EQT (EQT) 10-K risk factor changes: FY2024 vs FY2023

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

Drilling [removed: for] [added: for, producing, gathering, transmitting, storing] and [removed: producing] [added: processing] natural gas [removed: is a] [added: are] high-risk and costly [removed: activity] [added: activities] with many uncertainties.

Our future financial position, cash flows and results of operations depend on the success of our [removed: development and acquisition] [added: operating] activities, which are subject to numerous risks beyond our [removed: control, including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in drilled wells.][added: control.]

Many factors may curtail, [removed: delay] [added: delay, suspend] or cancel our scheduled drilling projects, [removed: 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), [added: and our gathering, transmission, storage and processing operations,] including the following:

- shortages of or delays in obtaining equipment, rigs, [added: pipe,] materials, qualified [removed: personnel or] [added: personnel,] water (for hydraulic fracturing [removed: activities);][added: activities) or other natural resources needed for our operations;]

- adverse weather conditions, such as flooding, droughts, freeze-offs, [added: fires,] landslides, blizzards and ice storms;

Any of these risks can cause a delay [removed: in] [added: or suspension of] our [added: operations, including our] development program or 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 [removed: or loss of wells] and other regulatory penalties.

Our business is subject to all of the inherent hazards and risks normally incidental to drilling for, producing, transporting, storing, processing, gathering and 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 [removed: equipment] [added: equipment, pipe] and qualified personnel or in obtaining water [added: and other natural resources] 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.

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

An operational issue at any of those stations would materially impact our production, cash [removed: flow] [added: flows] and results of operation.

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

Some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere produce climate changes that may have significant physical effects, such as increased frequency and severity of storms, [added: fires,] floods, droughts, and other extreme climatic events.

Potential adverse effects could include disruption of our production activities; delays in getting our [added: and our customers'] 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 [added: and midstream services] or cause us to incur significant costs in preparing for, or responding to, the effects of climatic or weather events themselves.

[added: 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.

Because of these uncertain factors, we do not know if the drilling locations we have [removed: identified] [added: scheduled] will ever be drilled or if we will be able to produce natural gas, NGLs or oil from these or any other drilling locations.

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

For the years ended December 31, [removed: 2023, 2022] [added: 2024, 2023] and [removed: 2021,] [added: 2022,] we recorded impairment and expiration of leases of [removed: $109.4] [added: $97.4] million, [removed: $176.6] [added: $109.4] million and [removed: $311.8] [added: $176.6] million, respectively.

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

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

[removed: We may] [added: Although many of these rights are perpetual in nature, we occasionally] obtain the rights to construct and operate our pipelines [added: and other facilities] on land owned by third parties and governmental agencies for a specific period of [removed: time.][added: time or in a manner in which certain facts could give rise to the presumption of the abandonment of the pipeline or other facilities.]

[removed: Our loss] [added: Such issues in respect] of [removed: these rights, through our inability to renew] the [removed: right-of-way or for other reasons,] [added: construction of midstream assets] could [removed: materially] adversely affect our business, financial condition, results of [removed: operations] [added: operations,] and cash flows.

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

Commodity pricing is estimated by using a combination of the [removed: five-year] [added: three-year] NYMEX forward strip prices and assumptions related to gas quality, locational basis adjustments and inflation.

[added: 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.

Our primary business involves the exploration, [removed: production] [added: production, gathering, transmission] and sale of hydrocarbons, and in particular, natural gas.

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of [removed: $3.78] [added: $3.40] per MMBtu to a low of [removed: $1.74] [added: $1.21] per MMBtu between the period from January 1, [removed: 2023] [added: 2024] through December 31, [removed: 2023,] [added: 2024,] and the daily spot prices for NYMEX West Texas Intermediate oil ranged from a high of [removed: $93.67] [added: $87.69] per barrel to a low of [removed: $66.61] [added: $66.73] per barrel during the same period.

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

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 [removed: revenues.][added: revenues, and demand for our midstream services may decrease, diminishing the cash flows from such operations.]

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues (including continued hostilities between Russia and Ukraine as well as other conflicts, including in the Middle East), [added: potential tariffs imposed by the United States or other countries on goods and natural resources, including natural gas and LNG,] inflation and U.S. Federal Reserve interest rate [removed: increases] [added: adjustments] in response thereto, [added: and] the availability and cost of credit, [removed: 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.

[added: 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 [removed: schedule.][added: schedule and could impact the development schedule of our midstream customers, thereby resulting in decreased demand for, and revenue from, our midstream services.]

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 [added: and services] align with a low-carbon transition.

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, [added: including enhanced disclosure obligations,] (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 [removed: produce] [added: produce, transport] and sell.

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

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

Further, there have been efforts [removed: 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 [removed: reserves.][added: reserves, which if successful, 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.]

[removed: While our business is not a party to any such litigation, we] [added: We] could be named in actions making similar allegations.

We may not be able to successfully execute our plan to deleverage our business or otherwise reduce our debt [removed: level.][added: level, which could adversely affect our operating flexibility, business, financial condition, results of operations, and cash flows.]

We intend to fund our Debt Retirement Plan through [removed: free cash flow, and have aligned our hedge strategy in a manner that we believe will mitigate] [added: asset monetizations, such as] the [removed: risk of volatility of future natural gas] [added: NEPA Non-Operated Asset Divestitures] and [removed: NGLs prices, which we anticipate will enable us to execute on our Debt Retirement Plan] [added: the Midstream Joint Venture Transaction,] and [removed: other capital allocation strategies;] [added: free cash flow;] however, there can be no assurance that we will be able to generate sufficient [added: monetization proceeds and] free cash flow to execute our Debt Retirement Plan on our anticipated timeframe, if at all.

