EQT (EQT) 10-K risk factor changes: FY2023 vs FY2022

Risks Associated with Natural Gas [removed: Drilling] [added: Drilling, Transmission and Processing] Operations

Many factors may curtail, delay or cancel our scheduled drilling projects, [added: or the development schedule of wells which we do not operate but in which we have a working interest (referred to as non-operated wells),] including the following:

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

Any of these risks can cause a delay in our development program or [added: the scheduled development of non-operated wells in which we have a working interest, or] result in substantial financial losses, personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

We are subject to risks associated with the operation of our [removed: wells] [added: wells, pipelines] and facilities.

Our business is subject to all of the inherent hazards and risks normally incidental to drilling for, producing, [removed: transporting] [added: transporting, storing, processing, gathering] and [removed: storing] [added: compressing] 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, wastewater, toxic gases or other pollutants into the environment, especially those that reach surface water or groundwater; inadvertent third-party damage to our assets; and natural disasters.

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

Growing geopolitical instability and armed conflicts (including [removed: the armed conflict] between Russia and [removed: Ukraine)] [added: Ukraine and in the Middle East)] 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 [removed: cyber attacks,] [added: cyber-attacks,] and, if infrastructure integral to our operations is destroyed or damaged, we may experience a significant disruption in our operations.

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

Approximately [removed: 6%] [added: 7%] of our net undeveloped acres are subject to leases that could expire over the next three years.

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

For the years ended December 31, [removed: 2022, 2021] [added: 2023, 2022] and [removed: 2020,] [added: 2021,] we recorded impairment and expiration of leases of [removed: $176.6] [added: $109.4] million, [removed: $311.8] [added: $176.6] million and [removed: $306.7] [added: $311.8] million, respectively.

We may incur losses as a result of title defects in the properties in which we [removed: invest.][added: invest or the loss of certain leasehold or other rights related to our midstream activities.]

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

The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas, NGLs and [removed: crude] oil reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas, NGLs and [removed: crude] oil reserves.

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

We review the carrying values of our [removed: proved oil and gas properties] [added: assets] for indications of impairment when events or circumstances indicate that the remaining carrying value may not be recoverable.

[removed: Proved oil and] gas properties that have carrying amounts in excess of estimated future cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.

See "Critical Accounting [removed: 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 [added: significant] accounting policies and [removed: significant] assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

Because our production and reserves predominantly consist of natural gas (approximately [removed: 94%] [added: 93%] of our equivalent proved developed reserves), changes in natural gas prices have significantly greater impact on our financial results than oil prices.

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of [removed: $9.85] [added: $3.78] per MMBtu to a low of [removed: $3.46] [added: $1.74] per MMBtu between the period from January 1, [removed: 2022] [added: 2023] through December 31, [removed: 2022,] [added: 2023,] and the daily spot prices for NYMEX West Texas Intermediate [removed: crude] oil ranged from a high of [removed: $123.64] [added: $93.67] per barrel to a low of [removed: $71.05] [added: $66.61] per barrel during the same period.

We expect commodity price volatility to continue or increase in the future due to rising macroeconomic uncertainty and geopolitical [removed: tensions, including the Russian invasion of Ukraine, which began in February 2022 and has put upward pressure on natural gas and oil prices.][added: tensions.]

[added: 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.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues (including continued hostilities between Russia and [removed: Ukraine),] [added: Ukraine as well as other conflicts, including in the Middle East),] 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.

[removed: 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.

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

Our [removed: exploration and production] operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms.

We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas, NGLs and oil [removed: reserves.][added: reserves, as well as processing facilities, pipelines and related infrastructure.]

We typically fund our capital expenditures with existing cash and cash generated by operations and, to the extent our capital expenditures exceed our cash resources, from borrowings under our [added: revolving] credit facility and other external sources of capital.

If we do not have sufficient borrowing availability under our [added: revolving] credit facility, we may seek alternate debt or equity financing, sell assets or reduce our capital expenditures.

- our ability to access the public or private capital markets or borrow under our [added: revolving] credit facility.

If our cash flows from operations or the borrowing capacity under our [added: revolving] credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.

As of December 31, [removed: 2022,] [added: 2023,] our senior notes were rated [removed: "Ba1"] [added: "Baa3"] with a [removed: "positive"] [added: "stable"] outlook by Moody's Investors Services (Moody's), [removed: "BBB-"] [added: "BBB–"] with a "stable" outlook by Standard & Poor's Ratings Service (S&P) and [removed: "BBB-"] [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 our [added: revolving credit facility and] Term Loan Facility (defined in Note [removed: 10] [added: 8] to the Consolidated Financial 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 [removed: 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: 2022,] [added: 2023,] we had approximately [removed: $5.7] [added: $5.8] billion of debt outstanding, and we may incur additional indebtedness in the future.

- limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making certain [removed: investments,] [added: investments] and paying dividends;

If the price that we receive for our natural gas, NGLs and oil production deteriorates from current levels [removed: or] [added: and] continues for an extended period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance.

In addition, we are exposed to credit risk related to our [added: revolving] credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing line of credit if it experiences liquidity problems.

Additionally, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest.

Adjustments to our planned development schedule or the development schedule of non-operated wells in which we have a working interest could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

infrastructure, such as processing plants, compressor stations and pipelines.

Additionally, our investment in midstream infrastructure development and maintenance programs is intended, among other items, to connect our wells to other existing gathering and transmission pipelines and can involve significant risks, including those relating to timing, cost overruns and operational efficiency.

Significant portions of our natural gas production are dependent on a small number of key compression and processing stations.

An operational issue at any of those stations would materially impact our production, cash flow and results of operation.

Potential physical effects of climate change could disrupt our production, transmission and processing activities, cause us to incur significant costs in preparing for or responding to those effects, or otherwise adversely affect our business.

Potential adverse effects could include disruption of our production activities; delays in getting our produced natural gas and NGLs to market or possibly shut-in as a result of physical damage to pipelines, other midstream infrastructure and processing facilities; increases in our costs of operation or reductions in the efficiency of our operations; reduced availability of electrical power, road accessibility, and transportation facilities; impacts on our personnel, supply chain, distribution chain or customers; and potentially increased costs for insurance coverages in the aftermath of such effects.

Such physical effects could also adversely affect or delay demand for our products or cause us to incur significant costs in preparing for, or responding to, the effects of climatic or weather events themselves.

Further, energy demand could increase or decrease as a result of extreme weather conditions.

A decrease in energy use due to weather or climatic changes may affect our financial condition through decreased revenues.

Any one of these factors has the potential to have a material adverse effect on our business, financial condition, results of operations, and cash flow.

Our ability to mitigate the physical impacts of adverse weather conditions depends in part upon our disaster preparedness and response along with our business continuity planning.

Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices; the

Additionally, most of the land on which our midstream systems have been constructed is not owned in fee by us; rather, the properties are held by surface use agreements, rights-of-way or other easement rights.

We are, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate.

We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time.

Our loss of these rights, through our inability to renew the right-of-way or for other reasons, could materially adversely affect our business, financial condition, results of operations and cash flows.

of productive wells that perform below expectations or that do not produce sufficient revenues to return a profit.

Proved oil and

See "Critical Accounting 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 significant accounting policies and assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

Additionally, in recent years, volatility in natural gas prices and prolonged periods of high market prices for natural gas have led to calls by certain politicians to impose a windfall profits tax on natural gas producers, limit or prohibit the volume of LNG exports out of the United States and similar restrictive regulations on natural gas development and sales.

While no such regulations have been passed in the United States, continued natural gas price volatility or prolonged high natural gas prices could result in the imposition of certain regulations directed at driving down the market price for natural gas.

In the event such regulations are adopted, the price at which we sell our natural gas may be negatively impacted, thereby impacting our sales volume and operating revenues.

Global economic conditions, geopolitical issues and inflation

Developments related to climate change may expedite a transition away from the use of carbon-intensive sources for energy generation and products derived from certain fossil fuels, which could have a material and adverse effect on us if we are not able to demonstrate that our products align with a low-carbon transition.

Governmental and regulatory bodies, investors, consumers, industry participants and other stakeholders have been increasingly focused on combating the effects of climate change.

This focus, together with changes in consumer, industrial and commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, and the use of products manufactured with, or powered by, fossil fuels, has led to, and in the long-term is anticipated to continue to result in, (i) the enactment of climate change-related regulations, policies and initiatives, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy, and (iii) increased consumer, industrial and commercial demand for low-carbon energy sources and products manufactured with, or powered by, demonstrably low carbon-intensive sources.

This has in turn led to increased scrutiny over the carbon-intensity of various fossil fuels, including the natural gas and NGLs that we produce and sell.

If we are not able to demonstrate that our products align with a transition to a low-carbon economy, the demand and prices for our products could be negatively impacted depending on the pace of such transition and potential future demands for low-carbon products.

Such developments may also adversely impact, among other things, the availability of third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy.

Climate change-related developments may also impact the market prices of, or our access to, raw materials such as energy and water and therefore result in increased costs to our business.

Further, there have been efforts in recent years to influence the investment community, including investment advisors, insurance companies, and certain sovereign wealth, pension and endowment funds and other groups, by promoting divestment of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves.

Financial institutions may elect in the future to shift some or all of their investment into non-fossil fuel related sectors.

There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector.

Certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities.

Institutional lenders who provide financing to energy companies have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding.

Ultimately, the foregoing factors could make it more difficult to secure funding for exploration and production activities or adversely impact the cost of capital for both us and our customers, and could thereby adversely affect the demand and price of our securities.

Limitation of investments in and financings for energy companies could also result in the restriction, delay or cancellation of infrastructure projects and energy production activities.

Finally, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law or alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customers.

We also face various

expiration of a lease term approaches and drilling activity has not commenced.

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

In addition, to the

In December 2021, we outlined a leverage and debt retirement strategy with the goal of retiring a significant amount of our total debt by the end of 2023 (our Debt Retirement Plan).

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

Opposition toward oil and natural gas drilling and development activities generally has been growing globally and is particularly pronounced in the U.S., and companies in our industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability and business practices.

In February 2021, the U.S. formally rejoined the Paris Agreement, an international treaty signed by nearly 200 counties which calls for countries to set their own GHG emissions targets and to be transparent about the measures they will implement to achieve their GHG emissions targets.

In furtherance of the objectives of the Paris Agreement, in April 2021, the Biden Administration announced goals aimed at reducing the U.S.’s GHG emissions by 50-52% (compared to 2005 levels) by 2030.

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

In June 2021, President Biden signed legislation reinstituting regulations which were previously repealed by the Trump Administration establishing NSPS for methane and VOC from new and modified oil and natural gas production and natural gas processing and transmission facilities.

Additionally, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions.

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis.

Furthermore, in November 2021, the EPA announced proposed rules expanding upon the NSPS rule which would establish standards for existing wells, impose more frequent and stringent leak monitoring, and mandate that all pneumatic controllers have zero emissions.

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.

