | [added: 53.26 | | | | | $ |] 44.50 | | | | | $ | 20.51 | |

| Cash settled derivatives [removed: not designated as hedges] ($/Bbl) | | | [added: (3.91) | | | | | |] (12.32) | | | | | | (0.12) | | |

| Average [added: NGLs] price, including cash settled derivatives ($/Bbl) | | | $ | [added: 49.35 | | | | | $ |] 32.18 | | | | | $ | 20.39 | |

| NGLs [removed: sales] [added: sales, including cash settled derivatives] | | | $ | [added: 466,664 | | | | | $ |] 344,260 | | | | | $ | 151,877 | |

| Ethane: | | | | | | | | | | | | [added: | | | | | |]

| Sales volume (MMcfe) (b) | | | [added: 35,100 | | | | | |] 37,548 | | | | | | 29,489 | | |

| Sales volume (Mbbl) | | | [added: 5,850 | | | | | |] 6,258 | | | | | | 4,914 | | |

| [removed: Price] [added: Ethane price] ($/Bbl) | | | $ | [added: 14.20 | | | | | $ |] 8.85 | | | | | $ | 3.48 | |

| Ethane sales | | | $ | [added: 83,096 | | | | | $ |] 55,393 | | | | | $ | 17,085 | |

| Oil: | | | | | | | | | | | | [added: | | | | | |]

| Sales volume (MMcfe) (b) | | | [added: 6,164 | | | | | |] 9,750 | | | | | | 4,827 | | |

| Sales volume (Mbbl) | | | [added: 1,027 | | | | | |] 1,625 | | | | | | 804 | | |

| [removed: Price] [added: Oil price] ($/Bbl) | | | $ | [added: 77.06 | | | | | $ |] 56.82 | | | | | $ | 25.57 | |

| Oil sales | | | $ | [added: 79,160 | | | | | $ |] 92,334 | | | | | $ | 20,574 | |

| Total liquids sales volume (MMcfe) (b) | | | [added: 97,999 | | | | | |] 111,500 | | | | | | 79,018 | | |

| Total liquids sales volume (Mbbl) | | | [added: 16,333 | | | | | |] 18,583 | | | | | | 13,169 | | |

| Total liquids sales | | | $ | [added: 628,920 | | | | | $ |] 491,987 | | | | | $ | 189,536 | |

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.

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.

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.

revenues, a non-GAAP supplemental financial measure.

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| | | | Years Ended December 31, | | | | | | | | | | | | | | |

| | | | 2022 | | | | | | 2021 | | | | | | 2020 | | |

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| | | | (Thousands, unless otherwise noted) | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | |

| Total sales volume (MMcfe) | | | 1,940,043 | | | | | | 1,857,817 | | | | | | 1,497,792 | | |

| Average realized price ($/Mcfe) | | | $ | 3.17 | | | | | $ | 2.50 | | | | | $ | 2.37 | |

| | | | 2022 | | | | | | 2021 | | | | | | Change | | | | | | % Change | | |

| Marcellus | | | 1,809,049 | | | | | | 1,684,673 | | | | | | 124,376 | | | | | | 7.4 | | |

| Ohio Utica | | | 123,517 | | | | | | 163,775 | | | | | | (40,258) | | | | | | (24.6) | | |

| Other | | | 7,477 | | | | | | 9,369 | | | | | | (1,892) | | | | | | (20.2) | | |

| Total sales volume | | | 1,940,043 | | | | | | 1,857,817 | | | | | | 82,226 | | | | | | 4.4 | | |

| Average daily sales volume (MMcfe/d) | | | 5,315 | | | | | | 5,090 | | | | | | 225 | | | | | | 4.4 | | |

| Sales of natural gas, NGLs and oil | | | $ | 12,114,168 | | | | | $ | 6,804,020 | | | | | $ | 5,310,148 | | | | | 78.0 | | |

Results of operations for 2021 include the results of approximately six months of our operation of assets acquired in the Alta Acquisition, which closed in July 2021, the results of a full year of our operation of assets acquired from Chevron U.S.A. Inc. (the Chevron Acquisition), which closed in November 2020, and nine months of our operation of assets acquired from Reliance Marcellus, LLC (the Reliance Asset Acquisition).

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on [Form 10-K](http://www.sec.gov/ix?doc=/Archives/edgar/data/33213/000003321321000006/eqt-20201231.htm#i43f68b92b00b4f60b7eb2031407a74f6_58) for the year ended December 31, 2020, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2019.

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The following table presents information on our production-related operating expenses.

Our investment in Equitrans Midstream fluctuates with changes in Equitrans Midstream's stock price, which was $10.34 and $8.04 as of December 31, 2021 and 2020, respectively.

*Loss on debt extinguishment.* During 2021, we recognized a loss on debt extinguishment of $9.8 million due to fees incurred for a bridge-loan commitment related to the Alta Acquisition and the repayment of our 4.875% senior notes.

During 2020, we recognized a loss on debt extinguishment of $25.4 million related to the repayment of all or a portion of our 4.875% senior notes, 2.50% senior notes, 3.00% senior notes, floating rate notes and term loan facility.

Impairment of Oil and Gas Properties

Aggregate future payments for these items as of December 31, 2021 were $23.8 billion, composed of $1.7 billion in 2022, $1.8 billion in 2023, $1.8 billion in 2024, $1.8 billion in 2025, $1.7 billion in 2026 and $15.0 billion thereafter (primarily in 2027 through 2042).

As of December 31, 2021, future commitments under these contracts were $135.6 million in 2022, $99.0 million in 2023, $47.5 million in 2024, $40.0 million in 2025, $40.0 million in 2026 and $178.3 million thereafter.

Sales volume in 2022 is expected to be 1,950 to 2,050 Bcfe.

Additionally, we plan to dispose of our remaining retained shares of Equitrans Midstream's common stock and use the proceeds to reduce our debt.

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on [Form 10-K](http://www.sec.gov/ix?doc=/Archives/edgar/data/33213/000003321321000006/eqt-20201231.htm#i43f68b92b00b4f60b7eb2031407a74f6_58) for the year ended December 31, 2020, which is incorporated herein by reference, for discussion and analysis of operating, investing and financing activities for the year ended December 31, 2019.

During the third quarter of 2021, we amended agreements with six of our largest OTC hedge counterparties to permanently or temporarily reduce or eliminate our margin posting obligations associated with our OTC derivative instruments with such OTC hedge counterparties.

The purpose of such amendments was to mitigate the amount of cash collateral that we would otherwise have been required to post based on current NYMEX strip pricing.

As of February 4, 2022, our margin balance on our existing hedge portfolio, including both OTC and broker margin balances, was approximately $0.3 billion, compared to approximately $0.1 billion as of December 31, 2020, despite a significant increase in natural gas prices.

The calculation of this ratio excludes the effects of accumulated other comprehensive loss.

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| Hedged Volume (MMDth) | | | | | | 355 | | | | | | 329 | | | | | | 287 | | | | | | 287 | | | | | | 858 | | | | | | 16 | | |

| Hedged Volume (MMDth/d) | | | | | | 3.9 | | | | | | 3.6 | | | | | | 3.1 | | | | | | 3.1 | | | | | | 2.4 | | | | | | — | | |

| Swaps (includes Futures) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Volume (MMDth) | | | | | | 289 | | | | | | 296 | | | | | | 254 | | | | | | 232 | | | | | | 166 | | | | | | 2 | | |

| Avg. Short Strike ($/Dth) | | | | | | $ | 3.26 | | | | | $ | 3.00 | | | | | $ | 3.00 | | | | | $ | 3.00 | | | | | $ | 4.38 | | | | | $ | 3.11 | |

| Avg. Long Strike ($/Dth) | | | | | | $ | 2.68 | | | | | $ | 2.68 | | | | | $ | 2.68 | | | | | $ | 2.68 | | | | | $ | 2.90 | | | | | $ | 2.45 | |

For 2022, 2023 and 2024, we have natural gas sales agreements for approximately 18 MMDth, 88 MMDth and 11 MMDth, respectively, that include average NYMEX ceiling prices of $3.17, $2.84 and $3.21, respectively.

During the third and fourth quarters of 2021, we purchased $67 million of net winter calls to reposition our 2021 and 2022 hedge portfolio to enable incremental upside participation in rising natural gas prices and to further mitigate potential incremental margin posting requirements.

As of December 31, 2021, the remaining positions cover approximately 45 net MMDth in the first quarter of 2022 and have been excluded from the table above.

In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against us.

While the amounts claimed may be substantial, we are unable to predict with certainty the ultimate outcome of such claims and proceedings.

We accrue legal and other direct costs related to loss contingencies when actually incurred.

We have established reserves that we believe to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against us will not materially affect our financial condition, results of operations or liquidity.

See Item 3., "Legal Proceedings."

Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense.

See "Impairment of Oil and Gas Properties" for additional information on our oil and gas reserves.

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

See also Note 5 to the Consolidated Financial Statements for a discussion of the derivative liability recorded in connection with the Equitrans Share Exchange.

*Contract Asset.* In the first quarter of 2020, we entered into two share purchase agreements with Equitrans Midstream to sell to Equitrans Midstream 50% of our ownership of Equitrans Midstream's common stock in exchange for a combination of cash and rate relief under certain of our gathering agreements with EQM, an affiliate of Equitrans Midstream.

See Note 5 to the Consolidated Financial Statements for further discussion of the key assumptions used in the fair value calculation of the contract asset and Note 1 to the Consolidated Financial Statements for a discussion of impairment considerations.

[removed: Due to the volatility of commodity prices, we are unable to predict future potential movements in the] market prices for natural gas and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.

Increases in natural gas and NGLs prices may be accompanied by, or result in, increased well drilling costs, increased production taxes, increased [removed: lease operating expenses,] [added: LOE,] increased volatility in seasonal gas price spreads for our storage assets and increased end-user conservation or conversion to alternative fuels.

The overall objective of our hedging program is to protect [added: our] cash flows from undue exposure to the risk of changing commodity prices.

A hypothetical decrease of 10% in the NYMEX natural gas price on December 31, [removed: 2021] [added: 2022] and [removed: 2020] [added: 2021] would increase the fair value of our natural gas derivative commodity instruments by approximately [removed: $577] [added: $727] million and [removed: $501] [added: $577] million, respectively.

A hypothetical increase of 10% in the NYMEX natural gas price on December 31, [removed: 2021] [added: 2022] and [removed: 2020] [added: 2021] would decrease the fair value of our natural gas derivative commodity instruments by approximately [removed: $581] [added: $333] million and [removed: $495] [added: $581] million, respectively.

For purposes of this analysis, we applied the 10% change in the NYMEX natural gas price on December 31, [removed: 2021] [added: 2022] and [removed: 2020] [added: 2021] to our natural gas derivative commodity instruments as of December 31, [removed: 2021] [added: 2022] and [removed: 2020] [added: 2021] to calculate the hypothetical change in fair value.

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

*Interest Rate Risk.* Changes in market interest rates affect the amount of interest we earn on cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our credit [removed: facility.][added: facility and Term Loan Facility.]

A 1% increase in interest rates on the borrowings under our credit facility during the year ended December 31, [removed: 2021] [added: 2022] would have increased interest expense by approximately [removed: $6] [added: $5] million.