- aging infrastructure and mechanical or structural problems;

- failure of equipment, facilities or new technology;

- damage to pipelines, wells and storage assets, facilities, equipment, environmental controls and surrounding properties, and pipeline blockages or other operational interruptions, caused or exacerbated by natural phenomena, weather conditions, acts of sabotage, vandalism and terrorism;

- security risks, including cybersecurity incidents;

- inadvertent damage from construction, vehicles, and farm and utility equipment;

- leaks, migrations or losses of natural gas as a result of issues regarding pipeline and/or storage equipment or facilities and, including with respect to storage assets, as a result of undefined boundaries, geologic anomalies, limitations in then-applied industry-standard testing methodologies, operational practices (including as a result of regulatory requirements), natural pressure migration and wellbore migration or other factors relevant to such storage assets;

The location of certain segments of our wells and pipeline systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks.

Accidents or other operating risks have resulted, and in the future could result, in loss of service available to our pipeline customers.

Customer impacts arising from service interruptions on segments of our pipeline systems and/or our assets have included and/or may include, without limitation and as applicable, curtailments, limitations on our ability to satisfy customer contractual requirements, obligations to provide reservation charge credits to customers and solicitation of our existing customers by third parties for potential new projects that would compete directly with our existing services.

Such circumstances could adversely impact our ability to retain customers and negatively impact our business, financial condition, results of operations, and cash flows.

Significant portions of our assets have been in service for several decades.

There could be unknown events or conditions, or increased maintenance or repair expenses and downtime, associated with our assets that could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Significant portions of our transmission and storage systems have been in service for several decades.

The age and condition of these systems has contributed to, and could result in, adverse events, or increased maintenance or repair expenditures, and downtime associated with increased maintenance and repair activities, as applicable.

Any such adverse events or any significant increase in maintenance and repair expenditures or downtime, or related loss of revenue, due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, and cash flows.

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

The development and construction by us or our joint ventures of pipeline and storage facilities and the optimization of such assets involve numerous construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties that are beyond our control, require the expenditure of significant amounts of capital and expose us to risks.

Those risks include, but are not limited to:

- physical construction conditions, such as topographical, or unknown or unanticipated geological, conditions and impediments;

- construction site access logistics;

- crew availability and productivity and ability to adhere to construction workforce drawdown plans;

- adverse weather conditions;

- project opposition, including delays caused by landowners, advocacy groups or activists opposed to our projects and/or the natural gas industry through lawsuits or intervention in regulatory proceedings;

- evolving regulatory or legal requirements and related impacts therefrom, including additional costs of compliance;

- the application of time of year or other regulatory restrictions affecting construction;

- failure to meet customer contractual requirements;

- environmental conditions;

- vandalism and acts of sabotage;

- the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof, including as a result of inflation and/or tariffs);

- issues regarding availability of or access to connecting infrastructure; and

- the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained)

Risks inherent in the construction of these types of projects, such as unanticipated geological conditions, challenging terrain in certain of our construction areas and severe or continuous adverse weather conditions, have adversely affected, and in the future could adversely affect, project timing, completion and costs, as well as increase the risk of loss of human life, personal injuries, significant damage to property or environmental contamination.

Most notably, certain of these risks have been realized in the construction of the MVP, including construction-related risks and adverse weather conditions, and such risks or other risks may be realized in the future which may further adversely affect the timing and/or cost of the MVP and MVP Southgate (defined in Note 11 to the Consolidated Financial Statements).

Given such risks and uncertainties, our midstream projects or those of our joint ventures may not be completed on schedule, within budgeted cost or at all.

As a further example, public participation, including by pipeline infrastructure opponents, in the review and permitting process of projects, through litigation or otherwise, has previously introduced, and in the future could introduce, uncertainty and adversely affect project timing, completion and cost.

Further, civil protests regarding environmental justice, environmental health and safety, and social issues or challenges in project permitting processes related to such issues, including proposed construction and location of infrastructure associated with fossil fuels, poses an increased risk and may lead to increased litigation, legislative and regulatory initiatives and review at federal, state, tribal and local levels of government or permitting delays that can prevent or delay the construction of such infrastructure and realization of associated revenues.

Additionally, construction expenditures on projects generally occur over an extended period, yet we will not receive revenues from, or realize any material increases in cash flow as a result of, the relevant project until it is placed into service.

Moreover, our cash flow from a project may be delayed or may not meet our expectations, including as a result of taxes which could potentially be calculated based on excess expenditures, inclusive of maintenance, incurred during extended court-driven construction delays.

Furthermore, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize or is delayed beyond our expectations.

As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return.

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

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

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

Proved oil and

Global economic conditions, geopolitical issues and inflation

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.

We have published a leverage and debt retirement strategy with the ultimate goal of reducing our absolute debt to $3.5 billion (our Debt Retirement Plan).

Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.

For more information about our debt agreements, read "Capital Resources and Liquidity" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

We cannot

We depend on third-party midstream providers for a significant portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure to successfully deliver natural gas, NGLs and oil to market on competitive terms may adversely affect our earnings, cash flows and results of operations.

Our delivery of natural gas, NGLs and oil depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities primarily owned by third parties, and our ability to contract with these third parties at competitive rates or at all.

The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our natural gas, NGLs and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

Competition for access to pipeline infrastructure within the Appalachian Basin is intense, and our ability to secure access to pipeline infrastructure on favorable economic terms could affect our competitive position.

Although we own and operate certain midstream infrastructure for our own use, we depend on third-party providers to provide us with access to additional midstream infrastructure to get a significant portion of our produced natural gas, NGLs and oil to market.

To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such third-party infrastructure until suitable arrangements are made to market our production.

Access to midstream assets may be unavailable due to market conditions or mechanical or other reasons.

In addition, due to regulatory and economic constraints, construction of new pipelines and building of such infrastructure may occur more slowly.

A lack of access to needed infrastructure, or an extended interruption of access to or service from third-party pipelines and facilities for any reason, including vandalism, terroristic acts, sabotage or cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas, NGLs and oil.

Finally, in order to ensure access to certain midstream facilities, we have entered into agreements that obligate us to pay demand charges to various pipeline operators.