In October 2019, Pennsylvania Governor Tom Wolf signed an Executive Order directing the PADEP to draft regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, with the intent of enabling Pennsylvania to join RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states.

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

Depending on the outcome of such litigation, Pennsylvania’s membership in RGGI will result in increased operating costs should we be required to purchase emission allowances in connection with our operations.

Further, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities.

While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

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.

For example, in June 2015, the EPA and the Corps issued a rule under the CWA defining the scope of the EPA's and the Corps' jurisdiction over WOTUS, which never took effect before being replaced by the NWPR in December 2019.

A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021.

In addition, in an April 2020 decision further defining the scope of the CWA, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

The Court rejected the EPA and Corps’ assertion that groundwater should be totally excluded from the CWA.

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.

Net income attributable to EQT Corporation for [removed: 2022] [added: 2023] was [removed: $1,771] [added: $1,735] million, [removed: $4.38] [added: $4.22] per diluted share, compared to [removed: net loss attributable to EQT Corporation for 2021 of $1,143] [added: $1,771] million, [removed: $3.54] [added: $4.38] per diluted [removed: share.][added: share, for 2022.]

The [removed: change] [added: decrease] was attributable primarily to [removed: increased] [added: decreased] sales of natural gas, NGLs and oil, partly offset by [removed: income tax expense, greater] [added: a gain on derivatives in 2023 compared to a] loss on [removed: derivatives, the] [added: derivatives in 2022,] impairment of [removed: our] [added: the] contract asset (discussed in Note 5 to the Consolidated Financial [removed: Statements), increased transportation and processing] [added: Statements) in 2022, decreased income tax] expense and [removed: increased] [added: a] loss on debt [removed: extinguishment.][added: extinguishment in 2022.]

Results of operations for [removed: 2022 and for] the period beginning [removed: July 21, 2021 and ending] [added: August 22, 2023 through] December 31, [removed: 2021] [added: 2023] include the results of our operation of assets acquired in the [removed: Alta] [added: Tug Hill and XcL Midstream] Acquisition.

See Note [removed: 6] [added: 8] to the Consolidated Financial Statements for further [removed: discussion.][added: discussion of our revolving credit facility.]

Our sales volume and operating expenses [removed: for 2022] [added: on a per Mcfe basis during the first half of 2023] were negatively impacted by fewer wells turned-in-line [removed: and adjustments] [added: during 2022 compared] to our [added: 2022] planned development schedule [removed: as a result of] [added: due to] third-party supply chain constraints.

[removed: Furthermore,] [added: Additionally,] certain of our commitments for demand charges under our existing long-term contracts and processing capacity are subject to consumer price index adjustments.

[removed: Additionally, while] [added: While] the prices for natural gas, NGLs and oil have historically been volatile, price volatility was especially pronounced during [removed: 2022.][added: 2022, with natural gas prices peaking in August 2022, then steadily declining into the first half of 2023.]

Our revenue, profitability, [removed: 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.

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

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

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

| NATURAL GAS | | | | | | | | | | | | [removed: | | | | | |]

| Sales volume (MMcf) | | | [removed: 1,842,044 | | | | | | 1,746,317] [added: 1,907,343] | | | | | | [removed: 1,418,774] [added: 1,842,044] | | |

| NYMEX price ($/MMBtu) | | | $ | [removed: 6.64 | | | | | $ | 3.97] [added: 2.74] | | | | | $ | [removed: 2.09] [added: 6.64] | |

| Btu uplift | | | [removed: 0.35 | | | | | | 0.20] [added: 0.14] | | | | | | [removed: 0.11] [added: 0.35] | | |

| Natural gas price ($/Mcf) | | | $ | [removed: 6.99 | | | | | $ | 4.17] [added: 2.88] | | | | | $ | [removed: 2.20] [added: 6.99] | |

| Basis ($/Mcf) (a) | | | $ | [removed: (0.77) | | | | | $ | (0.63)] [added: (0.51)] | | | | | $ | [removed: (0.47)] [added: (0.77)] | |

| Cash settled basis swaps ($/Mcf) | | | [removed: (0.02) | | | | | | (0.07)] [added: (0.03)] | | | | | | [removed: 0.05] [added: (0.02)] | | |

| Average differential, including cash settled basis swaps ($/Mcf) | | | $ | [removed: (0.79) | | | | | $ | (0.70)] [added: (0.54)] | | | | | $ | [removed: (0.42)] [added: (0.79)] | |

| Average adjusted price ($/Mcf) | | | $ | [removed: 6.20 | | | | | $ | 3.47] [added: 2.34] | | | | | $ | [removed: 1.78] [added: 6.20] | |

| Cash settled derivatives ($/Mcf) | | | [removed: (3.20) | | | | | | (1.09)] [added: 0.34] | | | | | | [removed: 0.59] [added: (3.20)] | | |

| Average natural gas price, including cash settled derivatives ($/Mcf) | | | $ | [removed: 3.00 | | | | | $ | 2.38] [added: 2.68] | | | | | $ | [removed: 2.37] [added: 3.00] | |

| Natural gas sales, including cash settled derivatives | | | $ | [removed: 5,529,963 | | | | | $ | 4,153,221] [added: 5,112,278] | | | | | $ | [removed: 3,359,583] [added: 5,529,963] | |

| LIQUIDS | | | | | | | | | | | | [removed: | | | | | |]

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

| Sales volume (MMcfe) (b) | | | [removed: 56,735 | | | | | | 64,202] [added: 64,859] | | | | | | [removed: 44,702] [added: 56,735] | | |

| Sales volume (Mbbl) | | | [removed: 9,456 | | | | | | 10,700] [added: 10,810] | | | | | | [removed: 7,451] [added: 9,456] | | |

| NGLs price ($/Bbl) | | | $ | [removed: 53.26 | | | | | $ | 44.50] [added: 36.39] | | | | | $ | [removed: 20.51] [added: 53.26] | |

| Cash settled derivatives ($/Bbl) | | | [removed: (3.91) | | | | | | (12.32)] [added: (1.27)] | | | | | | [removed: (0.12)] [added: (3.91)] | | |

| Average NGLs price, including cash settled derivatives ($/Bbl) | | | $ | [removed: 49.35 | | | | | $ | 32.18] [added: 35.12] | | | | | $ | [removed: 20.39] [added: 49.35] | |

| NGLs sales, including cash settled derivatives | | | $ | [removed: 466,664 | | | | | $ | 344,260] [added: 379,663] | | | | | $ | [removed: 151,877] [added: 466,664] | |

| Ethane: | | | | | | | | | | | | [removed: | | | | | |]

| Sales volume (MMcfe) (b) | | | [removed: 35,100 | | | | | | 37,548] [added: 34,441] | | | | | | [removed: 29,489] [added: 35,100] | | |

| Sales volume (Mbbl) | | | [removed: 5,850 | | | | | | 6,258] [added: 5,740] | | | | | | [removed: 4,914] [added: 5,850] | | |

| Ethane price ($/Bbl) | | | $ | [removed: 14.20 | | | | | $ | 8.85] [added: 6.00] | | | | | $ | [removed: 3.48] [added: 14.20] | |

| Ethane sales | | | $ | [removed: 83,096 | | | | | $ | 55,393] [added: 34,417] | | | | | $ | [removed: 17,085] [added: 83,096] | |

| Oil: | | | | | | | | | | | | [removed: | | | | | |]

| Sales volume (MMcfe) (b) | | | [removed: 6,164 | | | | | | 9,750] [added: 9,630] | | | | | | [removed: 4,827] [added: 6,164] | | |

| Sales volume (Mbbl) | | | [removed: 1,027 | | | | | | 1,625] [added: 1,605] | | | | | | [removed: 804] [added: 1,027] | | |

| Oil price ($/Bbl) | | | $ | [removed: 77.06 | | | | | $ | 56.82] [added: 59.93] | | | | | $ | [removed: 25.57] [added: 77.06] | |

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/33213/000003321323000008/eqt-20221231.htm) for the year ended December 31, 2022, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2021.

In addition, as a result of third-party supply chain constraints in 2022, we shifted the planned development of approximately 30 wells from 2022 to 2023 (the Rescheduled Wells).

All of the Rescheduled Wells were completed and turned-to-sales as of July 2023, resulting in our third quarter 2023 sales volumes returning to our normalized level of production; however, our sales volume during the second half of 2023 was negatively impacted by approximately 13 Bcfe of curtailments (inclusive of non-operated wells in which we have a working interest) principally in response to lower natural gas prices in the Appalachian Basin.

Future supply chain constraints or declines in natural gas prices may result in adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest.

Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest.

Adjustments to our 2024 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

The annual inflation rate in the United States increased rapidly during 2022, and, although the inflation rate decreased through 2023, it still remains elevated compared to the rate of inflation over the prior five years.

While the prices for certain of the raw materials and services we use in our operations have generally decreased from the peak prices experienced during 2022, we will not fully realize the benefit of such reduced prices until we enter into new contracts for such materials and services, and inflationary pressures may cause prices to fluctuate.

The second half of 2023 saw moderate increases in natural gas prices; however, on average, prices in 2023 remained lower than in 2022.

We expect commodity prices to be volatile throughout 2024 due to macroeconomic uncertainty and geopolitical tensions, including developments pertaining to Russia's invasion of Ukraine and conflicts in the Middle East.

Additionally, after several years of delays, in the third quarter of 2023, Equitrans Midstream resumed forward construction of the Mountain Valley Pipeline following the approval of federal legislation ratifying and approving all permits and authorizations necessary for the construction and initial operation of the project.

The fee structure and various conditions precedent specified in certain of our agreements with Equitrans Midstream, including but not limited to the Consolidated GGA, are tied to the date on which the Mountain Valley Pipeline is placed in service.

As a result, the timing of the date on which the Mountain Valley Pipeline is ultimately placed in service, which is outside of our control, could impact our operating results during 2024, including our operating expenses and per unit metrics, average differential and any payments required to settle the Henry Hub Cash Bonus (defined and described in Note 3 to the Consolidated Financial Statements), if required.

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

| | | | 2023 | | | | | | 2022 | | |

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

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

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

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

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

| | | | 2023 | | | | | | 2022 | | |

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

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

| Average realized price ($/Mcfe) | | | $ | 2.79 | | | | | $ | 3.17 | |

| Sales volume (MMcfe) | | | 2,016,273 | | | | | | 1,940,043 | | | | | | 76,230 | | | | | | 3.9 | | |

| Gain (loss) on derivatives | | | 1,838,941 | | | | | | (4,642,932) | | | | | | 6,481,873 | | | | | | (139.6) | | |

| Total operating revenues | | | $ | 6,908,923 | | | | | $ | 7,497,689 | | | | | $ | (588,766) | | | | | (7.9) | | |

The following table presents the composition of net cash settlements that we received (paid) on derivatives.