[removed: Interest rates on our other outstanding senior notes do not] fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch.

Approximately [removed: 47%,] [added: 36%,] or [removed: $456] [added: $710] million, of our OTC derivative contracts outstanding at December 31, [removed: 2020] [added: 2022] had a positive fair value.

As of December 31, [removed: 2021,] [added: 2022,] we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts.

During the year ended December 31, [removed: 2021,] [added: 2022,] we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure.

Revenues and related accounts receivable from our operations are generated primarily from the sale of [added: our] produced natural gas, NGLs and oil to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast United States and Canada.

We also contract with certain processors to market a portion of [added: our] NGLs on our behalf.

Due to the volatility of commodity prices, we are unable to predict future potential movements in the

We had no borrowings under our Term Loan Facility as of December 31, 2022.

Interest rates on our other outstanding senior notes do not

As of December 31, [removed: 2021,] [added: 2022,] we had 25.0 Tcfe of proved natural gas, NGLs and crude oil reserves across approximately 2.0 million gross acres, including approximately [removed: 1.7] [added: 1.8] million gross acres in the Marcellus play.

Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh [added: and recycled] water (as opposed to truck-transported water), [added: and provides] the ability to continuously meet completions supply needs and the use of environmentally friendly technologies.

Combo-development, when compared to similar production from non-combo-development operations, translates into fewer trucks on the road, decreased fuel usage, shorter periods of noise pollution, fewer areas impacted by midstream pipeline construction and shortened duration of site operations, all of which fosters a greater focus on [removed: safety and] [added: safety,] environmental [removed: protection.][added: protection and social responsibility.]

[removed: Combo-development] [added: Our strategy, and combo-development] projects [removed: require] [added: in particular, requires] significant advanced planning, including the establishment of a large, contiguous leasehold position; the advanced acquisition of regulatory permits and sourcing of fracturing sand and water; the timely verification of midstream connectivity; and the ability to quickly respond to internal and external stimuli.

We believe that our proprietary digital work [removed: environment] [added: environment,] in conjunction with the size and contiguity of our asset [removed: base] [added: base,] uniquely position us to execute on a multi-year inventory of combo-development projects in our core acreage position.

Our operational strategy employs this differentiation to advance our mission of being the operator of choice for all [removed: stakeholders.][added: stakeholders, while simultaneously helping to address energy security and affordability both domestically and globally.]

We believe that combo-development projects are key to delivering sustainably low well costs and higher returns on invested [removed: capital and that our long-term transformative plan has been designed to create value by leveraging our strategic advantage, both operational and environmental, over our peers.][added: capital.]

We are [added: also] focused on [removed: achieving and] maintaining investment grade credit [removed: metrics as well as regaining our investment grade credit rating in the near term,] [added: metrics,] which [removed: will allow] [added: allows] us to capture a lower cost of capital and [added: further] enhance shareholder returns.

- Achieved [added: investment grade] credit ratings [removed: upgrades] from [removed: S&P, Moody's] [added: Fitch] and [removed: Fitch.][added: S&P and upgraded to positive outlook at Moody's.]

In [removed: 2022,] [added: 2023,] we expect to spend approximately [removed: $1.30] [added: $1.7] to [removed: $1.45] [added: $1.9] billion in total capital expenditures, excluding amounts attributable to noncontrolling [removed: interest.][added: interests and acquisitions.]

We expect to allocate the planned capital expenditures as follows: approximately [removed: $1.0] [added: $1,400] to [removed: $1.1 billion] [added: $1,535 million] to fund reserve development, approximately [removed: $110] [added: $120] to [removed: $130] [added: $140] million to fund land and lease acquisitions, approximately [removed: $120] [added: $125] to $160 million to fund other production infrastructure and approximately $55 to [removed: $75] [added: $65] million applied towards capitalized overhead.

[removed: In addition, we announced our] [added: Our capital allocation] plan [removed: to return] [added: is focused on maintaining production volumes while also returning] capital to shareholders, [removed: which included the commencement of a] [added: including through our] share repurchase program, under which we are authorized to repurchase [removed: $1.0] [added: up to $2.0] billion of our outstanding common stock, and [removed: the reinstatement of a] [added: through our] quarterly cash [removed: dividend at] [added: dividend, which is currently] an annual rate of [removed: $0.50] [added: $0.60] per [removed: share of our common stock starting in the first quarter of 2022.][added: share.]

[removed: We] [added: Furthermore, we] have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future natural gas and NGLs prices, [removed: which will enable] [added: thereby enabling] us to execute on our capital expenditure, debt [removed: reduction] [added: retirement] and shareholder return strategy.

See [removed: "Impairment of Oil and Gas Properties" and] "Critical Accounting Policies and Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" [added: and Note 1 to the Consolidated Financial Statements] for a discussion of our accounting policies and significant assumptions related to accounting for [added: natural] gas, NGLs and oil producing activities and [removed: our accounting policies and processes related to] impairment [removed: reviews for proved] [added: of our oil] and [removed: unproved property.][added: gas properties.]

| [added: Year Ended December 31, 2021] | | | [removed: December 31, 2021] [added: 60] | | | | | | [added: 17] | | | | | | [added: 5] | | | [added: | | | 82 | | |]

| Proved undeveloped reserves | | | [removed: 7,372] [added: 7,284] | | | | | | [removed: 62] [added: 34] | | | | | | [removed: 7,743] [added: 7,489] | | |

| | | | Marcellus | | | | | | [removed: Upper Devonian | | | | | |] Ohio Utica | | | | | | Other | | | | | | Total | | |

| | | | (Bcfe) | | | | | | | | | | | | | | | | | | | | | [removed: | | | | | |]

| Proved undeveloped reserves | | | [removed: 7,733 | | | | | | —] [added: 7,468] | | | | | | [removed: 10] [added: 17] | | | | | | [removed: —] [added: 4] | | | | | | [removed: 7,743] [added: 7,489] | | |

| Proved developed non-producing reserves | | | [removed: 375] [added: 461] | | | | | | [removed: 123] [added: 109] | | | | | | [removed: 6] [added: 28] | | | | | | | | | | | | [removed: 504] [added: 598] | | |

| Gross proved undeveloped drilling locations | | | [removed: 279] [added: 256] | | | | | | [removed: 146] [added: 126] | | | | | | [removed: 5] [added: 6] | | | | | | | | | | | | [removed: 430] [added: 388] | | |

| Net proved undeveloped drilling locations | | | [removed: 195] [added: 194] | | | | | | [removed: 118] [added: 106] | | | | | | 1 | | | | | | | | | | | | [removed: 314] [added: 301] | | |

Our [removed: 2021] [added: 2022] total proved reserves increased by [removed: 5.2 Tcfe,] [added: 41 Bcfe,] or [removed: 26%,] [added: 0.2%,] compared to [removed: 2020] [added: 2021] due to [added: extensions, discoveries and other additions of 2,495 Bcfe and] acquisitions of [removed: 4,187] [added: 141] Bcfe from the [removed: Alta Acquisition and Reliance] [added: 2022] Asset Acquisition (defined in Note 6 to the Consolidated Financial [removed: Statements) and extensions, discoveries and other additions of 3,104 Bcfe,] [added: Statements),] partly offset by production of [removed: 1,858] [added: 1,940] Bcfe and revisions to previous estimates of [removed: 274] [added: 655] Bcfe.

| Conversions into proved developed reserves | | | [removed: (1,634)] [added: (1,365)] | | |

| Acquisition of in-place reserves | | | [removed: 1,217] [added: 141] | | |

| Revision of previous estimates (a) | | | [removed: (881)] [added: (1,107)] | | |

| Extensions, discoveries and other additions (b) | | | [removed: 2,880] [added: 2,077] | | |

(a)Composed of (i) negative revisions of [removed: 819] [added: 1,625] Bcfe [removed: from] [added: related to] proved undeveloped locations that are no longer expected to be developed [added: as proved reserves] within five years of initial booking as [removed: proved reserves as] a result of [removed: changes to our] development [removed: plan to support the continued implementation of our combo-development strategy;] [added: schedule changes, driven largely by third-party impacts, which has pushed planned completion dates into a future period from when originally planned;] and (ii) [removed: negative] [added: positive] revisions of [removed: 62] [added: 518] Bcfe due primarily to changes in [removed: working interests and net revenue] [added: ownership] interests.

(b)Composed of [removed: (i) 2,828] [added: 2,077] Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to [removed: 2021] [added: 2022] reserve development that expanded the number of our proven [removed: locations, implementation of, and alignment with, our combo-development strategy] [added: locations] and additions to our five-year drilling [removed: plan; and (ii) 52 Bcfe from the extension of lateral lengths of proved undeveloped reserves.][added: plan.]

As of December 31, [removed: 2021,] [added: 2022,] we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

[removed: See Note 18 to the Consolidated Financial] Statements for further discussion of the preparation of, and year-over-year changes in, our reserves estimate and calculation of the standardized measure of estimated future net cash flows from natural gas and crude oil reserves.

If the prices used in the calculation of the [removed: standardized measure] [added: Standardized Measure] instead reflected five-year strip pricing as of December [removed: 31, 2021] [added: 30, 2022] and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp. M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the [removed: standardized measure,] [added: Standardized Measure,] and holding all other assumptions constant, our total proved reserves would be [removed: 24,913] [added: 24,971] Bcfe, the [removed: standardized measure of our discounted net future cash flows] [added: Standardized Measure] after taxes of our proved reserves would be [removed: $16,059] [added: $22,625] million and the discounted future net cash flows before taxes would be [removed: $19,672] [added: $29,169] million.

The average realized product prices weighted by production over the remaining lives of the properties would be [removed: $46.84 per barrel of oil, $27.22 per barrel of NGLs and $2.448 per Mcf of gas (compared to $51.57] [added: $50.13] per barrel of oil, [removed: $29.95] [added: $27.30] per barrel of NGLs and [removed: $2.694] [added: $3.565] per Mcf of [removed: gas using SEC pricing, as described in Note 18 to the Consolidated Financial Statements).][added: gas.]

The NYMEX strip price [added: for] proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with SEC pricing [added: for] proved reserves and do not comply with SEC pricing assumptions.

While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate and [added: are] not necessarily an accurate projection of future oil and gas prices.

Actual future prices may vary significantly from [removed: the] NYMEX prices; therefore, actual revenue and value generated may be more or less than the amounts disclosed.

| | | | [removed: 2021] [added: 2022] | | | | | | [removed: 2020] [added: 2021] | | | | | | [removed: 2019] [added: 2020] | | |

| Marcellus | | | $ | [removed: 788] [added: 1,102] | | | | | $ | [removed: 737] [added: 788] | | | | | $ | [removed: 1,184] [added: 737] | |

| Utica | | | [removed: 40] [added: 29] | | | | | | [removed: 102] [added: 40] | | | | | | [removed: 193] [added: 102] | | |

| Total | | | $ | [removed: 828] [added: 1,131] | | | | | $ | [removed: 839] [added: 828] | | | | | $ | [removed: 1,377] [added: 839] | |

Our business model has been developed to enable us to generate sustainable free cash flow and correspondingly, we have implemented a robust capital allocation strategy directed at responsibly developing our assets while also returning capital to our shareholders through a combination of dividends, strategic share repurchases, and debt retirements.