We also have commitments with third parties for processing capacity.

We may be obligated to make payments under these agreements even if we do not fully use the capacity we have reserved, and these payments may be significant.

The substantial majority of our midstream and water services are provided by one provider, Equitrans Midstream.

Therefore, any regulatory, infrastructure or other events that materially adversely affect Equitrans Midstream's business operations will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers.

Additionally, our midstream services contracts with Equitrans Midstream involve significant long-term financial and other commitments on our part, which hinders our ability to diversify our slate of midstream service providers and seek better economic and other terms for the midstream services that are provided to us.

We have no control over Equitrans Midstream's business decisions and operations, and Equitrans Midstream is not under any obligation to adopt a business strategy that favors us.

Historically, we have received the substantial majority of our natural gas gathering, transmission and storage and water services from Equitrans Midstream.

Additionally, on February 26, 2020, we executed a gas gathering agreement with a wholly-owned subsidiary of Equitrans Midstream (the Consolidated GGA), which, among other things, consolidated the majority of our prior gathering agreements with Equitrans Midstream and its subsidiaries into a single agreement, established a new fee structure for gathering and compression fees charged by Equitrans Midstream, increased our minimum volume commitments with Equitrans Midstream, committed certain of our remaining undedicated acreage to Equitrans Midstream and extended our and Equitrans Midstream's contractual obligations with each other to 2035.

Because we have significant long-term contractual commitments with Equitrans Midstream, we expect to receive the majority of our midstream and water services from Equitrans Midstream for the foreseeable future.

Therefore, any event, whether in our areas of operation or otherwise, that adversely affects Equitrans Midstream's operations, water assets, pipelines, other transportation facilities, gathering and processing facilities, financial condition, leverage, results of operations or cash flows will have a disproportionately adverse effect on our business and operating results as compared to similar events experienced by our other third-party service providers.

Accordingly, we are subject to the business risks of Equitrans Midstream, including the following:

- federal, state and local regulatory, political and legal actions that could adversely affect Equitrans Midstream's and its subsidiaries operations, assets and infrastructure, including potential further delays associated with placing the Mountain Valley Pipeline in service;

- construction risks associated with the construction or repair of Equitrans Midstream's pipelines and other midstream infrastructure, such as delays caused by landowners or advocacy groups opposed to the natural gas industry, environmental hazards, adverse weather conditions, the performance of third-party contractors, the lack of available skilled labor, equipment and materials and the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained);

- cyber-attacks or acts of sabotage or terrorism that could cause significant damage or injury to Equitrans Midstream's personnel, assets or infrastructure or lead to extended interruptions of Equitrans Midstream's operations;

Net income attributable to EQT Corporation for [removed: 2023] [added: 2024] was [removed: $1,735] [added: $231] million, [removed: $4.22] [added: $0.45] per diluted share, compared to [removed: $1,771] [added: $1,735] million, [removed: $4.38] [added: $4.22] per diluted share, for [removed: 2022.][added: 2023.]

See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on [Form [removed: 10-K](http://www.sec.gov/ix?doc=/Archives/edgar/data/33213/000003321323000008/eqt-20221231.htm)] [added: 10-K](https://www.sec.gov/ix?doc=/Archives/edgar/data/33213/000003321324000008/eqt-20231231.htm)] for the year ended December 31, [removed: 2022,] [added: 2023,] which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, [removed: 2021.][added: 2022.]

Results of operations for [added: 2024 and] the [removed: period beginning August 22, 2023 through December 31,] [added: second half of] 2023 include the results of our operation of assets acquired in the Tug Hill and XcL Midstream [removed: Acquisition.][added: Acquisition (defined in Note 6 to the Consolidated Financial Statements), which closed on August 22, 2023.]

See Note [removed: 6] [added: 10] to the Consolidated Financial Statements for further discussion of [removed: the Tug Hill and XcL Midstream Acquisition.][added: our debt.]

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

[removed: Future supply chain constraints] [added: Low natural gas prices] or [removed: declines] [added: volatility] in [added: the] natural gas [removed: prices] [added: market] may result in adjustments to our [removed: 2024] [added: 2025] planned development schedule or the development schedule of non-operated wells in which we have a working interest.

Adjustments to our [removed: 2024] [added: 2025] planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

[removed: We] [added: Lastly, we] expect commodity prices to be volatile [removed: throughout 2024] [added: through 2025] due to macroeconomic [removed: uncertainty] [added: uncertainty, changes to the regulatory environment] and geopolitical tensions, including developments pertaining to Russia's invasion of [removed: Ukraine and] [added: Ukraine,] conflicts in the Middle [removed: East.][added: East and potential further imposition of domestic and foreign tariffs.]

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

[removed: Adjusted] [added: Production adjusted] operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends.

[removed: Adjusted] [added: Production adjusted] operating revenues should not be considered as an alternative to total [added: Production] operating revenues.

See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of [added: Production] adjusted operating revenues [removed: with] [added: from] total [added: Production] operating revenues, the most directly comparable financial measure calculated in accordance with [removed: GAAP.][added: United States generally accepted accounting principles (GAAP).]