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

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

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

| | | | 2023 | | | | | | 2022 | | |

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

| | | | (Thousands) | | | | | | | | |

| Net cash settlements received (paid) on NYMEX natural gas hedge positions | | | $ | 976,432 | | | | | $ | (5,855,959) | |

| Net cash settlements paid on basis and liquids hedge positions | | | (75,782) | | | | | | (71,739) | | |

| Net cash settlements received (paid) on derivatives | | | $ | 900,650 | | | | | $ | (5,927,698) | |

Net loss attributable to EQT Corporation for 2021 was $1,143 million, $3.54 per diluted share, compared to net loss attributable to EQT Corporation for 2020 of $959 million, $3.68 per diluted share.

The change was attributable primarily to the loss on derivatives, increased depreciation and depletion, increased transportation and processing and the gain on the Equitrans Share Exchange (defined and discussed in Note 5 to the Consolidated Financial Statements) recognized in 2020, partly offset by increased sales of natural gas, NGLs and oil, the income from investments, higher income tax benefit and the gain on sale/exchange of long-lived assets.

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.

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.

revenues, a non-GAAP supplemental financial measure.

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

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

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

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

| Sales volume by shale (MMcfe): | | | | | | | | | | | | | | | | | | | | | | | |

| 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) | | |

| Operating revenues: | | | | | | | | | | | | | | | | | | | | | | | |

| Loss on derivatives | | | (4,642,932) | | | | | | (3,775,042) | | | | | | (867,890) | | | | | | 23.0 | | |

| Total operating revenues | | | $ | 7,497,689 | | | | | $ | 3,064,663 | | | | | $ | 4,433,026 | | | | | 144.6 | | |

Sales volume increased primarily as a result of sales volume increases from the assets acquired in the Alta Acquisition, partly offset by natural decline of producing wells and fewer wells turned-in-line.

Sales volume for 2022 was negatively impacted by fewer wells turned-in-line as a result of third-party supply chain constraints.

Supply chain constraints and inflationary pressures may continue to impact our future operating revenues.

The assets which we intend to acquire in the pending Tug Hill and XcL Midstream Acquisition, which is subject to regulatory approvals, are currently producing approximately 800 MMcfe per day of sales volume, 20% of which is liquids sales volume.

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

| | | | 2021 | | | | | | 2020 | | | | | | Change | | | | | | % Change | | |

| Marcellus | | | 1,684,673 | | | | | | 1,314,801 | | | | | | 369,872 | | | | | | 28.1 | | |

| Ohio Utica | | | 163,775 | | | | | | 177,864 | | | | | | (14,089) | | | | | | (7.9) | | |

| Other | | | 9,369 | | | | | | 5,127 | | | | | | 4,242 | | | | | | 82.7 | | |

| Total sales volume | | | 1,857,817 | | | | | | 1,497,792 | | | | | | 360,025 | | | | | | 24.0 | | |

| Average daily sales volume (MMcfe/d) | | | 5,090 | | | | | | 4,092 | | | | | | 998 | | | | | | 24.4 | | |

| Sales of natural gas, NGLs and oil | | | $ | 6,804,020 | | | | | $ | 2,650,299 | | | | | $ | 4,153,721 | | | | | 156.7 | | |

| (Loss) gain on derivatives | | | (3,775,042) | | | | | | 400,214 | | | | | | (4,175,256) | | | | | | (1,043.3) | | |

| Net marketing services and other | | | 35,685 | | | | | | 8,330 | | | | | | 27,355 | | | | | | 328.4 | | |

| Total operating revenues | | | $ | 3,064,663 | | | | | $ | 3,058,843 | | | | | $ | 5,820 | | | | | 0.2 | | |

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

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

The 2020 Strategic Production Curtailments refers to our strategic decisions to temporarily curtail certain 2020 production.

In May 2020, we temporarily curtailed approximately 1.4 Bcf per day of gross production, equivalent to approximately 1.0 Bcf per day of net production.

In July 2020, we began a moderated approach to bring back on-line the curtailed production.

In September 2020, we curtailed approximately 0.6 Bcf per day of gross production, equivalent to approximately 0.4 Bcf per day of net production.

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

We monitor price and production levels on a continuous basis and [removed: make adjustments to] [added: adjust] quantities hedged as warranted.

A hypothetical decrease of 10% in the NYMEX natural gas price on December 31, [removed: 2022] [added: 2023] and [removed: 2021] [added: 2022] would increase the fair value of our natural gas derivative commodity instruments by approximately [removed: $727] [added: $204] million and [removed: $577] [added: $727] million, respectively.

A hypothetical increase of 10% in the NYMEX natural gas price on December 31, [removed: 2022] [added: 2023] and [removed: 2021] [added: 2022] would decrease the fair value of our natural gas derivative commodity instruments by approximately [removed: $333] [added: $482] million and [removed: $581] [added: $333] million, respectively.

For purposes of this analysis, we applied the 10% change in the NYMEX natural gas price on December 31, [removed: 2022] [added: 2023] and [removed: 2021] [added: 2022] to our natural gas derivative commodity instruments as of December 31, [removed: 2022] [added: 2023] and [removed: 2021] [added: 2022] to calculate the hypothetical change in fair value.

*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 [added: revolving] credit facility and [added: the] Term Loan Facility.

A 1% increase in interest rates [removed: on] [added: for] the borrowings under our [added: revolving] credit facility [removed: during] [added: and] the [removed: year ended December 31, 2022] [added: Term Loan Facility during 2023] would have increased interest expense by approximately [removed: $5] [added: $12.9] million.

Interest rates [removed: on] [added: for] our [added: revolving credit facility, the Term Loan Facility, our] 6.125% senior notes due 2025 and [removed: 7.00%] [added: our 7.000%] senior notes due 2030 fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch.

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

For a discussion of credit rating downgrade risk, see Item 1A., "Risk Factors – Our [removed: exploration and production] operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms." Changes in interest rates affect the fair value of our fixed rate debt.

See Note [removed: 10] [added: 8] to the Consolidated Financial Statements for further discussion of our debt and Note 4 to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value measurement of our debt.

Approximately [removed: 17%,] [added: 86%,] or [removed: $477] [added: $912] million, of our OTC derivative contracts outstanding at December 31, [removed: 2021] [added: 2023] had a positive fair value.

As of December 31, [removed: 2022,] [added: 2023,] we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts.

During [removed: the year ended December 31, 2022,] [added: 2023,] 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.

No one lender of the large group of financial institutions in the syndicate for our [added: revolving] credit facility [added: and the Term Loan Facility] holds more than 10% of the financial commitments under [removed: such] [added: either] facility.

market prices for natural gas and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.

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

fluctuate based on changes to the credit ratings assigned to our senior notes by Moody's, S&P and Fitch.

We are a natural gas production company with operations focused in the [removed: Marcellus and Utica Shales of the] Appalachian Basin.

[removed: Based] [added: As of December 31, 2023, we had 27.6 Tcfe of proved natural gas, NGLs and oil reserves across approximately 2.1 million gross acres, and, based] on average daily sales volume, we [removed: are] [added: were] the largest producer of natural gas in the United States.

By promoting a culture that prioritizes operational efficiency, [removed: technology] [added: technology, sustainability] and [removed: sustainability,] [added: safety,] we seek to continuously improve the way we produce environmentally responsible, reliable low-cost energy.

We measure sustainability through [added: consideration of] our best-in-class team and culture, [removed: ESG-focused] [added: the ESG performance of our] operations, [added: our] substantial inventory of core drilling locations and [removed: strong] [added: our investment grade] balance sheet.

We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our [removed: evolution into a modern,] digitally-enabled exploration and production business enhances our strategic advantage.

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 [removed: dividends,] [added: debt retirements, dividends and] strategic share [removed: repurchases, and debt retirements.][added: repurchases.]

Our strategy, and combo-development projects 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; [removed: the] timely [removed: verification of] midstream connectivity; and the ability to quickly respond to internal and external stimuli.

Without a [removed: modern,] digitally-connected operating model or an acreage position that enables operations of this scale, combo-development would not be possible.

[removed: ◦Repurchased $393] [added: - Repurchased $200] million of common stock, reducing our [added: outstanding] share count by [removed: 13.1] [added: 5.9] million shares.

[removed: ◦Increased] [added: - Increased] quarterly base dividend by [removed: 20%] [added: 5%] to [removed: $0.15] [added: $0.1575] per share [removed: ($0.60] [added: ($0.63] per share annualized).

[removed: ◦Paid $204] [added: - Paid $228] million in dividends to shareholders.

We expect to allocate the [added: total] planned capital expenditures as follows: approximately [removed: $1,400] [added: $1,685 million] to [removed: $1,535] [added: $1,775] million to fund reserve development, approximately [removed: $120] [added: $220 million] to [removed: $140] [added: $250] million to fund [removed: land] [added: midstream] and [removed: lease acquisitions,] [added: other infrastructure,] approximately $125 [added: million] to [removed: $160] [added: $190] million to fund [removed: other production infrastructure] [added: land] and [added: lease acquisitions,] approximately [removed: $55] [added: $70 million] to [removed: $65] [added: $80] million [removed: applied] towards capitalized [removed: overhead.][added: overhead and approximately $50 million to $55 million towards capitalized interest and other items.]

We are committed to maintaining investment grade credit [removed: metrics] [added: metrics,] and we have a goal to [removed: retire at least $4.0 billion of] [added: reduce] our [added: absolute] debt [removed: between January 1, 2022 and December 31, 2023,] [added: to $3.5 billion,] subject to the [removed: occurrence and timing of the closing of the Tug Hill and XcL Midstream Acquisition and the] overall performance of the commodity markets.

Our capital allocation plan is focused on maintaining production volumes while also returning capital to shareholders, including through our [added: quarterly cash dividend and] share repurchase program, [removed: under] [added: pursuant to] which we are authorized to repurchase [removed: up to $2.0 billion] [added: shares] of our outstanding common [removed: stock, and through our quarterly cash dividend, which is currently] [added: stock for] an [removed: annual rate] [added: aggregate purchase price] of [removed: $0.60 per share.][added: up to $2 billion, excluding fees, commissions and expenses.]

Our revenues, [removed: earnings, liquidity] [added: earnings] and [removed: ability to grow] [added: liquidity] are substantially dependent on the prices we receive for, and our ability to develop our reserves of, natural gas, NGLs and oil.