Furthermore, we believe the benefits of our operating model can be magnified through select strategic transactions, and part of our strategy includes creating value through mergers and acquisitions, divestitures, joint ventures and similar business transactions, as well as investing in energy transition opportunities directed at complementing, and in certain cases diversifying, our core business operations.

2022 Highlights

- Generated $3,466 million of net cash provided by operating activities.

- Delivered on our capital return strategy through debt retirements, share buybacks and dividends.

◦Repaid or repurchased $826 million aggregate principal of senior notes.

◦Repurchased $85 million aggregate principal of convertible notes, reducing our fully diluted share count by 5.7 million shares.

◦Repurchased $393 million of common stock, reducing our share count by 13.1 million shares.

◦Increased quarterly base dividend by 20% to $0.15 per share ($0.60 per share annualized).

◦Paid $204 million in dividends to shareholders.

- Authorized to repurchase up to $2.0 billion of our shares through December 31, 2023.

- Announced agreement to acquire Tug Hill and XcL Midstream.

- Added to the S&P 500 Index, joining top companies across all sectors of the U.S. economy.

- Successfully completed our initiative to eliminate natural gas-powered pneumatic devices from our production operations, meaningfully reducing our methane and carbon emissions.

- Announced Appalachian Regional Clean Hydrogen Hub (ARCH2) collaboration with the State of West Virginia and leading energy and technology companies.

- Announced Appalachian Methane Initiative (AMI) collaboration to further enhance methane monitoring throughout the Appalachian Basin.

In 2023, we expect our sales volume to be 1,900 to 2,000 Bcfe, excluding amounts attributable acquisitions.

We are committed to maintaining investment grade credit metrics and we have a goal to retire at least $4.0 billion of our debt between January 1, 2022 and December 31, 2023, subject to the occurrence and timing of the closing of the Tug Hill and XcL Midstream Acquisition and the overall performance of the commodity markets.

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."

| | | | December 31, 2022 | | | | | | | | | | | | | | |

| Proved developed reserves | | | 16,541 | | | | | | 162 | | | | | | 17,514 | | |

| Total proved reserves | | | 23,825 | | | | | | 196 | | | | | | 25,003 | | |

| | | | December 31, 2022 | | | | | | | | | | | | | | | | | | | | |

| Proved developed reserves | | | 16,718 | | | | | | 708 | | | | | | 88 | | | | | | 17,514 | | |

| Total proved reserves | | | 24,186 | | | | | | 725 | | | | | | 92 | | | | | | 25,003 | | |

| | | | December 31, 2022 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Proved developed producing reserves | | | 12,775 | | | | | | 3,461 | | | | | | 680 | | | | | | | | | | | | 16,916 | | |

| Proved undeveloped reserves | | | 4,933 | | | | | | 2,539 | | | | | | 17 | | | | | | | | | | | | 7,489 | | |

| Total proved reserves | | | 18,169 | | | | | | 6,109 | | | | | | 725 | | | | | | | | | | | | 25,003 | | |

Our 2022 proved undeveloped reserves decreased by 254 Bcfe, or 3.3%, compared to 2021.

| Balance at January 1, 2022 | | | 7,743 | | |

| Balance at December 31, 2022 | | | 7,489 | | |

The following table provides the estimated future net cash flows, excluding open derivative contracts, from proved reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10) and the prices used in projecting net cash flows over the past three years.

Our reserve estimates do not include any probable or possible reserves.

| | | | (Millions, except prices) | | | | | | | | | | | | | | |

| Future net cash flow | | | $ | 87,612 | | | | | $ | 36,567 | | | | | $ | 7,543 | |

| Standardized measure of discounted future net cash flow | | | 40,065 | | | | | | 17,281 | | | | | | 3,366 | | |

| PV-10 (a) | | | 51,512 | | | | | | 21,496 | | | | | | 3,967 | | |

| Prices, including regional adjustments: | | | | | | | | | | | | | | | | | |

We believe our business model is sustainable and we expect to generate significant free cash flow over the next six years.

Our capital allocation plan is focused on reducing our debt and leverage, while also returning capital to shareholders through a combination of dividends and a share repurchase program.

2021 Highlights

- Achieved 2021 sales volume of 1,858 Bcfe, average daily sales volume of 5.1 Bcfe per day; received an average realized price of $2.50 per Mcfe.

- Increased 2021 total proved reserves by 5.2 Tcfe, or 26%, compared to 2020.

- Acquired strategic assets located in the Appalachian Basin from Alta Resources Development, LLC for total consideration of $2,925 million (the Alta Acquisition).

- Realized a meaningful reduction of gathering and transmission expense on a per Mcfe basis of $0.05 and $0.06, respectively, during 2021 compared to 2020.

- Extended the term of our credit facility and reduced outstanding letters of credit under our credit facility by $351 million.

- Obtained Equitable Origin and MiQ Certifications for a majority of our natural gas.

Our 2022 capital expenditure program is expected to deliver sales volume of 1,950 to 2,050 Bcfe.

In December 2021, we reaffirmed our commitment to attaining investment grade credit metrics and outlined a leverage and debt reduction strategy with the goal of reducing total debt by at least $1.5 billion by the end of 2023.

Our capital allocation plan is focused on maintaining production volumes.

| Proved developed reserves | | | 16,152 | | | | | | 178 | | | | | | 17,219 | | |

| Total proved reserves | | | 23,524 | | | | | | 240 | | | | | | 24,962 | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Proved developed reserves | | | 15,528 | | | | | | 806 | | | | | | 787 | | | | | | 98 | | | | | | 17,219 | | |

| Total proved reserves | | | 23,261 | | | | | | 806 | | | | | | 797 | | | | | | 98 | | | | | | 24,962 | | |

| Proved developed producing reserves | | | 12,642 | | | | | | 3,292 | | | | | | 781 | | | | | | | | | | | | 16,715 | | |

| Proved undeveloped reserves | | | 5,085 | | | | | | 2,648 | | | | | | 10 | | | | | | | | | | | | 7,743 | | |

| Total proved reserves | | | 18,102 | | | | | | 6,063 | | | | | | 797 | | | | | | | | | | | | 24,962 | | |

Our 2021 proved undeveloped reserves increased by 1,582 Bcfe, or 26%, compared to 2020.

| Balance at January 1, 2021 | | | 6,161 | | |

| Balance at December 31, 2021 | | | 7,743 | | |

As of December 31, 2021, the standardized measure of our estimated future net cash flows from natural gas and crude oil reserves, which is calculated using average first-day-of-the-month closing prices for the prior twelve months (referred to as SEC pricing), was $17,281 million, as described in Note 18 to the Consolidated Financial Statements.

| Total gross productive acreage | | | 396,356 | | | | | | 117,972 | | | | | | 51,109 | | | | | | | | | | | | 565,437 | | |

| Total gross undeveloped acreage | | | 938,848 | | | | | | 364,456 | | | | | | 124,151 | | | | | | | | | | | | 1,427,455 | | |

| Total gross acreage | | | 1,335,204 | | | | | | 482,428 | | | | | | 175,260 | | | | | | | | | | | | 1,992,892 | | |

| Total net productive acreage | | | 336,228 | | | | | | 123,734 | | | | | | 38,589 | | | | | | | | | | | | 498,551 | | |

| Total net undeveloped acreage | | | 805,349 | | | | | | 319,486 | | | | | | 108,443 | | | | | | | | | | | | 1,233,278 | | |

| Total net acreage | | | 1,141,577 | | | | | | 443,220 | | | | | | 147,032 | | | | | | | | | | | | 1,731,829 | | |

| | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | December 31, 2021 | | | | | | | | |

| Total gross | | | 4,527 | | | | | | | | |

| Total net | | | 3,510 | | | | | | | | |

| Total gross | | | 282 | | | | | | | | |

| Total net | | | 248 | | | | | | | | |

| Total gross productive wells (a) | | | 3,543 | | | | | | 710 | | | | | | 274 | | | | | | | | | | | | 4,527 | | |

In January 2022, we determined the release was larger than initially discovered and we disclosed this information to PADEP on January 14, [removed: 2022.]

The plaintiffs sought more than $100 million in compensatory damages for the trespass claim under the Stout [removed: Lease] [added: Lease,] and approximately $20 million for insufficient royalties under both the Stout Lease and the Cities Services Lease, in addition to punitive damages and other relief.

2022.

On January 18, 2023, the Circuit Court of Doddridge County, West Virginia granted an Order to dismiss this case and all corresponding claims, counterclaims, and pending motions.

Accordingly, this matter is now closed.

On October 7, 2020, the plaintiffs filed a motion to amend their complaint and to stay entry of an Order of Dismissal.

On January 14, 2021, we filed a motion to enforce the settlement agreed to with the plaintiffs and to seek sanctions.

All motions are pending.

| | | | FOR THE FISCAL YEAR ENDED DECEMBER 31, [removed: 2021] [added: 2022] | | | | | |

The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, [removed: 2021: $6.2] [added: 2022: $12.6] billion

As of February [removed: 4, 2022, 376,023,250] [added: 10, 2023, 360,360,130] shares of common stock, no par value, of the registrant were outstanding.

EQT Corporation's definitive proxy statement relating to its [removed: 2022] [added: 2023] annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the close of EQT Corporation's fiscal year ended December 31, [removed: 2021] [added: 2022] and is incorporated by reference in Part III to the extent described therein.

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| [Item [removed: 15.](#ib6b2fe1565e24737983a625bb9fea3f6_181)] [added: 15.](#i4ae3a35ac7604788a4cf429083eb6d7f_187)] | | | [Exhibits and Financial Statement [removed: Schedules](#ib6b2fe1565e24737983a625bb9fea3f6_181)] [added: Schedules](#i4ae3a35ac7604788a4cf429083eb6d7f_187)] | | | [removed: [117](#ib6b2fe1565e24737983a625bb9fea3f6_181)] [added: [115](#i4ae3a35ac7604788a4cf429083eb6d7f_187)] | | |

| [Item [removed: 16.](#ib6b2fe1565e24737983a625bb9fea3f6_190)] [added: 16.](#i4ae3a35ac7604788a4cf429083eb6d7f_196)] | | | [Form 10-K [removed: Summary](#ib6b2fe1565e24737983a625bb9fea3f6_190)] [added: Summary](#i4ae3a35ac7604788a4cf429083eb6d7f_196)] | | | [removed: [123](#ib6b2fe1565e24737983a625bb9fea3f6_190)] [added: [122](#i4ae3a35ac7604788a4cf429083eb6d7f_196)] | | |

| ESG – [removed: Environmental, Social] [added: environmental, social] and [removed: Governance initiatives] [added: governance] | | |

Pressures on the market as a whole, or our specific financial position – whether due to depressed commodity prices, our [added: hedge positions,] leverage, [removed: our] credit [removed: ratings] [added: ratings, tax law changes] or otherwise – could make it difficult for us to obtain the funding necessary to conduct our operations.

While these [removed: digital] systems [added: and infrastructure] enable us to efficiently supply our natural gas, NGLs and oil to the market, they are also susceptible to [added: physical and] cyber security threats.

Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in sections "Strategy" and "Outlook" in Item 1., "Business," [added: the] section [removed: "Impairment of Oil] [added: "Trends] and [removed: Gas Properties"] [added: Uncertainties"] in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of [removed: Operations,"] [added: Operations",] and the expectations of our plans, strategies, objectives and growth and anticipated financial and operational performance, including guidance regarding our strategy to develop our reserves; drilling plans and programs, including availability of capital to complete these plans and programs; total resource potential and drilling inventory duration; projected production and sales volume and growth rates; natural gas prices; changes in basis and the impact of commodity prices on our business; potential future impairments of our assets; projected well costs and capital expenditures; infrastructure programs; the cost, capacity and timing of obtaining regulatory approvals; our ability to successfully implement and execute our operational, organizational, technological and ESG initiatives, and achieve the anticipated results of such initiatives; projected gathering and compression rates; [removed: monetization transactions, including asset sales, joint ventures or other transactions involving our assets, and our planned use of the proceeds from such monetization transactions;] potential acquisition transactions or other strategic transactions, the timing thereof and our ability to achieve the intended operational, financial and strategic benefits from any such [removed: transactions;] [added: transactions, including] the [removed: timing and structure of any dispositions of our remaining retained shares of Equitrans Midstream's common stock,] [added: Tug Hill] and [removed: the planned use of] [added: XcL Midstream Acquisition (defined in Note 6 to] the [removed: proceeds from any such dispositions;] [added: Consolidated Financial Statements);] the amount and timing of any repayments, redemptions or repurchases of our common stock, outstanding debt securities or other debt instruments; our ability to [removed: reduce] [added: retire] our debt and the timing of such [removed: reductions,] [added: retirements,] if any; the projected amount and timing of dividends; projected cash flows and free cash flow, and the timing thereof; liquidity and financing requirements, including funding sources and availability; our ability to maintain or improve our credit ratings, leverage levels and financial profile; our hedging strategy and projected margin posting obligations; the effects of litigation, government regulation and tax position; and the expected impact of changes to tax laws.

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

| [Signatures](#i4ae3a35ac7604788a4cf429083eb6d7f_199) | | | | | | [123](#i4ae3a35ac7604788a4cf429083eb6d7f_199) | | |

turned-in-line – when a well is completed, producing and initially turned to sales.

| FTC – Federal Trade Commission | | |

| WTI – West Texas Intermediate crude oil | | |

| [Signatures](#ib6b2fe1565e24737983a625bb9fea3f6_193) | | | | | | [124](#ib6b2fe1565e24737983a625bb9fea3f6_193) | | |

Information about our Executive Officers (as of February [removed: 10, 2022)][added: 16, 2023)]

| Tony Duran [removed: (43)] [added: (44)] | | | | | | Chief Information Officer (2019) | | | | | | Mr. Duran was appointed as the Chief Information Officer of EQT Corporation in July 2019. Prior to joining EQT Corporation, Mr. Duran ran PH6 Labs, a technology incubator he founded, from December 2017 to July 2019. Prior to that, he served as the Chief Information Officer of Rice Energy Inc. (independent natural gas and oil company acquired by EQT Corporation in November 2017) from January 2016 to November 2017; and as the Interim Chief Information Officer of Express Energy Services (oilfield services company for well construction and well testing services) from September 2015 to December 2015. Additionally, Mr. Duran held various positions at National Oilwell Varco (multinational corporation that provides equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry) from May 2002 to August 2015, where he last held the role of Assistant Chief Information Officer. | | |

| Lesley Evancho [removed: (44)] [added: (45)] | | | | | | Chief Human Resources Officer (2019) | | | | | | Ms. Evancho was appointed as the Chief Human Resources Officer of EQT Corporation in July 2019. Prior to joining EQT Corporation, Ms. Evancho served as Vice President, Global Talent Management at Westinghouse Electric Company, LLC (nuclear power, fuel and services company) from April 2019 to July 2019; Senior Director, Human Resources at Thermo Fisher Scientific, Inc. (biotechnology product development company) from August 2018 to March 2019; Vice President, Human Resources at Edward Marc Brands (food services company) from March 2018 to August 2018; and Vice President, Human Resources at Rice Energy Inc. from April 2017 to November 2017. Additionally, Ms. Evancho served as Global Director, Talent Management at MSA Safety, Inc. (manufacturer of industrial safety equipment) from November 2011 to April 2017. | | |

| Todd M. James [removed: (39)] [added: (40)] | | | | | | Chief Accounting Officer (2019) | | | | | | Mr. James was appointed as the Chief Accounting Officer of EQT Corporation in November 2019. Prior to joining EQT Corporation, Mr. James served as the Corporate Controller and Chief Accounting Officer of L.B. Foster Company (manufacturer and distributor of products and services for transportation and energy infrastructure) from April 2018 to October 2019. Prior to that he served as the Senior Director, Technical Accounting and Financial Reporting at Rice Energy Inc. from December 2014 through its acquisition by EQT Corporation in November 2017 and until February 2018. Prior to joining Rice Energy, Mr. James was a Senior Manager, Assurance at PricewaterhouseCoopers LLP (public accounting firm), where he worked from August 2005 to November 2014. | | |

| William E. Jordan [removed: (41)] [added: (42)] | | | | | | Executive Vice President, General Counsel and Corporate Secretary (2019) | | | | | | Mr. Jordan was appointed as the Executive Vice President and General Counsel of EQT Corporation in July 2019 and assumed the role of Corporate Secretary in November 2020. Mr. Jordan served as an advisor to the Rice Investment Group (multi-strategy investment fund investing in all verticals of the oil and gas sectors) from May 2018 until July 2019. Prior to that, he served as the Senior Vice President, General Counsel and Corporate Secretary of Rice Energy Inc. and Senior Vice President, General Counsel and Corporate Secretary of Rice Midstream Partners LP (former midstream services affiliate of Rice Energy Inc.), in each case from January 2014 until their acquisition by EQT Corporation in November 2017. From September 2005 to December 2013, Mr. Jordan was an associate at Vinson & Elkins LLP (an international law firm) representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. | | |

| David M. Khani [removed: (58)] [added: (59)] | | | | | | Chief Financial Officer (2020) | | | | | | Mr. Khani was appointed as the Chief Financial Officer of EQT Corporation in January 2020. Prior to joining EQT Corporation, Mr. Khani served as the Executive Vice President and Chief Financial Officer of CONSOL Energy (energy company primarily focused on developing coal interests), from March 2013 to December 2019; and as Vice President, Finance at CONSOL Energy from September 2011 to March 2013. In addition, Mr. Khani served as Chief Financial Officer and as a member of the Board of Directors of CONE Midstream LLC (midstream services affiliate of CONSOL Energy) from September 2014 to January 2018; as a member of the Board of Directors of CNX Coal Resources (coal mining affiliate of CONSOL Energy) from July 2015 to August 2017; and as Chief Financial Officer and as a member of the Board of Directors of CONSOL Coal Resources (coal mining affiliate of CONSOL Energy) from August 2017 to December 2019. | | |

| Toby Z. Rice [removed: (40)] [added: (41)] | | | | | | President and Chief Executive Officer (2019) | | | | | | Mr. Rice was appointed as President and Chief Executive Officer of EQT Corporation in July 2019, when he also was elected to EQT Corporation's Board of Directors. Mr. Rice has served as a Partner at the Rice Investment Group, a multi-strategy fund investing in all verticals of the oil and gas sector, since May 2018. From October 2014 until its acquisition by EQT Corporation in November 2017, Mr. Rice was President and Chief Operating Officer of Rice Energy Inc. and served on the Board of Directors of Rice Energy Inc. from October 2013 to November 2017. Prior to that, he served in a number of positions with Rice Energy, its affiliates and predecessor entities beginning in February 2007, including as President and Chief Executive Officer of a predecessor entity from February 2008 through September 2013. Mr. Rice is the brother of Daniel J. Rice IV, a member of EQT Corporation's Board of Directors since November 2017. | | |

Officers are [removed: elected] [added: appointed] annually to serve during the ensuing year or until their successors are elected and qualified, or until death, resignation or removal.

As of February [removed: 4, 2022,] [added: 10, 2023,] there were [removed: 1,927] [added: 1,820] shareholders of record of our common stock.

On February [removed: 3, 2022,] [added: 9, 2023,] our Board of Directors declared a quarterly cash dividend of [removed: $0.125] [added: $0.15] per share, payable on March 1, [removed: 2022,] [added: 2023,] to shareholders of record at the close of business on February [removed: 14, 2022.][added: 21, 2023.]

Our Board of Directors have the discretion to change the [removed: annual] dividend rate at any time for any reason.

The following table sets forth our repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred during the three months ended December 31, [removed: 2021.][added: 2022.]

| | | | Total number of shares [removed: purchased] [added: purchased (a)] | | | | | | Average price paid per share [removed: (a)] [added: (b)] | | | | | | Total number of shares purchased as part of publicly announced plans or programs [removed: (b)] [added: (c)] | | | | | | Approximate dollar value of shares that may yet be purchased under plans or [removed: programs] [added: programs (c)] | | |

[removed: (a)Excludes] [added: (b)Excludes] any fees, commissions or other expenses associated with the share repurchases.

[removed: (b)On] [added: (c)On] December 13, 2021, we announced that our Board of Directors approved a share repurchase program to repurchase shares of our outstanding common stock for an aggregate purchase price up to $1 billion, excluding fees, commissions and expenses.

As of December 31, [removed: 2021,] [added: 2022,] we had purchased shares for an aggregate purchase price of [removed: $29.4] [added: $422.1] million, excluding fees, commissions and expenses, under this authorization since its inception.

The total number of shares purchased and the approximate dollar value of shares that may yet be purchased under our repurchase authority reported [added: in this table] reflect shares purchased in [removed: December 2021 (based] [added: each month based] on the trade [removed: date) that did] [added: date; however, certain purchases may] not [removed: settle] [added: have settled] until [removed: January 2022.][added: the following month.]

The following graph compares the most recent cumulative five-year total return provided to shareholders of our common stock relative to the cumulative five-year total returns of the S&P 500 Index, the S&P MidCap 400 Index and two customized peer groups, the [removed: 2020] [added: 2021] Self-Constructed Peer Group and [removed: 2021] [added: 2022] Self-Constructed Peer Group, whose company composition is discussed in footnotes (a) and (b), respectively, below.

Our common stock was included in the S&P 500 Index until [removed: the Separation (defined and discussed in Note 9 to the Consolidated Financial Statements) and Distribution in] [added: November] 2018, [removed: following] [added: at] which [added: time] our common stock was added to the S&P MidCap 400 Index.

[removed: We] [added: Accordingly, we] have presented both indices for comparison in the following graph.

An investment of $100, with reinvestment of all dividends, is assumed to have been made in our common stock, in the S&P 500 Index, the S&P MidCap 400 Index and in each of the peer groups on December 31, [removed: 2016] [added: 2017] and its relative performance is tracked through December 31, [removed: 2021.][added: 2022.]

[removed: ][added: ]

*$100 invested on [removed: 12/31/16] [added: 12/31/17] in stock, index, or peer group, including reinvestment of dividends.