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

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

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

| Sales volume (MMcf) | | | [added: 2,086,441 | | | | | |] 1,907,343 | | | | | | [removed: 1,842,044] | | |

| NYMEX price ($/MMBtu) | | | $ | [removed: 2.74] [added: 2.30] | | | | | $ | [removed: 6.64] [added: 2.74] | | [added: | | | | | |]

| Btu uplift | | | [added: 0.13 | | | | | |] 0.14 | | | | | | [removed: 0.35] | | |

| Natural gas price ($/Mcf) | | | $ | [removed: 2.88] [added: 2.43] | | | | | $ | [removed: 6.99] [added: 2.88] | | [added: | | | | | |]

| Basis ($/Mcf) (a) | | | $ | [removed: (0.51)] [added: (0.41)] | | | | | $ | [removed: (0.77)] [added: (0.51)] | | [added: | | | | | |]

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

| Average differential, including cash settled basis swaps ($/Mcf) | | | $ | [removed: (0.54)] [added: (0.48)] | | | | | $ | [removed: (0.79)] [added: (0.54)] | | [added: | | | | | |]

| Average adjusted price ($/Mcf) | | | $ | [removed: 2.34] [added: 1.95] | | | | | $ | [removed: 6.20] [added: 2.34] | | [added: | | | | | |]

| Cash settled derivatives ($/Mcf) | | | [added: 0.64 | | | | | |] 0.34 | | | | | | [removed: (3.20)] | | |

| Average natural gas price, including cash settled derivatives ($/Mcf) | | | $ | [removed: 2.68] [added: 2.59] | | | | | $ | [removed: 3.00] [added: 2.68] | | [added: | | | | | |]

| Natural gas sales, including cash settled derivatives | | | $ | [removed: 5,112,278] [added: 5,401,642] | | | | | $ | [removed: 5,529,963] [added: 5,112,278] | | [added: | | | | | |]

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

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

| Sales volume (MMcfe) (b) | | | [added: 87,564 | | | | | |] 64,859 | | | | | | [removed: 56,735] | | |

| Sales volume (Mbbl) | | | [added: 14,594 | | | | | |] 10,810 | | | | | | [removed: 9,456] | | |

| NGLs price ($/Bbl) | | | $ | [removed: 36.39] [added: 39.13] | | | | | $ | [removed: 53.26] [added: 36.39] | | [added: | | | | | |]

| Cash settled derivatives ($/Bbl) | | | [added: (0.30) | | | | | |] (1.27) | | | | | | [removed: (3.91)] | | |

| Average NGLs price, including cash settled derivatives ($/Bbl) | | | $ | [removed: 35.12] [added: 38.83] | | | | | $ | [removed: 49.35] [added: 35.12] | | [added: | | | | | |]

| NGLs sales, including cash settled derivatives | | | $ | [removed: 379,663] [added: 566,808] | | | | | $ | [removed: 466,664] [added: 379,663] | | [added: | | | | | |]

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

| Sales volume (MMcfe) (b) | | | [added: 44,586 | | | | | |] 34,441 | | | | | | [removed: 35,100] | | |

| Sales volume (Mbbl) | | | [added: 7,431 | | | | | |] 5,740 | | | | | | [removed: 5,850] | | |

| Ethane price ($/Bbl) | | | $ | [removed: 6.00] [added: 6.03] | | | | | $ | [removed: 14.20] [added: 6.00] | | [added: | | | | | |]

| Ethane sales | | | $ | [removed: 34,417] [added: 44,806] | | | | | $ | [removed: 83,096] [added: 34,417] | | [added: | | | | | |]

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

Recent and Significant Events

*Midstream Joint Venture Transaction*

On December 30, 2024, in connection with the completion of the Midstream Joint Venture Transaction, the Midstream Joint Venture received $3.5 billion of cash consideration, net of certain transaction fees and expenses, from a third-party investor in exchange for a noncontrolling equity interest in the Midstream Joint Venture.

Borrowings under the Bridge Credit Facility were used to fund the redemption and repurchase of certain of EQM's senior notes, including pursuant to the EQM Tender Offer (defined in Note 10 to the Consolidated Financial Statements).

*NEPA Non-Operated Asset Divestitures and NEPA Gathering System Acquisition*

Results of operations for 2024 include the results of our operation of assets received as consideration for the First NEPA Non-Operated Asset Divestiture, which closed on May 31, 2024.

Such assets received included the remaining 16.25% equity interest in the NEPA Gathering System (defined in Note 6 to the Consolidated Financial Statements) (which was the sole remaining minority interest following our acquisition of a 33.75% equity interest in the NEPA Gathering System Acquisition (defined in Note 6 to the Consolidated Financial Statements) on April 11, 2024), resulting in our 100% ownership of the NEPA Gathering System.

In addition, on December 31, 2024, we completed the Second NEPA Non-Operated Asset Divestiture.

We used the proceeds from the Second NEPA Non-Operated Asset Divestiture of $1.25 billion, subject to customary post-closing purchase price adjustments and transaction costs, to repay a portion of outstanding borrowings under EQT's revolving credit facility.

*Equitrans Midstream Merger*

Results of operations for 2024 include the results of our operation of assets acquired in the Equitrans Midstream Merger, which closed on July 22, 2024.

Following the completion of the Equitrans Midstream Merger, we own a gathering system with 1,975 miles of gathering lines (including gathering lines owned prior to the Equitrans Midstream Merger) and a transmission and storage system with approximately 950 miles of FERC-regulated, interstate pipelines.

See Note 6 to the Consolidated Financial Statements.

For the period from July 22, 2024 through December 31, 2024, our consolidated gathering expense decreased due to our ownership of the gathering and transmission assets acquired in the Equitrans Midstream Merger.

Our ownership of such assets will continue to positively impact our Production segment's gathering expense, with a corresponding increase to our Production segment's affiliate transportation and processing expense, which is eliminated in consolidation.

This relationship will be prominent for full year 2025 results and beyond.

*Tug Hill and XcL Midstream Acquisition*

On March 4, 2024, we announced our decision to strategically curtail approximately 1.0 Bcfe per day of gross production (the Strategic Curtailment) beginning on February 24, 2024 in response to the low natural gas price environment resulting from warm winter weather and elevated storage inventories.

The Strategic Curtailment resulted in total decreased sales volume of 107 Bcfe for 2024.

In addition, certain operators of wells in which we have a non-operating working interest also curtailed production in 2024.

For 2024, we estimate that our total expected sales volume was negatively impacted by approximately 130 to 140 Bcfe of curtailments, including our Strategic Curtailment of 107 Bcfe and curtailments by certain operators of wells in which we have a non-operating working interest.

In connection with the recent U.S. election and corresponding inauguration of President Trump on January 20, 2025, the President executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the institution of tariffs on foreign goods and services.