See "Critical Accounting [removed: 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 [added: significant] accounting policies and [removed: significant] assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

The following [removed: tables summarize] [added: table summarizes] our proved developed and undeveloped natural gas, NGLs and [removed: crude] oil reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by [removed: product and play.][added: product.]

| | | | Natural Gas | | | | | | NGLs and [removed: Crude] Oil | | | | | | [removed: Total] [added: Total (a)] | | |

| Proved undeveloped reserves | | | [removed: 7,284] [added: 7,609] | | | | | | [removed: 34] [added: 72] | | | | | | [removed: 7,489] [added: 8,039] | | |

| Proved developed non-producing reserves | | | [removed: 461] [added: 601] | | | | | | [removed: 109] [added: 234] | | | | | | [removed: 28] [added: 4] | | | | | | | | | | | | [removed: 598] [added: 839] | | |

| Gross proved undeveloped drilling locations | | | [removed: 256] [added: 222] | | | | | | [removed: 126] [added: 191] | | | | | | [removed: 6] [added: 4] | | | | | | | | | | | | [removed: 388] [added: 417] | | |

| Net proved undeveloped drilling locations | | | [removed: 194] [added: 174] | | | | | | [removed: 106] [added: 172] | | | | | | 1 | | | | | | | | | | | | [removed: 301] [added: 347] | | |

Our [removed: 2022] [added: 2023] total proved reserves increased by [removed: 41] [added: 2,594] Bcfe, or [removed: 0.2%,] [added: 10.4%,] compared to [removed: 2021] [added: 2022] due to extensions, discoveries and other additions of [removed: 2,495] [added: 3,412] Bcfe and acquisitions of [removed: 141] [added: 2,600] Bcfe from the [removed: 2022 Asset Acquisition (defined in Note 6 to the Consolidated Financial Statements),] [added: Tug Hill and XcL Midstream Acquisition,] partly offset by production of [removed: 1,940] [added: 2,016] Bcfe and revisions to previous estimates of [removed: 655] [added: 1,402] Bcfe.

The following table provides a [removed: rollforward] [added: roll-forward] of our proved undeveloped reserves.

| Conversions into proved developed reserves | | | [removed: (1,365)] [added: (2,561)] | | |

| Acquisition of in-place reserves | | | [removed: 141] [added: 840] | | |

| Revision of previous estimates (a) | | | [removed: (1,107)] [added: (832)] | | |

| Extensions, discoveries and other additions (b) | | | [removed: 2,077] [added: 3,103] | | |

(a)Composed of (i) negative revisions of [removed: 1,625] [added: 755] Bcfe related to proved undeveloped locations that [removed: are] [added: we] no longer [removed: expected] [added: expect] to [removed: be developed] [added: develop] as proved reserves within five years of initial booking as a result of development schedule changes, [removed: driven largely by third-party impacts, which has pushed planned completion dates into a future period from when originally planned; and] (ii) [removed: positive] [added: negative] revisions of [removed: 518] [added: 367] Bcfe due primarily to [added: revisions to type curves and commodity price change, partly offset by (iii) positive revisions of 290 Bcfe due to] changes in ownership interests.

(b)Composed of [removed: 2,077] [added: (i) 1,670] Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to [removed: 2022] [added: 2023] reserve development that expanded the number of our proven locations and additions to our five-year drilling [removed: plan.][added: plan, (ii) 1,341 Bcfe of proved undeveloped additions for previously proved undeveloped properties reclassified from unproved properties due to their addition to our five-year development plan and (iii) positive revisions of 92 Bcfe from the extension of lateral lengths of proved undeveloped reserves.]

As of December 31, [removed: 2022,] [added: 2023,] we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

| | | | [removed: 2022] [added: 2023] | | | | | | [removed: 2021] [added: 2022] | | | | | | [removed: 2020] [added: 2021] | | |

| Future net cash flow | | | $ | [removed: 87,612] [added: 19,031] | | | | | $ | [removed: 36,567] [added: 87,612] | | | | | $ | [removed: 7,543] [added: 36,567] | |

| Standardized measure of discounted future net cash flow | | | [removed: 40,065] [added: 9,262] | | | | | | [removed: 17,281] [added: 40,065] | | | | | | [removed: 3,366] [added: 17,281] | | |

| PV-10 (a) | | | [removed: 51,512] [added: 11,520] | | | | | | [removed: 21,496] [added: 51,512] | | | | | | [removed: 3,967] [added: 21,496] | | |

| Natural gas price ($/Mcf) | | | $ | [removed: 5.543] [added: 1.700] | | | | | $ | [removed: 2.694] [added: 5.543] | | | | | $ | [removed: 1.380] [added: 2.694] | |

| NGLs price ($/Bbl) | | | [removed: 38.66] [added: 28.44] | | | | | | [removed: 29.95] [added: 38.66] | | | | | | [removed: 11.97] [added: 29.95] | | |

| Oil price ($/Bbl) | | | [removed: 76.83] [added: 63.86] | | | | | | [removed: 51.57] [added: 76.83] | | | | | | [removed: 20.94] [added: 51.57] | | |

PV-10 is derived from the standardized measure of discounted future net cash flows (the Standardized Measure), which is the most directly comparable financial measure computed using [removed: U.S.] GAAP.

PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with [removed: U.S.] GAAP.

2023 Highlights

- Generated $3.2 billion of net cash provided by operating activities with an average NYMEX price of $2.74 per MMBtu.

- Retired $1.1 billion aggregate principal of debt.

- Completed the Tug Hill and XcL Midstream Acquisition (defined and discussed in Note 6 to the Consolidated Financial Statements).

- Increased total proved reserves by 2,594 Bcfe, or 10.4%, compared to 2022.

- Achieved investment grade credit rating from Moody's Investors Services, making us investment grade rated by all three credit rating agencies.

In 2024, we expect to spend approximately $2.15 billion to $2.35 billion in total capital expenditures.

Included in total planned capital expenditures is approximately $200 million to $300 million for strategic growth projects composed of approximately $70 million to $90 million for water infrastructure within reserve development, approximately $50 million to $70 million for growth projects within midstream and other infrastructure and approximately $80 million to $140 million for in-fill leasing and mineral purchases within land and lease acquisitions.

In 2024, we expect our sales volume to be 2,200 Bcfe to 2,300 Bcfe.

| | | | December 31, 2023 | | | | | | | | | | | | | | |

| Proved developed reserves | | | 18,186 | | | | | | 229 | | | | | | 19,558 | | |

| Total proved reserves | | | 25,795 | | | | | | 301 | | | | | | 27,597 | | |

(a)The Marcellus Shale comprises 91% of our total proved developed reserves, 98% of our total proved undeveloped reserves and 93% of our total proved reserves.

| | | | December 31, 2023 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Proved developed producing reserves | | | 12,855 | | | | | | 5,312 | | | | | | 552 | | | | | | | | | | | | 18,719 | | |

| Proved undeveloped reserves | | | 4,160 | | | | | | 3,864 | | | | | | 15 | | | | | | | | | | | | 8,039 | | |

| Total proved reserves | | | 17,616 | | | | | | 9,410 | | | | | | 571 | | | | | | | | | | | | 27,597 | | |

Our 2023 proved undeveloped reserves increased by 550 Bcfe, or 7.3%, compared to 2022.

| Balance at January 1, 2023 | | | 7,489 | | |

| Balance at December 31, 2023 | | | 8,039 | | |

| | | | (Millions, unless otherwise noted) | | | | | | | | | | | | | | |

| | | | 2023 | | | | | | 2022 | | | | | | 2021 | | |

| | | | December 31, 2023 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Total gross productive acreage | | | 499,183 | | | | | | 218,837 | | | | | | 53,164 | | | | | | | | | | | | 771,184 | | |

| Total gross undeveloped acreage | | | 854,790 | | | | | | 405,166 | | | | | | 112,774 | | | | | | | | | | | | 1,372,730 | | |

| Total gross acreage | | | 1,353,973 | | | | | | 624,003 | | | | | | 165,938 | | | | | | | | | | | | 2,143,914 | | |

| Total net productive acreage | | | 441,971 | | | | | | 216,255 | | | | | | 44,798 | | | | | | | | | | | | 703,024 | | |

| Total net undeveloped acreage | | | 789,925 | | | | | | 396,179 | | | | | | 102,146 | | | | | | | | | | | | 1,288,250 | | |

| Total net acreage | | | 1,231,896 | | | | | | 612,434 | | | | | | 146,944 | | | | | | | | | | | | 1,991,274 | | |

| Year Ended December 31, 2023 | | | 1,496,197 | | | | | | 435,898 | | | | | | 84,178 | | | | | | 2,016,273 | | |

| | | | December 31, 2023 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Total gross productive wells (a) | | | 3,810 | | | | | | 1,091 | | | | | | 298 | | | | | | | | | | | | 5,199 | | |

We market the majority of our NGLs.

| | | | 2023 | | | | | | 2022 | | | | | | 2021 | | |

| 2024 | | | 1,348 | | | | | | 9,150 | | |

| 2028 | | | 315 | | | | | | 3,660 | | |

| Thereafter | | | 1,840 | | | | | | 31,030 | | |

During the fourth quarter of 2023, we entered into two firm sales agreements, pursuant to which we agreed to deliver and sell to the parties thereto up to an aggregate 1.2 Bcf per day of gas using our Mountain Valley Pipeline capacity for up to ten years beginning in 2027.

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows.

In January 2023, the EPA and the Corps issued a final rule that based the definition of WOTUS on the pre-2015 definition.

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

2022 Highlights

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

- Achieved investment grade credit ratings from Fitch and S&P and upgraded to positive outlook at Moody's.

- 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.

- 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 to spend approximately $1.7 to $1.9 billion in total capital expenditures, excluding amounts attributable to noncontrolling interests and acquisitions.

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

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

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

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

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

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

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

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

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

| | | | Marcellus | | | | | | Ohio Utica | | | | | | Other | | | | | | Total | | |

| | | | (Bcfe) | | | | | | | | | | | | | | | | | | | | |

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

| Proved undeveloped reserves | | | 7,468 | | | | | | 17 | | | | | | 4 | | | | | | 7,489 | | |

| 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 | | |

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

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

| | | | (Millions) | | | | | | | | | | | | | | |

The average realized product prices weighted by production over the remaining lives of the properties would be $50.13 per barrel of oil, $27.30 per barrel of NGLs and $3.565 per Mcf of gas.

The following table summarizes our capital expenditures for reserve development.

Environmental Proceedings

*Produced Water Release, Washington County, Pennsylvania*.

In December 2021, we discovered a produced water leak associated with a Gas Processing Unit (GPU) disposal line at one of our well pad sites located in Washington County, Pennsylvania.

We self-reported the release to the PADEP spill hotline on December 4, 2021 and initiated cleanup of the released produced water.

The initial release was determined to be in excess of one barrel and we entered the remediation project into PADEP's Land Recycling and Environmental Remediation Act 2 Program (Act 2) for voluntary cleanup.

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

2022.

Site characterization of the release is ongoing and upon completion, we intend to initiate the remediation according to PADEP's Act 2 guidelines.

While we anticipate that the penalties related to this matter will exceed $300,000, we expect that the resolution of this matter will not have a material impact on our financial condition, results of operations or liquidity.

Other Legal Proceedings

*Mary Farr Secrist, et al.

v.

EQT Production Company, et al., Circuit Court of Doddridge County, West Virginia.* On May 2, 2014, royalty owners whose predecessors had entered into a 960-acre lease (the Stout Lease) and several additional leases comprising 6,356-acres (the Cities Services Lease) with EQT Production Company's predecessor, each covering acreage in Doddridge County, West Virginia, filed a complaint in the Circuit Court of Doddridge County, West Virginia.