Copyright© [removed: 2022] [added: 2023] Standard & Poor's, a division of S&P Global.

[removed: (a)The 2020] [added: (b)The 2022] Self-Constructed Peer Group includes the following [removed: eight] [added: fifteen] companies: Antero Resources Corp., [added: Apache Corp.,] Chesapeake Energy Corp., CNX Resources Corp., Comstock Resources, Inc., Coterra Energy [removed: Inc. (formerly Cabot Oil & Gas Corp.), Gulfport] [added: Inc., Devon] Energy Corp., [added: Diamondback Energy Corp., Marathon Oil Corp., Matador Resources Co., Murphy Oil Corp., Ovintiv Inc., PDC Energy Inc.,] Range Resources Corp. and Southwestern Energy Co. The [removed: 2020] [added: 2022] Self-Constructed Peer Group is comprised of the companies included in our [removed: 2020] [added: 2022] performance peer [removed: group,] [added: group (with the exception of Continental Resources, Inc., which was excluded for purposes of the stock performance graph because its stock ceased to be publicly traded beginning in November 2022),] as selected by the Management Development and Compensation Committee of [removed: the] [added: our] Board of Directors for purposes of evaluating our relative total shareholder return under the [removed: 2020] [added: 2022] Incentive Performance Share Unit Program.

[removed: (b)The] [added: (a)The] 2021 Self-Constructed Peer Group includes the following [removed: eleven] [added: ten] companies: Antero Resources Corp., Apache Corp., CNX Resources Corp., Comstock Resources, Inc., [removed: Continental Resources, Inc.,] Coterra Energy Inc., Devon Energy Corp., Murphy Oil Corp., Ovintiv Inc., Range Resources Corp. and Southwestern Energy Co. The 2021 Self-Constructed Peer Group is comprised of the companies included in our 2021 performance peer group (with the exception of [added: (i)] Cimarex Energy Co., which was excluded for purposes of the stock performance graph because it was acquired by Cabot Oil & Gas Corp. in October 2021 thereby forming Coterra Energy [removed: Inc.),] [added: Inc, and (ii) Continental Resources, Inc., which was excluded for purposes of the stock performance graph because its stock ceased to be publicly traded beginning in November 2022),] as selected by the Management Development and Compensation Committee of [removed: the] [added: our] Board of Directors for purposes of evaluating our relative total shareholder return under the 2021 Incentive Performance Share Unit Program.

| October 1, 2022 – October 31, 2022 | | | 1,880,073 | | | | | | $ | 41.48 | | | | | 1,880,073 | | | | | | $ | 1,617,803,090 | |

| November 1, 2022 – November 30, 2022 | | | 958,327 | | | | | | 41.66 | | | | | | 958,327 | | | | | | 1,577,882,777 | | |

| December 1, 2022 – December 31, 2022 | | | 12,168 | | | | | | 41.08 | | | | | | — | | | | | | 1,577,882,777 | | |

| Total | | | 2,850,568 | | | | | | | | | | | | 2,838,400 | | | | | | | | |

(a)In December 2022, we withheld 12,168 shares to pay taxes upon vesting of restricted stock.

There were no shares withheld to pay taxes upon vesting of restricted stock in October and November 2022.

On September 6, 2022, we announced that our Board of Directors approved a $1 billion increase to the share repurchase program announced on December 13, 2021, pursuant to which approval we are authorized to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses.

Repurchases under the share repurchase program may be made from time to time in amounts and at prices we deem appropriate and will be subject to a variety of factors, including the market price of our common stock, general market and economic conditions, applicable legal requirements and other considerations.

The share repurchase program expires December 31, 2023 but may be suspended, modified or discontinued at any time without prior notice.

Our common stock was added back to the S&P 500 Index in October 2022.

Historical prices prior to November 2018 have been adjusted to reflect the spin-off of our midstream business in 2018.

| | | | 12/17 | | | | | | 12/18 | | | | | | 12/19 | | | | | | 12/20 | | | | | | 12/21 | | | | | | 12/22 | | |

| EQT Corporation | | | $ | 100.00 | | | | | $ | 61.28 | | | | | $ | 35.65 | | | | | $ | 41.80 | | | | | $ | 71.73 | | | | | $ | 113.04 | |

| S&P 500 Index | | | 100.00 | | | | | | 95.62 | | | | | | 125.72 | | | | | | 148.85 | | | | | | 191.58 | | | | | | 156.89 | | |

| S&P MidCap 400 Index | | | 100.00 | | | | | | 88.92 | | | | | | 112.21 | | | | | | 127.54 | | | | | | 159.12 | | | | | | 138.34 | | |

| 2021 Self-Constructed Peer Group (a) | | | 100.00 | | | | | | 60.74 | | | | | | 55.53 | | | | | | 41.45 | | | | | | 86.27 | | | | | | 131.48 | | |

| 2022 Self-Constructed Peer Group (b) | | | 100.00 | | | | | | 64.68 | | | | | | 60.70 | | | | | | 40.46 | | | | | | 89.07 | | | | | | 135.60 | | |

| October 1, 2021 – October 31, 2021 | | | — | | | | | | — | | | | | | — | | | | | | — | | |

| November 1, 2021 – November 30, 2021 | | | — | | | | | | — | | | | | | — | | | | | | — | | |

| December 1, 2021 – December 31, 2021 | | | 1,361,668 | | | | | | $ | 21.56 | | | | | 1,361,668 | | | | | | $ | 970,641,996 | |

| Total | | | 1,361,668 | | | | | | | | | | | | 1,361,668 | | | | | | | | |

Pursuant to the share repurchase authority, we may repurchase shares from time to time in open market or in privately negotiated transactions.

The share repurchase authority does not obligate us to acquire any specific number of shares, was effective immediately and is valid through December 31, 2023.

Historical prices prior to the Separation and Distribution have been adjusted to reflect the value of the Separation and Distribution.

| | | | 12/16 | | | | | | 12/17 | | | | | | 12/18 | | | | | | 12/19 | | | | | | 12/20 | | | | | | 12/21 | | |

| EQT Corporation | | | $ | 100.00 | | | | | $ | 87.43 | | | | | $ | 53.52 | | | | | $ | 31.14 | | | | | $ | 36.51 | | | | | $ | 62.65 | |

| S&P 500 Index | | | 100.00 | | | | | | 121.83 | | | | | | 116.49 | | | | | | 153.17 | | | | | | 181.35 | | | | | | 233.41 | | |

| S&P MidCap 400 Index | | | 100.00 | | | | | | 116.24 | | | | | | 103.36 | | | | | | 130.44 | | | | | | 148.26 | | | | | | 184.96 | | |

| 2020 Self-Constructed Peer Group (a) | | | 100.00 | | | | | | 83.12 | | | | | | 56.33 | | | | | | 39.36 | | | | | | 41.95 | | | | | | 71.12 | | |

| 2021 Self-Constructed Peer Group (b) | | | 100.00 | | | | | | 88.70 | | | | | | 56.49 | | | | | | 50.76 | | | | | | 34.79 | | | | | | 77.19 | | |

| [Reports of Independent Registered Public Accounting [removed: Firm](#ib6b2fe1565e24737983a625bb9fea3f6_61) [](#ib6b2fe1565e24737983a625bb9fea3f6_61)[(](#ib6b2fe1565e24737983a625bb9fea3f6_61)[PCAOB ID](#ib6b2fe1565e24737983a625bb9fea3f6_61)[:](#ib6b2fe1565e24737983a625bb9fea3f6_61) 42[)](#ib6b2fe1565e24737983a625bb9fea3f6_61)] [added: Firm (PCAOB ID:](#i4ae3a35ac7604788a4cf429083eb6d7f_64) 42[)](#i4ae3a35ac7604788a4cf429083eb6d7f_64)] | | | | | | [removed: [63](#ib6b2fe1565e24737983a625bb9fea3f6_61)] [added: [64](#i4ae3a35ac7604788a4cf429083eb6d7f_64)] | | |

| [Statements of Consolidated [removed: Operations](#ib6b2fe1565e24737983a625bb9fea3f6_64)] [added: Operations](#i4ae3a35ac7604788a4cf429083eb6d7f_67)] | | | | | | [removed: [67](#ib6b2fe1565e24737983a625bb9fea3f6_64)] [added: [67](#i4ae3a35ac7604788a4cf429083eb6d7f_67)] | | |

| [Statements of Consolidated [removed: Comprehensive](#ib6b2fe1565e24737983a625bb9fea3f6_70) [Loss](#ib6b2fe1565e24737983a625bb9fea3f6_70)] [added: Comprehensive Loss](#i4ae3a35ac7604788a4cf429083eb6d7f_73)] | | | | | | [removed: [68](#ib6b2fe1565e24737983a625bb9fea3f6_70)] [added: [68](#i4ae3a35ac7604788a4cf429083eb6d7f_73)] | | |

| [Consolidated Balance [removed: Sheets](#ib6b2fe1565e24737983a625bb9fea3f6_73)] [added: Sheets](#i4ae3a35ac7604788a4cf429083eb6d7f_76)] | | | | | | [removed: [69](#ib6b2fe1565e24737983a625bb9fea3f6_73)] [added: [69](#i4ae3a35ac7604788a4cf429083eb6d7f_76)] | | |

| [Statements of Consolidated Cash [removed: Flows](#ib6b2fe1565e24737983a625bb9fea3f6_76)] [added: Flows](#i4ae3a35ac7604788a4cf429083eb6d7f_79)] | | | | | | [removed: [70](#ib6b2fe1565e24737983a625bb9fea3f6_76)] [added: [70](#i4ae3a35ac7604788a4cf429083eb6d7f_79)] | | |

| [Statements of Consolidated [removed: Equity](#ib6b2fe1565e24737983a625bb9fea3f6_79)] [added: Equity](#i4ae3a35ac7604788a4cf429083eb6d7f_82)] | | | | | | [removed: [71](#ib6b2fe1565e24737983a625bb9fea3f6_79)] [added: [71](#i4ae3a35ac7604788a4cf429083eb6d7f_82)] | | |

| [Notes [removed: to](#ib6b2fe1565e24737983a625bb9fea3f6_82) [the](#ib6b2fe1565e24737983a625bb9fea3f6_82) [Consolidated] [added: to the Consolidated] Financial [removed: Statements](#ib6b2fe1565e24737983a625bb9fea3f6_82)] [added: Statements](#i4ae3a35ac7604788a4cf429083eb6d7f_85)] | | | | | | [removed: [72](#ib6b2fe1565e24737983a625bb9fea3f6_82)] [added: [72](#i4ae3a35ac7604788a4cf429083eb6d7f_85)] | | |

We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, [removed: 2021] [added: 2022] and [removed: 2020,] [added: 2021,] the related [added: consolidated] statements of [removed: consolidated] operations, comprehensive loss, cash flows and equity for each of the three years in the period ended December 31, [removed: 2021,] [added: 2022,] and the related notes and the financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements").

In our opinion, the consolidated financial statements present fairly, in all material respects, the [removed: consolidated] financial position of the Company at December 31, [removed: 2021] [added: 2022] and [removed: 2020,] [added: 2021,] and the [removed: consolidated] results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2021,] [added: 2022,] in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, [removed: 2021,] [added: 2022,] based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February [removed: 10, 2022] [added: 16, 2023] expressed an unqualified opinion thereon.