It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business.

A changing regulatory environment could increase our costs to comply with such regulations or make us susceptible to lawsuits or fines for failure to comply with such regulations.

Further, tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the price of natural gas, increase the price of supplies and raw materials that we rely on to conduct our business, and could impact interest rates.

A changing regulatory environment and domestic or foreign tariffs could ultimately impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.

The decrease was attributable primarily to a lower gain on derivatives, increased depreciation, depletion and amortization, increased other operating expenses and increased net interest expense, partly offset by the gains on the NEPA Non-Operated Asset Divestitures, decreased income tax expense, increased pipeline revenues and decreased transportation and processing expense.

We did not recast our discussion and analysis of financial condition and results of operations for the year ended December 31, 2022 for our change in reportable segments as such change does not materially change our historic comparative discussion of our financial condition and results of operations for the years ended December 31, 2023 and 2022 included within the 2023 Annual Report.

Prior to the Equitrans Midstream Merger, we operated our business as a single segment and did not generate material third-party gathering operating income.

Further, in our judgment, we do not believe such a recast is necessary to an understanding of our business, financial condition, changes in financial condition and results of operations.

See Note 2 to the Consolidated Financial Statements for financial information by business segment, including our profit and loss metric and capital expenditures for the year ended December 31, 2022 and segment assets as of December 31, 2022.

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

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See Note 2 to the Consolidated Financial Statements for a reconciliation of total Production operating revenues to EQT Corporation operating revenues as reported in the Statements of Consolidated Operations.

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

See "Sales Volume and Revenues" and "Operating Expenses" for discussions of items affecting operating income and "Other Income Statement Items" for a discussion of other income statement items.

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

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

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

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

Inflationary pressures have multiple impacts on our business, including increasing our operating expenses and our cost of capital.

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

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

Although we believe our scale and supply chain contracting strategy of using multi-year sand and frac crew contracts allows us to maximize capital and operating efficiencies, future increases in the inflation rate will negatively impact our long-term contracts with consumer price index adjustments.

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

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

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 | | |

Because we consider net marketing services and other to be unrelated to our natural gas and liquids production activities, adjusted operating revenues excludes net marketing services and other.

We believe that adjusted operating revenues provides useful information to investors for evaluating period-to-period comparisons of earnings trends.

| Total operating revenues | | | $ | 6,908,923 | | | | | $ | 7,497,689 | |

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

| Net marketing services and other | | | 25,214 | | | | | | 26,453 | | | | | | (1,239) | | | | | | (4.7) | | |

| 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.

| | | | (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) | |

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

| Gathering | | | $ | 1,282,402 | | | | | $ | 1,316,213 | | | | | $ | (33,811) | | | | | (2.6) | | |

| Transmission | | | 642,688 | | | | | | 601,497 | | | | | | 41,191 | | | | | | 6.8 | | |

| Processing | | | 232,170 | | | | | | 199,266 | | | | | | 32,904 | | | | | | 16.5 | | |

| Lease operating expenses (LOE) | | | 158,973 | | | | | | 156,523 | | | | | | 2,450 | | | | | | 1.6 | | |

| Production taxes | | | 95,727 | | | | | | 144,462 | | | | | | (48,735) | | | | | | (33.7) | | |

| Exploration | | | 3,330 | | | | | | 3,438 | | | | | | (108) | | | | | | (3.1) | | |

| Production depletion | | | $ | 1,702,198 | | | | | $ | 1,644,625 | | | | | $ | 57,573 | | | | | 3.5 | | |

| Other depreciation and depletion | | | 29,944 | | | | | | 21,337 | | | | | | 8,607 | | | | | | 40.3 | | |

| Total depreciation and depletion | | | $ | 1,732,142 | | | | | $ | 1,665,962 | | | | | $ | 66,180 | | | | | 4.0 | | |

| Gathering | | | $ | 0.64 | | | | | $ | 0.68 | | | | | $ | (0.04) | | | | | (5.9) | | |

Prolonged low, or significant, extended declines in, natural gas and NGLs prices could adversely affect, among other things, our development plans, which would decrease the pace of development and the level of our proved [removed: reserves.][added: reserves and, similarly, could adversely affect timing of development of additional reserves and production that is accessible by our pipeline and storage assets and limit growth in, or may reduce the demand for, and usage of, our gathering or transmission and storage services.]

Our use of derivatives is further described in Note [removed: 3] [added: 4] to the Consolidated Financial Statements and "Commodity Risk Management" under "Capital Resources and Liquidity" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." Our OTC derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of those institutions is regularly monitored.

A hypothetical decrease of 10% in the NYMEX natural gas price on December 31, [removed: 2023] [added: 2024] and [removed: 2022] [added: 2023] would increase the fair value of our natural gas derivative commodity instruments by approximately [removed: $204] [added: $283] million and [removed: $727] [added: $204] million, respectively.

A hypothetical increase of 10% in the NYMEX natural gas price on December 31, [removed: 2023] [added: 2024] and [removed: 2022] [added: 2023] would decrease the fair value of our natural gas derivative commodity instruments by approximately [removed: $482] [added: $340] million and [removed: $333] [added: $482] million, respectively.

For purposes of this analysis, we applied the 10% change in the NYMEX natural gas price on December 31, [removed: 2023] [added: 2024] and [removed: 2022] [added: 2023] to our natural gas derivative commodity instruments as of December 31, [removed: 2023] [added: 2024] and [removed: 2022] [added: 2023] to calculate the hypothetical change in fair value.

The change in fair value was determined using a method similar to our normal process for determining derivative commodity instrument fair value described in Note [removed: 4] [added: 5] to the Consolidated Financial Statements.

*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 [removed: our] [added: EQT's] revolving credit [added: facility, Eureka's revolving credit] facility and [added: (prior to its payoff and termination)] the Term Loan Facility.

None of the interest we pay on [removed: our] [added: EQT's or EQM's] senior notes fluctuates based on changes to market interest rates.