The complaint alleged that EQT Production Company and a number of related companies, including EQT Corporation, EQT Gathering, LLC, EQT Energy, LLC, and EQM Midstream Services, LLC (formerly known as EQT Midstream Services, LLC, the general partner of our former midstream affiliate), underpaid on royalties for gas produced under the leases and took improper post-production deductions from the royalties paid.

With respect to the Stout Lease, the plaintiffs also asserted that we committed a trespass by drilling on the leased property, claiming that we had no right under the lease to drill in the Marcellus Shale formation.

The plaintiffs also asserted claims for fraud, slander of title, punitive damages, pre-judgment interest and attorneys' fees.

The plaintiffs sought more than $100 million in compensatory damages for the trespass claim under the Stout 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.

On June 27, 2018, the court held that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter egos of one another and that royalties paid under the leases should have been based on the price of gas produced under the leases when sold to unaffiliated third parties, and not on the price when the gas was sold from EQT Production Company to EQT Energy, LLC.

Further, on January 14, 2019, the court entered an Order granting the plaintiffs' motion for summary judgment and declaring that we did not have the right to drill in the Marcellus Shale formation under the Stout Lease.

The court also ruled that seven of our wells that have been producing gas under the Stout Lease are trespassing, and that a jury will determine whether the trespass was willful or innocent.

On February 27, 2019, we filed a motion seeking permission to immediately appeal the trespass Order to the West Virginia Supreme Court; however, the motion was denied on March 25, 2019, and the court continued the trial to September 2019.

On May 28, 2019, the court entered an Order excluding certain of our costs that could have otherwise offset any damages for innocent trespass under the Stout Lease.

On August 8, 2019, we reached a settlement with the plaintiffs to resolve all claims under the Stout Lease and the Cities Services Lease for $54 million plus lease modifications to address the trespass issue and the calculation of future royalty payments under the leases.

We paid $51 million of the settlement in October 2019 and the remaining $3 million of the settlement in January 2020, and the Stout Lease was subsequently amended to address the terms agreed to with the plaintiffs under the settlement.

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.

| | | | FOR THE FISCAL YEAR ENDED DECEMBER 31, [removed: 2022] [added: 2023] | | | | | |

The aggregate market value of common [removed: stock] [added: stock, no par value,] held by non-affiliates of the registrant as of June 30, [removed: 2022: $12.6] [added: 2023: $14.7] billion

[removed: As] [added: The number] of [removed: February 10, 2023, 360,360,130] shares of common stock, no par value, of the registrant [removed: were outstanding.][added: outstanding (in thousands) as of February 9, 2024: 440,427]

EQT Corporation's definitive proxy statement relating to its [removed: 2023] [added: 2024] 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: 2022] [added: 2023] and is incorporated by reference [removed: in] [added: into] Part III [added: of this Annual Report on Form 10-K] to the extent described therein.

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| [Item [removed: 14.](#i4ae3a35ac7604788a4cf429083eb6d7f_181)] [added: 14.](#ie0b378c37216402fa1fab6dafbf447c8_178)] | | | [Principal Accountant Fees and [removed: Services](#i4ae3a35ac7604788a4cf429083eb6d7f_181)] [added: Services](#ie0b378c37216402fa1fab6dafbf447c8_178)] | | | [removed: [115](#i4ae3a35ac7604788a4cf429083eb6d7f_181)] [added: [116](#ie0b378c37216402fa1fab6dafbf447c8_178)] | | |

| [Item [removed: 15.](#i4ae3a35ac7604788a4cf429083eb6d7f_187)] [added: 15.](#ie0b378c37216402fa1fab6dafbf447c8_184)] | | | [Exhibits and Financial Statement [removed: Schedules](#i4ae3a35ac7604788a4cf429083eb6d7f_187)] [added: Schedules](#ie0b378c37216402fa1fab6dafbf447c8_184)] | | | [removed: [115](#i4ae3a35ac7604788a4cf429083eb6d7f_187)] [added: [116](#ie0b378c37216402fa1fab6dafbf447c8_184)] | | |

| [Item [removed: 16.](#i4ae3a35ac7604788a4cf429083eb6d7f_196)] [added: 16.](#ie0b378c37216402fa1fab6dafbf447c8_193)] | | | [Form 10-K [removed: Summary](#i4ae3a35ac7604788a4cf429083eb6d7f_196)] [added: Summary](#ie0b378c37216402fa1fab6dafbf447c8_193)] | | | [removed: [122](#i4ae3a35ac7604788a4cf429083eb6d7f_196)] [added: [122](#ie0b378c37216402fa1fab6dafbf447c8_193)] | | |

net – "net" natural gas and oil wells or "net" acres [removed: are determined by adding] [added: equals] the [added: sum of our] fractional ownership working interests we have in gross wells or acres.

has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated [added: or in an analogous formation.]

| Bcfe = billion cubic feet of natural gas equivalents, with one barrel of NGLs and [removed: crude] oil being equivalent to 6,000 cubic feet of natural gas | | |

| Mcfe = thousand cubic feet of natural gas equivalents, with one barrel of NGLs and [removed: crude] oil being equivalent to 6,000 cubic feet of natural gas | | |

| MMcfe = million cubic feet of natural gas equivalents, with one barrel of NGLs and [removed: crude] oil being equivalent to 6,000 cubic feet of natural gas | | |

| Tcfe = trillion cubic feet of natural gas equivalents, with one barrel of NGLs and [removed: crude] oil being equivalent to 6,000 cubic feet of natural gas | | |

- Risks Associated with Natural Gas [removed: Drilling] [added: Drilling, Transmission and Processing] Operations. As a natural gas producer, [added: and an operator of certain transmission pipelines and processing facilities,] there are risks inherent in our primary business operations.

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

- Legal and Regulatory Risks. There are many environmental, energy, financial, real property and other regulations that we are required to comply with in the context of conducting our [removed: operations,] [added: operations;] otherwise, we may be exposed to fines, penalties, investigations, litigation or other legal proceedings.

Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe" and other words of similar meaning, or the negative [removed: thereof, in connection with any discussion of future operating or financial matters.][added: thereof.]

| [Item 1C.](#ie0b378c37216402fa1fab6dafbf447c8_1793) | | | [Cybersecurity](#ie0b378c37216402fa1fab6dafbf447c8_1793) | | | [44](#ie0b378c37216402fa1fab6dafbf447c8_1793) | | |

| [Signatures](#ie0b378c37216402fa1fab6dafbf447c8_196) | | | | | | [123](#ie0b378c37216402fa1fab6dafbf447c8_196) | | |

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

or in an analogous formation.

We maintain an Enterprise Risk Committee, composed of our Chief Financial Officer, General Counsel, Chief Information Officer and other members of senior management, which oversees the identification and management of corporate-level risks, including cybersecurity risk, using the COSO Enterprise Risk Management Framework.

To support the identification of emerging risks and align our focus on our primary business risks, our Manager Enterprise Risk, whose job responsibilities are dedicated to enterprise risk management, surveys senior leaders at least annually to assess our most significant, or "Tier 1," enterprise risks.

Based in part on this survey, our Enterprise Risk Committee assesses our most significant risks and considers the effectiveness of our risk mitigation efforts, and the Manager Enterprise Risk leads a presentation to our Board of Directors covering this information on an annual basis.

Our Enterprise Risk Committee also oversees periodic follow-up assessments to analyze changes in existing, evolving and emerging risks and identify new or more effective measures for mitigation.

Cybersecurity risk was classified as a Tier 1 enterprise risk for our company by our Enterprise Risk Committee for 2023.

Our Manager Enterprise Risk, with oversight by our Enterprise Risk Committee, facilitates the monitoring of all Tier 1 enterprise risks within our digital work environment for changes in risk drivers and supports the evaluation of the potential impacts of each Tier 1 enterprise risk on our company, taking into consideration the effectiveness of our identified risk mitigants.

As part of its regular oversight role, our Board of Directors, with a primary focus on policy, oversight and strategic direction, oversees management's development and maintenance of the enterprise cybersecurity program and its actions to identify, assess, mitigate and remediate cybersecurity threats to our company.

Our Board of Directors has delegated to its Audit Committee primary responsibility for regular oversight of cybersecurity risk at the Board-level and this delegation is reflected in the Audit Committee's Charter.

Our Chief Information Officer provides a regular quarterly report to the Audit Committee of our Board of Directors regarding cybersecurity matters and our enterprise cybersecurity program.

Our management-level Enterprise Risk Committee has delegated to our Chief Information Officer primary responsibility for identifying, assessing and managing cybersecurity-related risks.

Our Chief Information Officer has a Bachelor of Science in Computer Science from the University of Kentucky and a Master of Business Administration in Finance from the Wharton School of Business at the University of Pennsylvania.

He has served in his current role at EQT since 2019 and has over twenty years of information technology experience within the energy industry.

Our Information Security team, led by our Vice President, Information Technology, who reports directly to our Chief Information Officer, manages our enterprise cybersecurity program and is responsible for managing all reported cybersecurity threats and addressing matters related to cybersecurity risk, information security and technology risk.

We maintain a Cybersecurity Incident Management Policy (Cybersecurity Policy), which provides guidance and processes for identifying, reporting, assessing, resolving and ensuring timely public disclosure, when appropriate, of cybersecurity threats, including both cybersecurity threats directed at our company and those associated with our use of third-party service providers.

We have retained a leading cybersecurity incident response vendor to assist us in responding to cybersecurity incidents and we maintain relationships with integration vendors to help us recover or rebuild technology systems in the event of a large-scale cybersecurity incident.

Our Cybersecurity Policy requires that all of our employees, contractors and vendors report any suspected cybersecurity threat to our Information Security team using reporting functions within our digital work environment.

Once reported, our Information Security team begins investigating the incident and assigns an alert classification to the incident, based on the perceived level of threat to our company and our technology network.

The team updates the alert classification, as appropriate, throughout the incident response process.

In the event our Information Security team classifies a cybersecurity incident as posing a "critical risk," our Disclosure Committee, which includes our General Counsel and Chief Accounting Officer, is immediately notified of such classification via functions within our digital work environment.

The Disclosure Committee, in consultation with our Information Security team and Chief Information Officer, engages in an assessment of the materiality of the cybersecurity incident, under applicable disclosure standards, including material developments throughout the incident response process.

Our Board of Directors would be promptly informed upon identification of any material cybersecurity event.

Our Information Security team is responsible for managing all reported cybersecurity threats until final resolution.

We maintain a record of reported cybersecurity incidents and the management and resolution of such incidents.

Our Information Security team, with support from our Legal Department, annually reviews our Cybersecurity Policy to ensure alignment with cybersecurity best practices.

Cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected our company, including our business strategy, results of operations or financial condition.

However, we face certain ongoing risks from cybersecurity threats that, if realized, may be reasonably likely to materially affect our operations and, therefore, our results of operations and/or financial condition.

For more information about these risks, see Item 1A., "Risk Factors - Cyber incidents targeting our digital work environment or other technologies or energy infrastructure may adversely impact our operations."