Critical Audit [removed: Matters][added: Matter]

The critical audit [removed: matters] [added: matter] communicated below [removed: are matters] [added: is a matter] arising from the current period audit of the financial statements that [removed: were] [added: was] communicated or required to be communicated to the audit committee and that: (1) [removed: relate] [added: relates] to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments.

The communication of [added: the] critical audit [removed: matters] [added: matter] does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit [removed: matters] [added: matter] below, providing [added: a] separate [removed: opinions] [added: opinion] on the critical audit [removed: matters] [added: matter] or on the accounts or disclosures to which [removed: they relate.][added: it relates.]

| *Description of the Matter* | | | At December 31, [removed: 2021,] [added: 2022,] the net book value of the Company's proved oil and natural gas properties was [removed: $15,610] [added: $16,023] million, and depreciation, depletion and amortization (DD&A) expense was [removed: $1,677] [added: $1,666] million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the Company's internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the Company's engineers, are used to calculate depletion on property acquisitions. Proved natural gas, natural gas liquids (NGLs) and oil reserve estimates are [removed: based on] [added: prepared using standard] geological and engineering [added: methods generally recognized in the petroleum industry based on] evaluations of [added: estimated] in-place hydrocarbon [removed: volumes.] [added: volumes using financial and non-financial inputs.] Significant judgment is required by the Company's engineers in [removed: evaluating geological and engineering] [added: interpreting the] data when estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including natural gas, NGLs and oil price assumptions, [added: and] future operating and capital costs [removed: assumptions and tax rates by jurisdiction,] [added: assumptions,] among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the Company's internal engineers as of December 31, [removed: 2021.] [added: 2022.] Auditing the Company's DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of management's determination of the inputs described above used by the specialists in estimating proved natural gas, NGLs and oil reserves. | | |

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

[added: | Q1 2022 | | | | | |] February [removed: 10,] [added: 11,] 2022 [added: | | | | | | 67.0535 | | |]

We have audited EQT Corporation and subsidiaries' internal control over financial reporting as of December 31, [removed: 2021,] [added: 2022,] based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria).

In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, [removed: 2021,] [added: 2022,] based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, [removed: 2021] [added: 2022] and [removed: 2020,] [added: 2021,] the related [added: consolidated] statements of [removed: consolidated] operations, comprehensive loss, cash flows and equity for each of the three years in the period ended December 31, [removed: 2021] [added: 2022] and the related notes and the financial statement schedule listed in the Index at Item 15(a) of the Company, and our report dated February [removed: 10, 2022] [added: 16, 2023] expressed an unqualified opinion thereon.

| | | | [removed: 2021] [added: 2022] | | | | | | [removed: 2020] [added: 2021 (a)] | | | | | | [added: 2020 (b) | | | | | |] 2019 | | | [added: | | | 2018 | | |]

| Sales of natural gas, natural gas liquids and oil | | | $ | [removed: 6,804,020] [added: 12,114,168] | | | | | $ | [removed: 2,650,299] [added: 6,804,020] | | | | | $ | [removed: 3,791,414] [added: 2,650,299] | |

| (Loss) gain on derivatives [removed: not designated as hedges] | | | [removed: (3,775,042)] [added: (4,642,932)] | | | | | | [removed: 400,214] [added: (3,775,042)] | | | | | | [removed: 616,634] [added: 400,214] | | |

| Net marketing services and other | | | [removed: 35,685] [added: 26,453] | | | | | | [removed: 8,330] [added: 35,685] | | | | | | [removed: 8,436] [added: 8,330] | | |

| Total operating revenues | | | [removed: 3,064,663] [added: 7,497,689] | | | | | | [removed: 3,058,843] [added: 3,064,663] | | | | | | [removed: 4,416,484] [added: 3,058,843] | | |

| Transportation and processing | | | [removed: 1,942,165] [added: 2,116,976] | | | | | | [removed: 1,710,734] [added: 1,942,165] | | | | | | [removed: 1,752,752] [added: 1,710,734] | | |

| Production | | | [removed: 225,279] [added: 300,985] | | | | | | [removed: 155,403] [added: 225,279] | | | | | | [removed: 153,785] [added: 155,403] | | |

| Exploration | | | [removed: 24,403] [added: 3,438] | | | | | | [removed: 5,484] [added: 24,403] | | | | | | [removed: 7,223] [added: 5,484] | | |

| Selling, general and administrative | | | [removed: 196,315] [added: 252,645] | | | | | | [removed: 174,769] [added: 196,315] | | | | | | [removed: 170,611] [added: 174,769] | | |

| Depreciation and depletion | | | [removed: 1,676,702] [added: 1,665,962] | | | | | | [removed: 1,393,465] [added: 1,676,702] | | | | | | [removed: 1,538,745] [added: 1,393,465] | | |

| Amortization of intangible assets | | | — | | | | | | [removed: 26,006] [added: —] | | | | | | [removed: 35,916] [added: 26,006] | | |

| (Gain) loss/impairment on sale/exchange of long-lived assets | | | [removed: (21,124)] [added: (8,446)] | | | | | | [removed: 100,729] [added: (21,124)] | | | | | | [removed: 1,138,287] [added: 100,729] | | |

| Impairment of [removed: intangible] [added: contract] and other assets | | | [removed: —] [added: 214,195] | | | | | | [removed: 34,694] [added: —] | | | | | | [removed: 15,411] [added: 34,694] | | |

| Impairment and expiration of leases | | | [removed: 311,835] [added: 176,606] | | | | | | [removed: 306,688] [added: 311,835] | | | | | | [removed: 556,424] [added: 306,688] | | |

| Other operating expenses | | | [removed: 70,063] [added: 57,331] | | | | | | [removed: 28,537] [added: 70,063] | | | | | | [removed: 199,440] [added: 28,537] | | |

| Total operating expenses | | | [removed: 4,425,638] [added: 4,779,692] | | | | | | [removed: 3,936,509] [added: 4,425,638] | | | | | | [removed: 5,568,594] [added: 3,936,509] | | |

| Operating [removed: loss] [added: income (loss)] | | | [removed: (1,360,975)] [added: 2,717,997] | | | | | | [removed: (877,666)] [added: (1,360,975)] | | | | | | [removed: (1,152,110)] [added: (877,666)] | | |

| Gain on Equitrans Share Exchange [removed: (see Note] [added: (Note] 5) | | | — | | | | | | [removed: (187,223)] [added: —] | | | | | | [removed: —] [added: (187,223)] | | |

| [removed: (Income) loss] [added: Loss (income)] from investments | | | [removed: (71,841)] [added: 4,931] | | | | | | [removed: 314,468] [added: (71,841)] | | | | | | [removed: 336,993] [added: 314,468] | | |

| Dividend and other income | | | [removed: (19,105)] [added: (11,280)] | | | | | | [removed: (35,512)] [added: (19,105)] | | | | | | [removed: (91,483)] [added: (35,512)] | | |

| Loss on debt extinguishment | | | [removed: 9,756] [added: 140,029] | | | | | | [removed: 25,435] [added: 9,756] | | | | | | [removed: —] [added: 25,435] | | |

February 16, 2023

February 16, 2023

| Interest expense | | | 249,655 | | | | | | 289,753 | | | | | | 259,268 | | |

| Income (loss) before income taxes | | | 2,334,662 | | | | | | (1,569,538) | | | | | | (1,254,102) | | |

| Income tax expense (benefit) | | | 553,720 | | | | | | (428,037) | | | | | | (295,293) | | |

| Net income (loss) | | | 1,780,942 | | | | | | (1,141,501) | | | | | | (958,809) | | |

| Net income (loss) attributable to EQT Corporation | | | $ | 1,770,965 | | | | | $ | (1,142,747) | | | | | $ | (958,799) | |

| Basic: | | | | | | | | | | | | | | | | | |

| Diluted (Note 1): | | | | | | | | | | | | | | | | | |

| Weighted average common stock outstanding | | | 406,495 | | | | | | 323,196 | | | | | | 260,613 | | |

| Net income (loss) attributable to EQT Corporation | | | $ | 4.38 | | | | | $ | (3.54) | | | | | $ | (3.68) | |

| Net income (loss) | | | $ | 1,780,942 | | | | | $ | (1,141,501) | | | | | $ | (958,809) | |

| Comprehensive income (loss) | | | 1,782,559 | | | | | | (1,140,757) | | | | | | (958,965) | | |

| Comprehensive income (loss) attributable to EQT Corporation | | | $ | 1,772,582 | | | | | $ | (1,142,003) | | | | | $ | (958,955) | |

| | | | 2022 | | | | | | 2021 | | |

| Cash and cash equivalents | | | $ | 1,458,644 | | | | | $ | 113,963 | |

| Current portion of debt | | | $ | 422,632 | | | | | $ | 1,060,970 | |

| Total current liabilities | | | 3,732,220 | | | | | | 5,186,241 | | |

| Total liabilities | | | 11,456,598 | | | | | | 11,636,389 | | |

| Total common shareholders' equity | | | 11,172,474 | | | | | | 9,954,763 | | |

| Total equity | | | 11,213,328 | | | | | | 9,970,999 | | |

| | | | 2022 | | | | | | 2021 | | | | | | 2020 | | |

| Net income (loss) | | | $ | 1,780,942 | | | | | $ | (1,141,501) | | | | | $ | (958,809) | |

| Deferred income tax expense (benefit) | | | 534,612 | | | | | | (427,470) | | | | | | (152,275) | | |

| Depreciation and depletion | | | 1,665,962 | | | | | | 1,676,702 | | | | | | 1,393,465 | | |

| Amortization of intangible assets | | | — | | | | | | — | | | | | | 26,006 | | |

| Loss (income) from investments | | | 4,931 | | | | | | (71,841) | | | | | | 314,468 | | |

| Loss on debt extinguishment | | | 140,029 | | | | | | 9,756 | | | | | | 25,435 | | |

| Distribution of earnings from equity method investment | | | 50,220 | | | | | | 14,911 | | | | | | — | | |

| Deposit on acquisition (Note 6) | | | (150,000) | | | | | | — | | | | | | — | | |

| Contribution from noncontrolling interest | | | 15,000 | | | | | | 7,500 | | | | | | 7,500 | | |

| Distribution to noncontrolling interest | | | (11,592) | | | | | | — | | | | | | — | | |

| Net loss | | | | | | | | | | | | | | | | | | | | | (958,799) | | | | | | | | | | | | (10) | | | | | | (958,809) | | |

| Capped Call Transactions (Note 10) | | | | | | | | | (32,500) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (32,500) | | |

| Net (loss) income | | | | | | | | | | | | | | | | | | | | | (1,142,747) | | | | | | | | | | | | 1,246 | | | | | | (1,141,501) | | |

| Net income | | | | | | | | | | | | | | | | | | | | | 1,770,965 | | | | | | | | | | | | 9,977 | | | | | | 1,780,942 | | |

| Dividends ($0.55 per share) | | | | | | | | | | | | | | | | | | | | | (203,629) | | | | | | | | | | | | | | | | | | (203,629) | | |

| Share-based compensation plans | | | 2,100 | | | | | | 23,671 | | | | | | 18,046 | | | | | | | | | | | | | | | | | | | | | | | | 41,717 | | |

| Convertible Notes settlements (Note 10) | | | 4 | | | | | | 63 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 63 | | |

| Repurchase and retirement of common stock | | | (13,140) | | | | | | (203,664) | | | | | | | | | | | | (189,358) | | | | | | | | | | | | | | | | | | (393,022) | | |