A 1% increase in interest rates for the borrowings under [removed: our] [added: EQT's] revolving credit [added: facility, Eureka's revolving credit] facility and the Term Loan Facility during [removed: 2023] [added: 2024] would have increased interest expense by approximately [removed: $12.9] [added: $15.6] million.

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

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

See Note [removed: 8] [added: 10] to the Consolidated Financial Statements for further discussion of our debt and Note [removed: 4] [added: 5] to the Consolidated Financial Statements for a discussion of fair value measurements, including the fair value measurement of our debt.

Approximately [removed: 36%,] [added: 20%,] or [removed: $710] [added: $93] million, of our OTC derivative contracts outstanding at December 31, [removed: 2022] [added: 2024] had a positive fair value.

As of December 31, [removed: 2023,] [added: 2024,] we were not in default under any derivative contracts and had no knowledge of default by any counterparty to our derivative contracts.

During [removed: 2023,] [added: 2024,] we made no adjustments to the fair value of our derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in our established fair value procedure.

[removed: No] [added: As of December 31, 2024, no] one lender of the large group of financial institutions in the syndicate for [removed: our] [added: EQT's] revolving credit facility [removed: and the Term Loan Facility holds] [added: held] more than 10% of the financial commitments [removed: under either facility.][added: thereunder.]

Price declines and sustained periods of low natural gas and NGLs prices could also have an adverse effect on the creditworthiness of our gathering, transmission and storage customers and related ability to pay firm reservation fees under long-term contracts.

In addition, changes in Eureka's Consolidated Leverage Ratio (defined in that certain Credit Agreement, dated May 13, 2021, among Eureka, Sumitomo Mitsui Banking Corporation, as administrative agent, the lenders party thereto from time to time and any other persons party thereto from time to time, as amended, governing Eureka's revolving credit facility (the Eureka Credit Agreement)) as a result on Eureka's liquidity needs, operating results or distributions to its members affect the interest rate Eureka pays on borrowings under its revolving credit facility.

In addition, as of December 31, 2024, no one lender of the large group of financial institutions in the syndicate for Eureka's revolving credit facility held more than 13% of the financial commitments thereunder.

We are a [added: vertically integrated] natural gas [removed: production] company with [added: production, gathering and transmission] operations focused in the Appalachian Basin.

As of December 31, [removed: 2023,] [added: 2024,] we had [removed: 27.6] [added: 26.3] Tcfe of proved natural gas, NGLs and oil reserves across approximately 2.1 million gross [removed: acres, and, based on average daily sales volume, we were the largest producer] [added: acres and approximately 2,925 miles] of [removed: natural gas in the United States.][added: pipeline infrastructure.]

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

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

Our business model [removed: has been developed to enable] [added: enables] us to generate [removed: sustainable] [added: durable] free cash flow and correspondingly, we have implemented a robust capital allocation strategy directed at responsibly developing our assets [added: and positioning us for organic growth,] while also returning capital to our shareholders through a combination of debt retirements, [removed: dividends] [added: a base dividend] and [removed: strategic] [added: opportunistic] share repurchases.

We are also focused on maintaining [added: and strengthening our] investment grade credit metrics, which [removed: allows us] [added: improve our access] to [removed: capture a lower cost of] [added: reliable, low-cost] capital [removed: and further enhance shareholder returns.][added: throughout market cycles.]

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

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

- Paid [removed: $228] [added: $327] million in [added: aggregate] dividends to shareholders.

- Completed the [removed: Tug Hill and XcL] [added: Equitrans] Midstream [removed: Acquisition] [added: Merger] (defined [removed: and discussed] in Note 6 to the Consolidated Financial Statements).

In [removed: 2024,] [added: 2025,] we expect to spend approximately [removed: $2.15] [added: $2.3] billion to [removed: $2.35] [added: $2.5] billion [removed: in] [added: on] total capital expenditures.

We expect to allocate the total planned capital expenditures as follows: approximately [removed: $1,685] [added: $1,445] million to [removed: $1,775] [added: $1,555] million to fund reserve development, approximately [removed: $220] [added: $160] million to [removed: $250] [added: $180] million to fund [removed: midstream] [added: land] and [added: lease acquisitions, approximately $80 million to $90 million to fund] other [added: production] infrastructure, approximately [removed: $125] [added: $360] million to [removed: $190] [added: $390] million to fund [removed: land and lease acquisitions,] [added: gathering infrastructure,] approximately [removed: $70] [added: $50] million to [removed: $80] [added: $60] million [removed: towards capitalized overhead] [added: to fund transmission infrastructure] and approximately [removed: $50] [added: $205] million to [removed: $55] [added: $225] million towards capitalized [removed: interest] [added: interest, capitalized overhead] and [removed: other items.][added: other.]

[removed: Included in] [added: Of the] total planned capital [removed: expenditures is] [added: expenditures, we expect to allocate] approximately [removed: $200] [added: $350] million to [removed: $300] [added: $380] million [removed: for] [added: to] strategic growth projects composed of approximately [removed: $70] [added: $85] million to [removed: $90] [added: $95] million for water infrastructure within reserve development, approximately [removed: $50] [added: $130] million to [removed: $70] [added: $140] million for growth projects within [removed: midstream and other] [added: gathering] infrastructure and approximately [removed: $80] [added: $135] million to [removed: $140] [added: $145] million for in-fill leasing [removed: and mineral purchases] within land and lease acquisitions.

In [removed: 2024,] [added: 2025,] we expect our sales volume to be [removed: 2,200] [added: 2,175] Bcfe to [removed: 2,300] [added: 2,275] Bcfe.

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

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

Lower prices and changes in our development plans could also result in non-cash impairments in the book value of our oil and gas properties [added: and midstream infrastructure] or downward adjustments to our estimated proved reserves.