Information about our Executive Officers (as of February [removed: 16, 2023)][added: 14, 2024)]

| Tony Duran [removed: (44)] [added: (45)] | | | | | | 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: (45)] [added: (46)] | | | | | | 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: (40)] [added: (41)] | | | | | | 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: (42)] [added: (43)] | | | | | | 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 [removed: sectors)] [added: sector)] 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. | | |

| Toby Z. Rice [removed: (41)] [added: (42)] | | | | | | 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 [removed: Energy,] [added: Energy Inc.,] 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. | | |

| Jeremy T. Knop (35) | | | | | | Chief Financial Officer (2023) | | | | | | Mr. Knop was appointed as the Chief Financial Officer of EQT Corporation in July 2023. Prior to becoming Chief Financial Officer, Mr. Knop was responsible for the development and execution of EQT Corporation’s mergers and acquisitions strategy, serving as Executive Vice President of Corporate Development beginning in March 2022 and as Senior Vice President of Corporate Development from January 2021 through March 2022. Prior to joining EQT Corporation, from August 2012 to January 2021, Mr. Knop was employed by The Blackstone Group (a global investment firm whose asset management business includes investment vehicles focused on real estate, private equity, infrastructure, life sciences, growth equity, credit, real assets and secondary funds), where he served in several capacities on the energy credit team, including as Principal from January 2019 to January 2021, Vice President from January 2017 to December 2018, Associate from January 2014 to December 2016, and Analyst from August 2012 to December 2013. Earlier in his career, Mr. Knop served as an Analyst in Global Natural Resources Investment Banking at Barclays Capital (a multinational investment bank) from June 2010 to August 2012. | | |

| David M. Khani (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. | | |

As of February [removed: 10, 2023,] [added: 9, 2024,] there were [removed: 1,820] [added: 1,735] shareholders of record of our common stock.

On February [removed: 9, 2023,] [added: 8, 2024,] our Board of Directors declared a quarterly cash dividend of [removed: $0.15] [added: $0.1575] per [removed: share,] [added: share of EQT Corporation common stock,] payable on March 1, [removed: 2023,] [added: 2024,] to shareholders of record at the close of business on February [removed: 21, 2023.][added: 20, 2024.]

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

[removed: The following table sets forth our repurchases of] [added: We did not repurchase any] equity securities registered under Section 12 of the Exchange Act [removed: that have occurred] during the three months ended December 31, [removed: 2022.][added: 2023.]

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

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

[removed: The share repurchase program expires] [added: As a result of such extension, the Share Repurchase Program will expire on] December 31, [removed: 2023] [added: 2024,] but [added: it] may be suspended, modified or discontinued at any time without prior notice.

As of December 31, [removed: 2022,] [added: 2023,] we had purchased shares for an aggregate purchase price of [removed: $422.1] [added: $622.1] million, excluding fees, commissions and expenses, under [removed: this authorization] [added: the Share Repurchase Program] since its [removed: inception.][added: inception, and the approximate dollar value of shares that may yet be purchased under the Share Repurchase Program is $1.4 billion.]

The [removed: following] graph [added: below] 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: 2021] [added: 2022] Self-Constructed Peer Group and [removed: 2022] [added: the 2023] Self-Constructed Peer Group, whose company composition is discussed in footnotes (a) and (b), respectively, below.

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: 2017] [added: 2018] and its relative performance is tracked through December 31, [removed: 2022.][added: 2023.]

[removed: ][added: ]

(a)The [removed: 2021] [added: 2022] Self-Constructed Peer Group includes the following [removed: ten] [added: fourteen] companies: Antero Resources Corp., [removed: Apache] [added: APA Corp. (US), Chesapeake Energy] Corp., CNX Resources Corp., Comstock Resources, Inc., Coterra Energy Inc., Devon Energy Corp., [added: Diamondback Energy, Inc., Marathon Oil Corp., Matador Resources Co.,] Murphy Oil Corp., Ovintiv Inc., Range Resources Corp. and Southwestern Energy Co. The [removed: 2021] [added: 2022] Self-Constructed Peer Group is comprised of the companies included in our [removed: 2021] [added: 2022] performance peer group (with the exception of (i) [removed: Cimarex Energy Co.,] [added: Continental Resources, Inc.,] which was excluded for purposes of the stock performance graph because [removed: it was acquired by Cabot Oil & Gas Corp.] [added: its stock ceased to be publicly traded beginning] in [removed: October 2021 thereby forming Coterra Energy Inc,] [added: November 2022,] and (ii) [removed: Continental Resources,] [added: PDC Energy] Inc., which was excluded for purposes of the stock performance graph because [removed: its stock ceased to be publicly traded beginning] [added: it was acquired by Chevron Corp.] in [removed: November 2022),] [added: August 2023),] as selected by the Management Development and Compensation Committee of our Board of Directors for purposes of evaluating our relative total shareholder return under the [removed: 2021] [added: 2022] Incentive Performance Share Unit Program.

(b)The [removed: 2022] [added: 2023] Self-Constructed Peer Group includes the following [removed: fifteen] [added: sixteen] companies: Antero Resources Corp., [removed: Apache Corp.,] [added: APA Corp. (US),] Chesapeake Energy Corp., CNX Resources Corp., Comstock [removed: Resources,] [added: Resources] Inc., Coterra Energy Inc., Devon Energy Corp., Diamondback [removed: Energy] [added: Energy, Inc., Hess] Corp., Marathon Oil Corp., Matador Resources Co., Murphy Oil Corp., Ovintiv Inc., [removed: PDC Energy Inc.,] [added: Pioneer Natural Resources Co.,] Range Resources Corp. and Southwestern Energy Co. The [removed: 2022] [added: 2023] Self-Constructed Peer Group is comprised of the companies included in our [removed: 2022] [added: 2023] performance peer group (with the exception of [removed: Continental Resources,] [added: PDC Energy] Inc., which was excluded for purposes of the stock performance graph because [removed: its stock ceased to be publicly traded beginning] [added: it was acquired by Chevron Corp.] in [removed: November 2022),] [added: August 2023),] as selected by the Management Development and Compensation Committee of our Board of Directors for purposes of evaluating our relative total shareholder return under the [removed: 2022] [added: 2023] Incentive Performance Share Unit Program.

The Share Repurchase Program was originally scheduled to expire on December 31, 2023; however, on April 26, 2023, we announced that our Board of Directors approved a one-year extension of the Share Repurchase Program.

| | | | 12/18 | | | | | | 12/19 | | | | | | 12/20 | | | | | | 12/21 | | | | | | 12/22 | | | | | | 12/23 | | |

| EQT Corporation | | | $ | 100.00 | | | | | $ | 58.18 | | | | | $ | 68.21 | | | | | $ | 117.05 | | | | | $ | 184.46 | | | | | $ | 214.36 | |

| S&P 500 Index | | | 100.00 | | | | | | 131.49 | | | | | | 155.68 | | | | | | 200.37 | | | | | | 164.08 | | | | | | 207.21 | | |

| S&P MidCap 400 Index | | | 100.00 | | | | | | 126.20 | | | | | | 143.44 | | | | | | 178.95 | | | | | | 155.58 | | | | | | 181.15 | | |

| 2022 Self-Constructed Peer Group (a) | | | 100.00 | | | | | | 94.04 | | | | | | 62.22 | | | | | | 135.86 | | | | | | 206.58 | | | | | | 194.10 | | |

| 2023 Self-Constructed Peer Group (b) | | | 100.00 | | | | | | 106.87 | | | | | | 75.96 | | | | | | 145.21 | | | | | | 223.56 | | | | | | 217.88 | | |

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

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

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

| 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.

(b)Excludes any fees, commissions or other expenses associated with the share repurchases.

The total number of shares purchased and the approximate dollar value of shares that may yet be purchased under our repurchase authority reported in this table reflect shares purchased in each month based on the trade date; however, certain purchases may not have settled until the following month.

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

*$100 invested on 12/31/17 in stock, index, or peer group, including reinvestment of dividends.

Copyright© 2023 Standard & Poor's, a division of S&P Global.

All right reserved.

| | | | 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 | | |

| [Reports of Independent Registered Public Accounting Firm (PCAOB [removed: ID:](#i4ae3a35ac7604788a4cf429083eb6d7f_64) 42[)](#i4ae3a35ac7604788a4cf429083eb6d7f_64)] [added: ID:](#ie0b378c37216402fa1fab6dafbf447c8_64) 42[)](#ie0b378c37216402fa1fab6dafbf447c8_64)] | | | | | | [removed: [64](#i4ae3a35ac7604788a4cf429083eb6d7f_64)] [added: [65](#ie0b378c37216402fa1fab6dafbf447c8_64)] | | |

| [Statements of Consolidated [removed: Operations](#i4ae3a35ac7604788a4cf429083eb6d7f_67)] [added: Operations](#ie0b378c37216402fa1fab6dafbf447c8_67)] | | | | | | [removed: [67](#i4ae3a35ac7604788a4cf429083eb6d7f_67)] [added: [69](#ie0b378c37216402fa1fab6dafbf447c8_67)] | | |

[removed: | [Statements of Consolidated Comprehensive Loss](#i4ae3a35ac7604788a4cf429083eb6d7f_73) | | | | | | [68](#i4ae3a35ac7604788a4cf429083eb6d7f_73) | | |][added: STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)]

| [Consolidated Balance [removed: Sheets](#i4ae3a35ac7604788a4cf429083eb6d7f_76)] [added: Sheets](#ie0b378c37216402fa1fab6dafbf447c8_76)] | | | | | | [removed: [69](#i4ae3a35ac7604788a4cf429083eb6d7f_76)] [added: [71](#ie0b378c37216402fa1fab6dafbf447c8_76)] | | |

| [Statements of Consolidated Cash [removed: Flows](#i4ae3a35ac7604788a4cf429083eb6d7f_79)] [added: Flows](#ie0b378c37216402fa1fab6dafbf447c8_79)] | | | | | | [removed: [70](#i4ae3a35ac7604788a4cf429083eb6d7f_79)] [added: [72](#ie0b378c37216402fa1fab6dafbf447c8_79)] | | |

| [Statements of Consolidated [removed: Equity](#i4ae3a35ac7604788a4cf429083eb6d7f_82)] [added: Equity](#ie0b378c37216402fa1fab6dafbf447c8_82)] | | | | | | [removed: [71](#i4ae3a35ac7604788a4cf429083eb6d7f_82)] [added: [73](#ie0b378c37216402fa1fab6dafbf447c8_82)] | | |

| [Notes to the Consolidated Financial [removed: Statements](#i4ae3a35ac7604788a4cf429083eb6d7f_85)] [added: Statements](#ie0b378c37216402fa1fab6dafbf447c8_85)] | | | | | | [removed: [72](#i4ae3a35ac7604788a4cf429083eb6d7f_85)] [added: [74](#ie0b378c37216402fa1fab6dafbf447c8_85)] | | |

We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, [removed: 2022] [added: 2023] and [removed: 2021,] [added: 2022,] the related consolidated statements of operations, comprehensive [removed: loss,] [added: income (loss),] cash flows and equity for each of the three years in the period ended December 31, [removed: 2022,] [added: 2023,] and the related notes and [removed: 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 financial position of the Company at December 31, [removed: 2022] [added: 2023] and [removed: 2021,] [added: 2022,] and the results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2022,] [added: 2023,] 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: 2022,] [added: 2023,] based on criteria established in Internal [removed: Control-Integrated] [added: Control – Integrated] Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February [removed: 16, 2023] [added: 14, 2024] expressed an unqualified opinion thereon.