Valuation of Acquired Natural Gas and Oil Properties

| *Description of the Matter* | | | As described in Note 6 to the consolidated financial statements, on July 21, 2021, the Company completed the acquisition of Alta Marcellus Development, LLC and ARD Operating, LLC and subsidiaries. The Company's accounting for the acquisition included determining the fair value of the acquired natural gas and oil properties. The determination of fair value of the acquired natural gas and oil properties included significant judgment and assumptions by management, including future commodity prices, anticipated production volumes, future operating and development costs, and a weighted average cost of capital (WACC). Auditing the Company's valuation of acquired natural gas and oil properties involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above about future market and economic conditions. In addition, certain of the assumptions developed by the Company’s internal engineers in conjunction with the reserve estimates described in the preceding critical audit matter are used as inputs in the cash flow model. | | |

| *How We Addressed the Matter in Our Audit* | | | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company's process to estimate fair value for the acquired natural gas and oil properties. For example, we tested controls over management's assessment of the appropriateness of the significant assumptions that are inputs to the fair value calculation and management’s review of the valuation model. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff, the independent engineers used to audit the estimates, and the external valuation specialist used to assist with the determination of the fair value of certain acquired assets. Our testing of the Company’s estimate of fair value of the acquired natural gas and oil properties included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit effort involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions described above used to develop the fair value estimate. We evaluated the reasonableness of management's assumptions by comparing the key market-related assumptions (including future natural gas prices and WACC rates) used in the cash flow model to external market and third-party data and anticipated production volumes to the reserve estimates audited by the independent engineers. | | |

| Interest expense | | | 308,903 | | | | | | 271,200 | | | | | | 199,851 | | |

| Loss before income taxes | | | (1,588,688) | | | | | | (1,266,034) | | | | | | (1,597,471) | | |

| Net loss | | | (1,154,513) | | | | | | (967,176) | | | | | | (1,221,695) | | |

| Net loss | | | $ | (1,154,513) | | | | | $ | (967,176) | | | | | $ | (1,221,695) | |

| Net change in interest rate cash flow hedges, net of tax: $210 in 2019 | | | — | | | | | | — | | | | | | 387 | | |

| Change in accounting principle | | | — | | | | | | — | | | | | | (496) | | |

| Other comprehensive income (loss) | | | 744 | | | | | | (156) | | | | | | 207 | | |

| Comprehensive loss | | | (1,153,769) | | | | | | (967,332) | | | | | | (1,221,488) | | |

| Comprehensive loss attributable to EQT Corporation | | | $ | (1,155,015) | | | | | $ | (967,322) | | | | | $ | (1,221,488) | |

| | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| Total current liabilities | | | 5,080,171 | | | | | | 1,762,410 | | |

| Total liabilities | | | 11,561,625 | | | | | | 8,850,739 | | |

| Total common shareholders' equity | | | 10,029,527 | | | | | | 9,255,240 | | |

| Total equity | | | 10,045,763 | | | | | | 9,262,730 | | |

| Deferred income tax benefit | | | (433,608) | | | | | | (155,840) | | | | | | (275,063) | | |

| Repayment of credit facility borrowings | | | (8,386,000) | | | | | | (3,112,250) | | | | | | (3,484,750) | | |

| Cash paid for taxes related to net settlement of share-based incentive awards | | | (3,845) | | | | | | (596) | | | | | | (7,224) | | |

| Cash and cash equivalents at beginning of year | | | 18,210 | | | | | | 4,596 | | | | | | 3,487 | | |

| Balance at December 31, 2018 | | | 254,472 | | | | | | $ | 7,828,554 | | | | | $ | (49,194) | | | | | $ | 3,184,275 | | | | | $ | (5,406) | | | | | $ | — | | | | | $ | 10,958,229 | |

| Net loss | | | | | | | | | | | | | | | | | | | | | (1,221,695) | | | | | | | | | | | | | | | | | | (1,221,695) | | |

| Net change in interest rate cash flow hedges, net of tax: $210 | | | | | | | | | | | | | | | | | | | | | | | | | | | 387 | | | | | | | | | | | | 387 | | |

| Dividends ($0.12 per share) | | | | | | | | | | | | | | | | | | | | | (30,655) | | | | | | | | | | | | | | | | | | (30,655) | | |

| Share-based compensation plans | | | 921 | | | | | | 6,355 | | | | | | 16,687 | | | | | | | | | | | | | | | | | | | | | | | | 23,042 | | |

| Change in accounting principle | | | | | | | | | | | | | | | | | | | | | 496 | | | | | | (496) | | | | | | | | | | | | — | | |

| Distribution of Equitrans Midstream Corporation (see Note 9) | | | | | | | | | (2,234) | | | | | | | | | | | | 93,123 | | | | | | | | | | | | | | | | | | 90,889 | | |

| Other | | | (222) | | | | | | (14,470) | | | | | | | | | | | | (2,455) | | | | | | | | | | | | | | | | | | (16,925) | | |

| Equity component of convertible senior notes (see Note 10) | | | | | | | | | 63,645 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 63,645 | | |

| Net (loss) income | | | | | | | | | | | | | | | | | | | | | (1,155,759) | | | | | | | | | | | | 1,246 | | | | | | (1,154,513) | | |

Common shares authorized: 320,000 at December 31, 2019 and 640,000 at December 31, 2020 and 2021.

In 2020, the Company entered into a partnership with a third-party investor (the Partnership).

Because the Partnership is a variable interest entity that the Company has the power to direct the activities that most significantly affect the Partnership's economic performance, the Company consolidates the Partnership.

See "Investment in Equitrans Midstream" and "Equity Method Investments" for discussion of the Company's accounting of its investment in equity securities and equity method investments.

During the fourth quarter of 2019, there were indicators that the carrying values of certain of the Company's properties may be impaired due to depressed natural gas prices and changes in the Company's development strategy, including the Company's contemplation of a potential asset divestiture of certain of its non-strategic exploration and production assets.

As a result of the 2019 impairment evaluation, the Company recorded total impairment of $1,124.4 million, of which $1,035.7 million was associated with the Company's non-strategic assets located in the Ohio Utica and $88.7 million was associated with the Company's Pennsylvania and West Virginia Utica assets.

The impairment was recorded as a reduction to the assets' carrying values to their estimated fair values of approximately $839.4 million with respect to the Company's Ohio Utica assets and approximately $26.8 million with respect to the Company's Pennsylvania and West Virginia Utica assets.

Key assumptions included in the calculation of the fair value included the following: (i) reserves, including risk adjustments for probable reserves; (ii) future commodity prices; (iii) to the extent available, market-based indicators of fair value, including estimated proceeds that could be realized upon a potential disposition; (iv) production rates based on the Company's experience with similar properties; (v) future operating and development costs; (vi) inflation and (vii) a market-based weighted average cost of capital.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, [removed: 2021.][added: 2022.]

Based on this assessment, management concluded that we maintained effective internal control over financial reporting as of December 31, [removed: 2021.][added: 2022.]

There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of [removed: 2021] [added: 2022] that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The following information is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2022] [added: 2023] annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of our fiscal year ended December 31, [removed: 2021:][added: 2022:]

Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Annual Report on Form 10-K under the caption "Information about our Executive Officers (as of February [removed: 10, 2022)."][added: 16, 2023)."]

The following information is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2022] [added: 2023] annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of our fiscal year ended December 31, [removed: 2021:][added: 2022:]

Information required by Item 403 of Regulation S-K with respect to stock ownership of significant shareholders, directors and executive officers is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2022] [added: 2023] annual meeting of shareholders, which is expected to be filed with the SEC within 120 days after the close of our fiscal year ended December 31, [removed: 2021.][added: 2022.]

The following table and related footnotes provide information as of December 31, [removed: 2021] [added: 2022] with respect to shares of our common stock that may be issued under our existing equity compensation plans, including the 2020 Long-Term Incentive Plan (2020 LTIP), 2019 Long-Term Incentive Plan (2019 LTIP), 2014 Long-Term Incentive Plan (2014 LTIP), the 2009 Long-Term Incentive Plan (2009 LTIP), the 2008 Employee Stock Purchase Plan (2008 ESPP), and the 2005 Directors' Deferred Compensation Plan (2005 DDCP):

| Equity Compensation Plans Not Approved by Shareholders (5) | | | | | | [removed: 51,151] [added: 52,518] | | | (6) | | | N/A | | | | | | [removed: 122,142] [added: 115,089] | | | (7) | | |

(2)Consists of (i) [removed: 1,844,520] [added: 3,155,055] shares subject to outstanding performance awards under the 2020 LTIP, inclusive of dividend reinvestments thereon (counted at a 2X multiple assuming maximum performance is achieved under the awards (representing [removed: 922,260] [added: 1,519,178] *target* awards and dividend reinvestments thereon)), (ii) [removed: 109,966] [added: 167,621] shares subject to outstanding directors' deferred stock units under the 2020 LTIP, inclusive of dividend reinvestments thereon, (iii) [removed: 2,053,512] [added: 2,076,527] shares subject to outstanding performance awards under the 2019 LTIP, inclusive of dividend reinvestments thereon (counted at a 1.5X multiple assuming maximum performance is achieved under the awards (representing [removed: 1,369,008] [added: 1,384,351] *target* awards and dividend reinvestments thereon)), (iv) 2,240,000 shares subject to outstanding stock options and stock appreciation rights under the 2019 LTIP, (v) [removed: 39,439] [added: 40,014] shares subject to outstanding directors' deferred stock units under the 2019 LTIP, inclusive of dividend reinvestments thereon, (vi) [removed: 1,292,969 shares subject to outstanding performance awards under the 2014 LTIP, inclusive of dividend reinvestments thereon (counted at a 2.75X multiple assuming maximum performance is achieved under the awards (representing 470,170 *target and confirmed* awards and dividend reinvestments thereon)), (vii) 1,487,329] [added: 448,331] shares subject to outstanding stock options under the 2014 LTIP, [removed: (viii) 95,547] [added: (vii) 62,117] shares subject to outstanding directors' deferred stock units under the 2014 LTIP, inclusive of dividend reinvestments thereon, [removed: (ix) 866,076] [added: (viii) 250,039] shares subject to outstanding stock options under the 2009 LTIP; and [removed: (x) 17,809] [added: (ix) 9,034] shares subject to outstanding directors' deferred stock units under the 2009 LTIP, inclusive of dividend reinvestments thereon.

The weighted average remaining term of the outstanding stock options and stock appreciation rights was [removed: 4.2] [added: 3.8] years and [removed: 8.0] [added: 7.0] years, respectively, as of December 31, [removed: 2021.][added: 2022.]