[removed: Reserves][added: *Reserves*]

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

| Proved undeveloped reserves | | | [removed: 7,609] [added: 7,105] | | | | | | [removed: 72] [added: 59] | | | | | | [removed: 8,039] [added: 7,460] | | |

[removed: (a)The Marcellus Shale comprises 91%] [added: 90%] of our total proved developed reserves, 98% of our total proved undeveloped reserves and [removed: 93%] [added: 92%] of our total proved [removed: reserves.][added: reserves are located in the Marcellus Shale.]

| | | | Pennsylvania | | | | | | West Virginia | | | | | | Ohio | | | | | | [removed: | | | | | |] Total | | |

| Gross proved undeveloped drilling locations | | | [removed: 222] [added: 178] | | | | | | [removed: 191] [added: 181] | | | | | | [removed: 4] [added: 3] | | | | | | | | | | | | [removed: 417] [added: 362] | | |

| Net proved undeveloped drilling locations | | | [removed: 174] [added: 150] | | | | | | [removed: 172] [added: 158] | | | | | | [removed: 1] [added: 3] | | | | | | | | | | | | [removed: 347] [added: 311] | | |

Our [removed: 2023] [added: 2024] total proved reserves [removed: increased] [added: decreased] by [removed: 2,594] [added: 1,332] Bcfe, or [removed: 10.4%,] [added: 4.8%,] compared to [removed: 2022] [added: 2023] due to [removed: extensions, discoveries and other additions] [added: production] of [removed: 3,412 Bcfe and acquisitions] [added: 2,228 Bcfe, negative revisions] of [removed: 2,600] [added: previous estimates of 1,080] Bcfe [added: and decreases] from the [removed: Tug Hill and XcL Midstream Acquisition,] [added: NEPA Non-Operated Asset Divestitures of 1,563 Bcfe,] partly offset by [removed: production] [added: extensions, discoveries and other additions] of [removed: 2,016] [added: 3,126] Bcfe and [removed: revisions to previous estimates] [added: acquisitions from the First NEPA Non-Operated Asset Divestiture] of [removed: 1,402] [added: 413] Bcfe.

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

| Conversions into proved developed reserves | | | [removed: (2,561)] [added: (2,637)] | | |

| Revision of previous estimates [removed: (a)] [added: (b)] | | | [removed: (832)] [added: (823)] | | |

| Extensions, discoveries and other additions [removed: (b)] [added: (c)] | | | [removed: 3,103] [added: 3,069] | | |

[removed: (a)Composed] [added: (b)Composed] of (i) negative revisions of [removed: 755] [added: 925] Bcfe related to proved undeveloped locations that we no longer expect to develop as proved reserves within five years of initial booking [added: primarily] as a result of development schedule changes, (ii) negative revisions of [removed: 367] [added: 87] Bcfe [removed: due] primarily [added: related] to revisions to [removed: type curves] [added: lateral lengths] and [removed: commodity price change,] [added: type curves,] partly offset by (iii) positive revisions of [removed: 290] [added: 189] Bcfe due [added: primarily] to changes in ownership interests.

[removed: (b)Composed] [added: (c)Composed] of (i) [removed: 1,670] [added: 2,912] Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to [removed: 2023] [added: 2024] reserve development that expanded the number of our proven locations and additions to our five-year drilling [removed: 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 [removed: (iii)] [added: (ii)] positive revisions of [removed: 92] [added: 157] Bcfe from the extension of lateral lengths of proved undeveloped reserves.

As of December 31, [removed: 2023,] [added: 2024,] we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

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

| | | | [removed: 2023] [added: 2024] | | | | | | [removed: 2022] [added: 2023] | | | | | | [removed: 2021] [added: 2022] | | |

| Future net cash flow | | | $ | [removed: 19,031] [added: 17,094] | | | | | $ | [removed: 87,612] [added: 19,031] | | | | | $ | [removed: 36,567] [added: 87,612] | |

| PV-10 (a) | | | [removed: 11,520] [added: 9,844] | | | | | | [removed: 51,512] [added: 11,520] | | | | | | [removed: 21,496] [added: 51,512] | | |

| Natural gas price ($/Mcf) | | | $ | [removed: 1.700] [added: 1.468] | | | | | $ | [removed: 5.543] [added: 1.700] | | | | | $ | [removed: 2.694] [added: 5.543] | |

| NGLs price ($/Bbl) | | | [removed: 28.44] [added: 29.28] | | | | | | [removed: 38.66] [added: 28.44] | | | | | | [removed: 29.95] [added: 38.66] | | |

| Oil price ($/Bbl) | | | [removed: 63.86] [added: 59.45] | | | | | | [removed: 76.83] [added: 63.86] | | | | | | [removed: 51.57] [added: 76.83] | | |

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

In addition, we operate and hold an investment in the Mountain Valley Pipeline (the MVP), a 303-mile long pipeline that spans from Wetzel County, West Virginia to Pittsylvania County, Virginia.

Our business strategy is to be the lowest-cost producer of natural gas.

The durability of this strategy relies on our substantial inventory of core drilling locations, our vast midstream infrastructure spanning the Appalachian Basin, our investment grade balance sheet, the low emissions profile of our operations and our best-in-class team and culture.

As the only large-scale, integrated natural gas producer in the United States, we are situated to endure and excel during times of market volatility.

In periods of low commodity prices, our integrated business model is designed to produce durable free cash flow due to the annuity-like nature of our midstream assets.

In periods of high commodity prices, our low-cost structure permits lower levels of financial hedging, thus providing increased exposure to higher natural gas prices.

Our peer-leading drilling inventory coupled with our midstream ownership and operatorship also positions us to provide production growth to serve growing demand from the power and LNG markets.

Our operational strategy is further enhanced by our robust midstream pipelines and services, enabling us to keep our development costs low and limiting our need to hedge our future production, providing both downside protection and better exposure to natural gas price increases in the face of a volatile commodity market.

2024 and Recent Highlights

- Generated $2.8 billion of net cash provided by operating activities.