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

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

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

| *Description of the Matter* | | | At December 31, [removed: 2022,] [added: 2023,] the net book value of the Company's proved oil and natural gas properties was [removed: $16,023] [added: $19,737] million, and depreciation, depletion and amortization (DD&A) expense was [removed: $1,666] [added: $1,732] 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 prepared using standard geological and engineering methods generally recognized in the petroleum industry based on evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs. Significant judgment is required by the Company's engineers in 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, and future operating and capital costs assumptions, among others. Because of the complexity involved in estimating natural gas, NGLs and oil reserves, management used independent engineers to audit the estimates prepared by the Company's internal engineers as of December 31, [removed: 2022.] [added: 2023.] 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: Finally, we] [added: We also] tested [removed: that] the [added: mathematical accuracy of the] DD&A [removed: expense calculations are based on] [added: calculations, including comparing] the [removed: appropriate] proved natural gas, NGLs, and oil [removed: reserve balances from] [added: reserves amounts used in] the Company's reserve report. | | |

[added: |] February [removed: 16,] 2023 [added: | | | | | | 8 | | | | | | 541 | | | | | | 30.77 | | |]

We have audited EQT Corporation and subsidiaries' internal control over financial reporting as of December 31, [removed: 2022,] [added: 2023,] 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: 2022,] [added: 2023,] 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: 2022] [added: 2023] and [removed: 2021,] [added: 2022,] the related consolidated statements of operations, comprehensive [removed: loss,] [added: income (loss),] cash flows and equity for each of the three years in the period ended December 31, [removed: 2022] [added: 2023] and the related notes and the financial statement schedule listed in the Index at Item [removed: 15(a) of the Company,] [added: 15(a),] and our report dated February [removed: 16, 2023] [added: 14, 2024] expressed an unqualified opinion thereon.

| | | | [added: 2023 (a) | | | | | |] 2022 | | | | | | [removed: 2021] [added: 2021 (a)] | | | | | | [removed: 2020] [added: 2020 (b)] | | | [added: | | | 2019 | | |]

| Sales of natural gas, natural gas liquids and oil | | | $ | [removed: 12,114,168] [added: 5,044,768] | | | | | $ | [removed: 6,804,020] [added: 12,114,168] | | | | | $ | [removed: 2,650,299] [added: 6,804,020] | |

| [removed: (Loss) gain] [added: Gain (loss)] on derivatives | | | [removed: (4,642,932)] [added: 1,838,941] | | | | | | [removed: (3,775,042)] [added: (4,642,932)] | | | | | | [removed: 400,214] [added: (3,775,042)] | | |

| Net marketing services and other | | | [removed: 26,453] [added: 25,214] | | | | | | [removed: 35,685] [added: 26,453] | | | | | | [removed: 8,330] [added: 35,685] | | |

| Total operating revenues | | | [removed: 7,497,689] [added: 6,908,923] | | | | | | [removed: 3,064,663] [added: 7,497,689] | | | | | | [removed: 3,058,843] [added: 3,064,663] | | |

| Transportation and processing | | | [removed: 2,116,976] [added: 2,157,260] | | | | | | [removed: 1,942,165] [added: 2,116,976] | | | | | | [removed: 1,710,734] [added: 1,942,165] | | |

| Production | | | [removed: 300,985] [added: 254,700] | | | | | | [removed: 225,279] [added: 300,985] | | | | | | [removed: 155,403] [added: 225,279] | | |

| Exploration | | | [removed: 3,438] [added: 3,330] | | | | | | [removed: 24,403] [added: 3,438] | | | | | | [removed: 5,484] [added: 24,403] | | |

| Selling, general and administrative | | | [removed: 252,645] [added: 236,171] | | | | | | [removed: 196,315] [added: 252,645] | | | | | | [removed: 174,769] [added: 196,315] | | |

| Depreciation and depletion | | | [removed: 1,665,962] [added: 1,732,142] | | | | | | [removed: 1,676,702] [added: 1,665,962] | | | | | | [removed: 1,393,465] [added: 1,676,702] | | |

| [removed: (Gain) loss/impairment] [added: Loss (gain)] on sale/exchange of long-lived assets | | | [removed: (8,446)] [added: 17,445] | | | | | | [removed: (21,124)] [added: (8,446)] | | | | | | [removed: 100,729] [added: (21,124)] | | |

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

| Impairment and expiration of leases | | | [removed: 176,606] [added: 109,421] | | | | | | [removed: 311,835] [added: 176,606] | | | | | | [removed: 306,688] [added: 311,835] | | |

| Other operating expenses | | | [removed: 57,331] [added: 84,043] | | | | | | [removed: 70,063] [added: 57,331] | | | | | | [removed: 28,537] [added: 70,063] | | |

| Total operating expenses | | | [removed: 4,779,692] [added: 4,594,512] | | | | | | [removed: 4,425,638] [added: 4,779,692] | | | | | | [removed: 3,936,509] [added: 4,425,638] | | |

| Operating income (loss) | | | [removed: 2,717,997] [added: 2,314,411] | | | | | | [removed: (1,360,975)] [added: 2,717,997] | | | | | | [removed: (877,666)] [added: (1,360,975)] | | |

| [removed: Loss (income)] [added: (Income) loss] from investments | | | [removed: 4,931] [added: (7,596)] | | | | | | [removed: (71,841)] [added: 4,931] | | | | | | [removed: 314,468] [added: (71,841)] | | |

| Dividend and other income | | | [removed: (11,280)] [added: (1,231)] | | | | | | [removed: (19,105)] [added: (11,280)] | | | | | | [removed: (35,512)] [added: (19,105)] | | |

| Loss on debt extinguishment | | | [removed: 140,029] [added: 80] | | | | | | [removed: 9,756] [added: 140,029] | | | | | | [removed: 25,435] [added: 9,756] | | |

| Interest [removed: expense] [added: expense, net] | | | [removed: 249,655] [added: 219,660] | | | | | | [removed: 289,753] [added: 249,655] | | | | | | [removed: 259,268] [added: 289,753] | | |

| Income (loss) before income taxes | | | [removed: 2,334,662] [added: 2,103,498] | | | | | | [removed: (1,569,538)] [added: 2,334,662] | | | | | | [removed: (1,254,102)] [added: (1,569,538)] | | |

Valuation of Acquired Natural Gas and Oil Properties

| *Description of the Matter* | | | As described in Note 6 to the consolidated financial statements, on August 22, 2023, the Company completed the acquisition of THQ Appalachia I, LLC and THQ-XcL Holdings I, 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. | | |

February 14, 2024

February 14, 2024

| | | | 2023 | | | | | | 2022 | | |

| Income tax receivable | | | 91,414 | | | | | | — | | |

| Term Loan Facility borrowings | | | 1,244,265 | | | | | | — | | |

| Net income (loss) | | | $ | 1,734,544 | | | | | $ | 1,780,942 | | | | | $ | (1,141,501) | |

| Depreciation and depletion | | | 1,732,142 | | | | | | 1,665,962 | | | | | | 1,676,702 | | |

| (Income) loss from investments | | | (7,596) | | | | | | 4,931 | | | | | | (71,841) | | |

| Loss on debt extinguishment | | | 80 | | | | | | 140,029 | | | | | | 9,756 | | |

| Net income (loss) | | | | | | | | | | | | | | | | | | | | | 1,735,232 | | | | | | | | | | | | (688) | | | | | | 1,734,544 | | |

| Dividends ($0.61 per share) | | | | | | | | | | | | | | | | | | | | | (228,339) | | | | | | | | | | | | | | | | | | (228,339) | | |

| Convertible Notes settlements | | | 8,565 | | | | | | 122,830 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 122,830 | | |

| Repurchase and retirement of common stock | | | (5,906) | | | | | | (91,545) | | | | | | | | | | | | (109,484) | | | | | | | | | | | | | | | | | | (201,029) | | |

| Tug Hill and XcL Midstream Acquisition | | | 49,600 | | | | | | 2,152,631 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,152,631 | | |

| Dissolution of consolidated variable interest entity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (25,227) | | | | | | (25,227) | | |

| Other | | | | | | | | | | | | | | | | | | | | | 911 | | | | | | | | | | | | | | | | | | 911 | | |

| Balance at December 31, 2023 | | | 419,896 | | | | | | $ | 12,093,986 | | | | | $ | — | | | | | $ | 2,681,898 | | | | | $ | (2,684) | | | | | $ | 7,617 | | | | | $ | 14,780,817 | |

*Nature of Operations.* EQT Corporation is a natural gas production company with operations focused in the Appalachian Basin.

See "Equity Method Investments" and "Investments in Equity Securities" for accounting policies for the Company's investments in entities that it does not consolidate.

In 2020, the Company entered into a partnership (the Partnership) with a third-party investor (the Investor) to purchase certain mineral rights in the Appalachian Basin.

During 2023, the Partnership's assets were distributed pro rata to the Company and the Investor, and the Partnership was dissolved.

Prior to the Partnership's dissolution, the Company consolidated the Partnership as management had determined that the Partnership was a variable interest entity, and the Company was the primary beneficiary of the Partnership.

| | | | 2023 | | | | | | 2022 | | |

As of December 31, 2023, the Company held a 31% ownership interest in Laurel Mountain Midstream, LLC (LMM), which owns gathering assets that are operated by The Williams Companies, Inc., and an approximate 15.43% ownership interest in WATT Fuel Cell Corporation (WATT), a developer and manufacturer of solid oxide fuel cell stacks and systems that operate on common, readily available fuels such as propane and natural gas.

As of December 31, 2023 and 2022, the fair value of the Company's investment in the Investment Fund was $36.1 million and $31.2 million, respectively, and was presented in other assets in the Consolidated Balance Sheets.

Prior to the Company's sale of Equitrans Midstream's common stock, the Company accounted for its investment in Equitrans Midstream as an investment in equity security.

| | | | 2023 | | | | | | 2022 | | |

The Company is under no legal or contractual obligation to restore or dismantle its midstream assets upon abandonment.

In addition, the Company is responsible for the operation and maintenance of its midstream assets and intends to continue such operation and maintenance so long as supply and demand for natural gas exists.