(4)Consists of (i) [removed: 4,436,758] [added: 17,832,453] shares available for future issuance under the 2020 LTIP and (ii) [removed: 241,444] [added: 201,845] shares available for future issuance under the 2008 ESPP.

As of December 31, [removed: 2021,] [added: 2022,] no shares were subject to purchase under the 2008 ESPP.

(6)Consists entirely of shares invested in the EQT [added: Corporation] common stock fund, payable in shares of common stock, allocated to non-employee directors' accounts under the 2005 DDCP as of December 31, [removed: 2021.][added: 2022.]

(7)Consists entirely of shares available for future issuance under the 2005 DDCP as of December 31, [removed: 2021.][added: 2022.]

| Equity Compensation Plans Approved by Shareholders (1) | | | | | | 8,448,738 | | | (2) | | | $ | 14.94 | | (3) | | | 18,034,298 | | | (4) | | |

| Total | | | | | | 8,501,256 | | | | | | $ | 14.94 | | | | | 18,149,387 | | | | | |

| Equity Compensation Plans Approved by Shareholders (1) | | | | | | 10,047,167 | | | (2) | | | $ | 19.80 | | (3) | | | 4,678,202 | | | (4) | | |

| Total | | | | | | 10,098,318 | | | | | | $ | 19.80 | | | | | 4,800,344 | | | | | |

Information required by Items 404 and 407(a) of Regulation S-K with respect to related person transactions and director independence is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2022] [added: 2023] annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of our fiscal year ended December 31, [removed: 2021.][added: 2022.]

Information required by Item 9(e) of Schedule 14A is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2022] [added: 2023] annual meeting of shareholders, which proxy statement is expected to be filed with the SEC within 120 days after the close of our fiscal year ended December 31, [removed: 2021.][added: 2022.]

| | | | | | | Statements of Consolidated Operations | | | [removed: [67](#ib6b2fe1565e24737983a625bb9fea3f6_64)] [added: [67](#i4ae3a35ac7604788a4cf429083eb6d7f_67)] | | |

| | | | | | | Statements of Consolidated Comprehensive Loss | | | [removed: [68](#ib6b2fe1565e24737983a625bb9fea3f6_70)] [added: [68](#i4ae3a35ac7604788a4cf429083eb6d7f_73)] | | |

| | | | | | | Consolidated Balance Sheets | | | [removed: [69](#ib6b2fe1565e24737983a625bb9fea3f6_73)] [added: [69](#i4ae3a35ac7604788a4cf429083eb6d7f_76)] | | |

| | | | | | | Statements of Consolidated Cash Flows | | | [removed: [70](#ib6b2fe1565e24737983a625bb9fea3f6_76)] [added: [70](#i4ae3a35ac7604788a4cf429083eb6d7f_79)] | | |

| | | | | | | Statements of Consolidated Equity | | | [removed: [71](#ib6b2fe1565e24737983a625bb9fea3f6_79)] [added: [71](#i4ae3a35ac7604788a4cf429083eb6d7f_82)] | | |

| | | | | | | Notes to the Consolidated Financial Statements | | | [removed: [72](#ib6b2fe1565e24737983a625bb9fea3f6_82)] [added: [72](#i4ae3a35ac7604788a4cf429083eb6d7f_85)] | | |

| | | | | | | Schedule II – Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, [removed: 2021] [added: 2022] | | | | | |

FOR THE THREE YEARS ENDED DECEMBER 31, [removed: 2021][added: 2022]

| [removed: [2.01](http://www.sec.gov/Archives/edgar/data/33213/000110465921062688/tm2113945d2_ex2-1.htm)] [added: [2.01(a)](https://www.sec.gov/Archives/edgar/data/33213/000110465922098267/tm2225319d1_ex2-1.htm)] | | | | | | [removed: Membership Interest] Purchase Agreement, dated [removed: May 5, 2021,] [added: September 6, 2022,] among [removed: Alta Resources Development, LLC, Alta Marcellus Development,] [added: THQ Appalachia I,] LLC, [removed: ARD Operating,] [added: THQ-XcL Holdings I,] LLC, [added: the subsidiaries of the foregoing entities named on the signature pages thereto,] EQT [removed: Acquisition HoldCo LLC] [added: Production Company] and EQT Corporation. | | | | | | Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on [removed: May] [added: September] 7, [removed: 2021.] [added: 2022.] | | |

| [removed: [4.01](https://www.sec.gov/Archives/edgar/data/33213/000003321322000007/ex40112312021eqt.htm)] [added: [4.01](http://www.sec.gov/Archives/edgar/data/33213/000003321322000007/ex40112312021eqt.htm)] | | | | | | Description of Capital Stock. | | | | | | [removed: Filed herewith as] [added: Incorporated herein by reference to] Exhibit [removed: 4.01.] [added: 4.01 to Form 10-K (#001-3551) for the year ended December 31, 2021.] | | |

| [removed: [4.02(](http://www.sec.gov/Archives/edgar/data/33213/000110465908043232/a08-16443_13ex4d01g.htm)[e](http://www.sec.gov/Archives/edgar/data/33213/000110465908043232/a08-16443_13ex4d01g.htm)[)](http://www.sec.gov/Archives/edgar/data/33213/000110465908043232/a08-16443_13ex4d01g.htm)] [added: [4.02(e)](http://www.sec.gov/Archives/edgar/data/33213/000110465908043232/a08-16443_13ex4d01g.htm)] | | | | | | Second Supplemental Indenture, dated June 30, 2008, between EQT Corporation, Equitable Resources, Inc., and Deutsche Bank Trust Company Americas, as trustee, pursuant to which EQT Corporation assumed the obligations of Equitable Resources, Inc. under the related Indenture. | | | | | | Incorporated herein by reference to Exhibit 4.01(g) to Form 8-K (#001-3551) filed on July 1, 2008. | | |

| [removed: [4.04(d)](http://www.sec.gov/Archives/edgar/data/33213/000110465917060857/a17-22759_2ex4d7.htm)] [added: [4.04(d)](http://www.sec.gov/Archives/edgar/data/33213/000110465917060857/a17-22759_2ex4d9.htm)] | | | | | | [removed: Seventh] [added: Eighth] Supplemental Indenture, dated October 4, 2017, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the [removed: 3.000%] [added: 3.900%] Senior Notes due [removed: 2022] [added: 2027] were issued. | | | | | | Incorporated herein by reference to Exhibit [removed: 4.7] [added: 4.9] to Form 8-K (#001-3551) filed on October 4, 2017. | | |

| [removed: [4.04(e)](http://www.sec.gov/Archives/edgar/data/33213/000110465917060857/a17-22759_2ex4d9.htm)] [added: [4.04(j)](http://www.sec.gov/Archives/edgar/data/33213/000110465922105842/tm2227180d1_ex4-3.htm)] | | | | | | [removed: Eighth] [added: Fourteenth] Supplemental Indenture, dated October 4, [removed: 2017,] [added: 2022,] between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the [removed: 3.900%] [added: 5.678%] Senior Notes due [removed: 2027] [added: 2025] were issued. | | | | | | Incorporated herein by reference to Exhibit [removed: 4.9] [added: 4.3] to Form 8-K (#001-3551) filed on October 4, [removed: 2017.] [added: 2022.] | | |

| [removed: [4.04(f)](http://www.sec.gov/Archives/edgar/data/33213/000110465920005572/tm201877d5_ex4-3.htm)] [added: [4.04(e)](http://www.sec.gov/Archives/edgar/data/33213/000110465920005572/tm201877d5_ex4-3.htm)] | | | | | | Ninth Supplemental Indenture, dated January 21, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 6.125% Senior Notes due 2025 were issued. | | | | | | Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on January 21, 2020. | | |

| [removed: [4.04(g)](http://www.sec.gov/Archives/edgar/data/33213/000110465920005572/tm201877d5_ex4-5.htm)] [added: [4.04(f)](http://www.sec.gov/Archives/edgar/data/33213/000110465920005572/tm201877d5_ex4-5.htm)] | | | | | | Tenth Supplemental Indenture, dated January 21, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 7.000% Senior Notes due 2030 were issued. | | | | | | Incorporated herein by reference to Exhibit 4.5 to Form 8-K (#001-3551) filed on January 21, 2020. | | |

| [removed: [4.04(h)](http://www.sec.gov/Archives/edgar/data/33213/000110465920125802/tm2036041d1_ex4-3.htm)] [added: [4.04(g)](http://www.sec.gov/Archives/edgar/data/33213/000110465920125802/tm2036041d1_ex4-3.htm)] | | | | | | Eleventh Supplemental Indenture, dated November 16, 2020, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 5.00% Senior Notes due 2029 were issued. | | | | | | Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on November 16, 2020. | | |

| [removed: [4.04(i)](http://www.sec.gov/Archives/edgar/data/33213/000110465921068869/tm2114643d6_ex4-3.htm)] [added: [4.04(h)](http://www.sec.gov/Archives/edgar/data/33213/000110465921068869/tm2114643d6_ex4-3.htm)] | | | | | | Twelfth Supplemental Indenture, dated May 17, 2021, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 3.125% Senior Notes due 2026 were issued. | | | | | | Incorporated herein by reference to Exhibit 4.3 to Form 8-K (#001-3551) filed on May 18, 2021. | | |

| [removed: [4.04(j)](http://www.sec.gov/Archives/edgar/data/33213/000110465921068869/tm2114643d6_ex4-4.htm)] [added: [4.04(i)](http://www.sec.gov/Archives/edgar/data/33213/000110465921068869/tm2114643d6_ex4-4.htm)] | | | | | | Thirteenth Supplemental Indenture, dated May 17, 2021, between EQT Corporation and The Bank of New York Mellon, as trustee, pursuant to which the 3.625% Senior Notes due 2031 were issued. | | | | | | Incorporated herein by reference to Exhibit 4.4 to Form 8-K (#001-3551) filed on May 18, 2021. | | |

| [removed: [10.01(a)](http://www.sec.gov/Archives/edgar/data/33213/000110465917049095/a17-18795_1ex10d1.htm)] [added: [10.01](http://www.sec.gov/Archives/edgar/data/33213/000110465922075309/tm2219570d1_ex10-1.htm)] | | | | | | [removed: Second] [added: Third] Amended and Restated Credit Agreement, dated [removed: July 31, 2017,] [added: June 28, 2022,] among EQT Corporation, PNC Bank, National Association, as administrative agent, swing line lender and [removed: an] L/C [removed: issuer] [added: issuer,] and the other lenders party thereto. | | | | | | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on [removed: August 3, 2017.] [added: June 28, 2022.] | | |

| [removed: [10.01(b)](http://www.sec.gov/Archives/edgar/data/33213/000110465921054672/tm2113945d1_ex10-1.htm)] [added: [10.02(b)](http://www.sec.gov/Archives/edgar/data/33213/000110465922129998/tm2233358d1_ex10-1.htm)] | | | | | | [removed: Extension Agreement and] First Amendment to [removed: Second Amended and Restated] Credit Agreement, dated [removed: April] [added: December] 23, [removed: 2021,] [added: 2022,] among EQT Corporation, PNC Bank, National Association, as administrative agent, and [removed: each lender] [added: the other lenders] party thereto. | | | | | | Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-3551) filed on [removed: April 26, 2021.] [added: December 27, 2022.] | | |