As the Company expects supply and demand for natural gas to exist into the foreseeable future, the Company has not recorded asset retirement obligations for its midstream assets.

| | | | 2023 | | | | | | 2022 | | |

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

| Other | | | 6,194 | | | | | | 767 | | | | | | 7,458 | | |

Prior to the Redemption, the Company used the if-converted method to calculate the impact of the Convertible Notes on diluted income per share.

| | | | 2023 | | | | | | 2022 | | | | | | 2021 | | |

| | | | 2023 | | | | | | 2022 | | | | | | 2021 | | |

| Dissolution of consolidated variable interest entity | | | 25,227 | | | | | | — | | | | | | — | | |

| | | | | | |

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

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

| | | | (Thousands, except per share amounts) | | | | | | | | | | | | | | |

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

| Gain on Equitrans Share Exchange (Note 5) | | | — | | | | | | — | | | | | | (187,223) | | |

| | | | (Thousands) | | | | | | | | | | | | | | |

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

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

| | | | (Thousands) | | | | | | | | |

| Treasury stock, shares at cost: zero and 1,033 | | | — | | | | | | (18,046) | | |

| Gain on Equitrans Share Exchange | | | — | | | | | | — | | | | | | (187,223) | | |

| Income tax receivable and payable | | | — | | | | | | (23,909) | | | | | | 322,763 | | |

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

| Net proceeds from issuance of common stock | | | — | | | | | | — | | | | | | 340,923 | | |

| Balance at December 31, 2019 | | | 255,171 | | | | | | $ | 7,818,205 | | | | | $ | (32,507) | | | | | $ | 2,023,089 | | | | | $ | (5,199) | | | | | $ | — | | | | | $ | 9,803,588 | |

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

| Dividends ($0.03 per share) | | | | | | | | | | | | | | | | | | | | | (7,664) | | | | | | | | | | | | | | | | | | (7,664) | | |

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

| Issuance of common stock | | | 23,000 | | | | | | 340,923 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 340,923 | | |

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

| Margin requirements with counterparties (see Note 3) | | | $ | 100,623 | | | | | $ | 147,773 | |

| Total prepaid expenses and other | | | $ | 135,337 | | | | | $ | 191,435 | |

The Company recognizes expense for lease expirations as the lease expires if the lease was not previously impaired.

During 2022, the Company sold the remaining balance of its shares of Equitrans Midstream's common stock.

The Company did not have the ability to exercise significant influence over Equitrans Midstream or any of its subsidiaries and, as such, accounted for its investment in Equitrans Midstream as an investment in equity securities that, as of December 31, 2021, was recorded at fair value in other assets in the Consolidated Balance Sheet.

The Company valued its investment by multiplying the closing stock price of Equitrans Midstream's common stock by the number of shares of Equitrans Midstream's common stock owned by the Company.

*Intangible Assets.* The Company's intangible assets, composed of non-compete agreements with former Rice Energy Inc. executives, were fully amortized as of December 31, 2020.

| Reorganization, including severance and contract terminations | | | 767 | | | | | | 7,458 | | | | | | 5,448 | | |

| | | | (Thousands, except per share amounts) | | |

In August 2020, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2020-06, *Debt with Conversion and Other Options and Derivatives and Hedging: Accounting for Convertible Instruments and Contracts in an Entity's Own Equity*.

This ASU simplifies accounting for convertible instruments by removing certain separation models for convertible instruments.

For convertible instruments with conversion features that are not accounted for as derivatives under Accounting Standards Codification 815 or that do not result in substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer separated from the host contract.

Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost.

Under ASU 2020-06, entities are required to use the if-converted method to calculate the impact of convertible instruments on diluted EPS.

The if-converted method assumes share settlement of the

instrument, which increases the number of potentially dilutive securities used to calculate diluted EPS.

This ASU also adds several new disclosure requirements.

The Company adopted ASU 2020-06 effective as of January 1, 2022 using the full retrospective method of adoption.

Accordingly, the consolidated financial statements have been recast.

[removed: Management] [added: Our management] assessed the effectiveness of our internal control over financial reporting as of December 31, [removed: 2022.][added: 2023.]

In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in [removed: *Internal Control-Integrated] [added: Internal Control – Integrated] Framework [removed: (2013)*.][added: (2013).]

Based on this assessment, [added: our] management concluded that we maintained effective internal control over financial reporting as of December 31, [removed: 2022.][added: 2023.]

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: 2022] [added: 2023] that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the three months ended December 31, 2023, none of our directors or "officers" (as defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" (as each term is defined in Item 408(a) of Regulation S-K).

Not Applicable.

The following information is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2023] [added: 2024] 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: 2022:][added: 2023:]

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: 16, 2023)."][added: 14, 2024)."]

The following information is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2023] [added: 2024] 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: 2022:][added: 2023:]

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: 2023] [added: 2024] 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: 2022.][added: 2023.]

The following table and related footnotes provide information as of December 31, [removed: 2022] [added: 2023] 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: 52,518] [added: 69,775] | | | (6) | | | N/A | | | | | | [removed: 115,089] [added: 107,061] | | | (7) | | |

(2)Consists of (i) [removed: 3,155,055] [added: 3,958,316] 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: 1,519,178 *target*] [added: 1,920,768 target] awards and dividend reinvestments thereon)), (ii) [removed: 167,621] [added: 186,341] shares subject to outstanding directors' deferred stock units under the 2020 LTIP, inclusive of dividend reinvestments thereon, (iii) [removed: 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 1,384,351 *target* awards and dividend reinvestments thereon)), (iv) 2,240,000] [added: 1,000,000] shares subject to outstanding stock options [removed: and stock appreciation rights] under the 2019 LTIP, [removed: (v) 40,014] [added: (iv) 40,661] shares subject to outstanding directors' deferred stock units under the 2019 LTIP, inclusive of dividend reinvestments thereon, [removed: (vi) 448,331] [added: (v) 388,231] shares subject to outstanding stock options under the 2014 LTIP, [removed: (vii) 62,117] [added: (vi) 63,122] shares subject to outstanding directors' deferred stock units under the 2014 LTIP, inclusive of dividend reinvestments thereon, [removed: (viii) 250,039] [added: (vii) 176,886] shares subject to outstanding stock options under the 2009 LTIP; and [removed: (ix) 9,034] [added: (viii) 9,180] shares subject to outstanding directors' deferred stock units under the 2009 LTIP, inclusive of dividend reinvestments thereon.

(3)The weighted-average exercise price is calculated solely based on outstanding stock options [removed: and stock appreciation rights] under the 2019 LTIP, 2014 LTIP and the 2009 LTIP and excludes deferred stock units under the [added: 2020 LTIP,] 2019 LTIP, 2014 [removed: LTIP,] [added: LTIP] and the 2009 LTIP and performance awards under the [removed: 2019] [added: 2020] LTIP, [removed: 2014] [added: 2019] LTIP and [removed: 2009] [added: 2014] LTIP.

The weighted average remaining term of the outstanding stock options [removed: and stock appreciation rights] was [removed: 3.8] [added: 2.7] years [removed: and 7.0 years, respectively,] as of December 31, [removed: 2022.][added: 2023.]

(4)Consists of (i) [removed: 17,832,453] [added: 15,464,915] shares available for future issuance under the 2020 LTIP and (ii) [removed: 201,845] [added: 175,365] shares available for future issuance under the 2008 ESPP.

As of December 31, [removed: 2022,] [added: 2023,] no shares were subject to purchase under the 2008 ESPP.

(6)Consists entirely of shares invested in the EQT 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: 2022.][added: 2023.]

(7)Consists entirely of shares available for future issuance under the 2005 DDCP as of December 31, [removed: 2022.][added: 2023.]

| Equity Compensation Plans Approved by Shareholders (1) | | | | | | 5,822,737 | | | (2) | | | $ | 18.75 | | (3) | | | 15,640,280 | | | (4) | | |

| Total | | | | | | 5,892,512 | | | | | | $ | 18.75 | | | | | 15,747,341 | | | | | |

| 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 | | | | | |

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: 2023] [added: 2024] 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: 2022.][added: 2023.]

Information required by Item 9(e) of Schedule 14A is incorporated herein by reference from our definitive proxy statement relating to the [removed: 2023] [added: 2024] 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: 2022.][added: 2023.]

| | | | | | | Statements of Consolidated Operations | | | [removed: [67](#i4ae3a35ac7604788a4cf429083eb6d7f_67)] [added: [69](#ie0b378c37216402fa1fab6dafbf447c8_67)] | | |

| | | | | | | Statements of Consolidated Comprehensive [removed: Loss] [added: Income (Loss)] | | | [removed: [68](#i4ae3a35ac7604788a4cf429083eb6d7f_73)] [added: [70](#ie0b378c37216402fa1fab6dafbf447c8_73)] | | |

| | | | | | | Consolidated Balance Sheets | | | [removed: [69](#i4ae3a35ac7604788a4cf429083eb6d7f_76)] [added: [71](#ie0b378c37216402fa1fab6dafbf447c8_76)] | | |

| | | | | | | Statements of Consolidated Cash Flows | | | [removed: [70](#i4ae3a35ac7604788a4cf429083eb6d7f_79)] [added: [72](#ie0b378c37216402fa1fab6dafbf447c8_79)] | | |

| | | | | | | Statements of Consolidated Equity | | | [removed: [71](#i4ae3a35ac7604788a4cf429083eb6d7f_82)] [added: [73](#ie0b378c37216402fa1fab6dafbf447c8_82)] | | |

| | | | | | | Notes to the Consolidated Financial Statements | | | [removed: [72](#i4ae3a35ac7604788a4cf429083eb6d7f_85)] [added: [74](#ie0b378c37216402fa1fab6dafbf447c8_85)] | | |

| | | | | | | Schedule II – Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, [removed: 2022] [added: 2023] | | | | | |

FOR THE THREE YEARS ENDED DECEMBER 31, [removed: 2022][added: 2023]

| Description | | | | | | Balance at Beginning of Period | | | | | | [removed: (Deductions) Additions] [added: Additions] Charged to Costs and Expenses | | | | | | [removed: Additions] [added: Deductions] Charged to Other Accounts | | | | | | Deductions | | | | | | Balance at End of Period | | |

See Note [removed: 9] [added: 7] to the Consolidated Financial Statements for a discussion of the change in valuation allowance.

| [removed: [2.01(a)](https://www.sec.gov/Archives/edgar/data/33213/000110465922098267/tm2225319d1_ex2-1.htm)] [added: [2.01(](https://www.sec.gov/Archives/edgar/data/33213/000110465922129998/tm2233358d1_ex2-1.htm)[a](https://www.sec.gov/Archives/edgar/data/33213/000110465922129998/tm2233358d1_ex2-1.htm)[)](https://www.sec.gov/Archives/edgar/data/33213/000110465922129998/tm2233358d1_ex2-1.htm)] | | | | | | [added: Amended and Restated] Purchase Agreement, dated [removed: September 6,] [added: December 23,] 2022, among THQ Appalachia I, LLC, THQ-XcL Holdings I, LLC, the subsidiaries of the foregoing entities named on the signature pages thereto, EQT Production Company and EQT Corporation. | | | | | | Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-3551) filed on [removed: September 7,] [added: December 27,] 2022. | | |