- Completed the First NEPA Non-Operated Asset Divestiture (defined in Note 7 to the Consolidated Financial Statements) in May 2024 and the Second NEPA Non-Operated Asset Divestiture (defined in Note 7 to the Consolidated Financial Statements) in December 2024.

- Completed the Midstream Joint Venture Transaction (defined in Note 8 to the Consolidated Financial Statements).

- Retired $4.3 billion aggregate principal of senior notes and term loans outstanding under the Term Loan Facility (defined in Note 10 to the Consolidated Financial Statements).

We are committed to maintaining investment grade credit metrics.

In 2024, we published a leverage and debt retirement strategy with the goal of reducing our debt to $7.5 billion by the end of 2025, and, in 2025, we published an update to our leverage and debt retirement strategy with the long-term goal of reducing our debt to $5.0 billion, subject to the overall performance of the commodity markets (our Debt Retirement Plan).

Prior to the completion of the Equitrans Midstream Merger, we reported our results of operations as a single consolidated segment.

Thereafter, and as a result thereof, we adjusted our internal reporting structure and our chief operating decision maker changed the manner in which he measures financial performance and allocates resources to incorporate the gathering and transmission assets we acquired in the Equitrans Midstream Merger.

Hence, our operations expanded to comprise three discrete segments reflective of our three lines of business of Production, Gathering and Transmission.

Accordingly, the manner in which we report our operations has been changed retrospectively, with certain prior period amounts recast between our Production segment and Gathering segment.

See Note 2 to the Consolidated Financial Statements as well as Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further discussion of our reportable segments.

The following table summarizes the composition of our operating revenues by business segment.

| Production (a) | | | $ | 5,009,833 | | | | | $ | 6,896,358 | | | | | $ | 7,484,063 | |

| Gathering (b) | | | 749,700 | | | | | | 161,395 | | | | | | 96,947 | | |

| Transmission (b) | | | 218,293 | | | | | | — | | | | | | — | | |

| Total Segment | | | 5,977,826 | | | | | | 7,057,753 | | | | | | 7,581,010 | | |

| Intersegment eliminations and other (c) | | | (704,517) | | | | | | (148,830) | | | | | | (83,321) | | |

| EQT Corporation | | | $ | 5,273,309 | | | | | $ | 6,908,923 | | | | | $ | 7,497,689 | |

(a)Primarily sales of natural gas, NGLs and oil and, for 2023 and 2022, gain (loss) on derivatives.

(b)Primarily pipeline revenues.

(c)Primarily elimination of intercompany transactions between our Production segment and our Gathering or Transmission segments for the transportation of our natural gas.

Production Segment Assets and Operations

| | | | December 31, 2024 | | | | | | | | | | | | | | |

| Proved developed reserves | | | 17,440 | | | | | | 227 | | | | | | 18,805 | | |

| Total proved reserves | | | 24,545 | | | | | | 286 | | | | | | 26,265 | | |

| | | | December 31, 2024 | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Proved developed reserves | | | 12,093 | | | | | | 5,850 | | | | | | 862 | | | | | | | | | | | | 18,805 | | |

| Proved undeveloped reserves | | | 3,741 | | | | | | 3,677 | | | | | | 42 | | | | | | | | | | | | 7,460 | | |

| Total proved reserves | | | 15,834 | | | | | | 9,527 | | | | | | 904 | | | | | | | | | | | | 26,265 | | |

Our 2024 proved undeveloped reserves decreased by 579 Bcfe, or 7.2%, compared to 2023.

| Balance at January 1, 2024 | | | 8,039 | | |

We measure sustainability through consideration of our best-in-class team and culture, the ESG performance of our operations, our substantial inventory of core drilling locations and 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 digitally-enabled exploration and production business enhances our strategic advantage.

Operational efficiencies realized from combo-development are passed on to our service providers, which reduces overall contract rates.

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; timely midstream connectivity; and the ability to quickly respond to internal and external stimuli.

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

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.

- Increased quarterly base dividend by 5% to $0.1575 per share ($0.63 per share annualized).

- Repurchased $200 million of common stock, reducing our outstanding share count by 5.9 million shares.

- 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.

We are committed to maintaining investment grade credit metrics, and we have a goal to reduce our absolute debt to $3.5 billion, subject to the overall performance of the commodity markets.

Our operations consist of one reportable segment.

We have a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments.

We measure financial performance as a single enterprise and not on an area-by-area basis.

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

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

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

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

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

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

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

| Proved developed non-producing reserves | | | 601 | | | | | | 234 | | | | | | 4 | | | | | | | | | | | | 839 | | |

| 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 | | |

| Acquisition of in-place reserves | | | 840 | | |

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

| Standardized measure of discounted future net cash flow | | | 9,262 | | | | | | 40,065 | | | | | | 17,281 | | |

| Standardized measure of discounted future net cash flow | | | $ | 9,262 | | | | | $ | 40,065 | | | | | $ | 17,281 | |

We believe that our combo-development strategy, coupled with our undeveloped inventory located in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.

Properties

| 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 | | |

Environmental Proceedings

*Pratt Storage Field Matter, Morgan Township, Pennsylvania*.

On October 31, 2018, a gas explosion occurred in Morgan Township, Greene County, Pennsylvania (the Pratt Incident), close in proximity to Equitrans, L.P.'s (one of our subsidiaries) Pratt Storage Field assets.

Following the explosion, the Pennsylvania Department of Environmental Protection (PADEP), the Pennsylvania Public Utilities Commission and the PHMSA began investigating the Pratt Incident.

The PADEP issued a final report and closed its investigation in August 2022, and we do not expect further inquiry from the PADEP on this matter; however, the Pennsylvania Public Utilities Commission and PHMSA investigations are still pending.

On October 23, 2023, Equitrans, L.P. received permission from the FERC to plug and abandon the AH Hupp 3660 storage well (Hupp Well) in the Pratt Storage Field that was the subject of the PADEP's investigation of the Pratt Incident.

On October 22, 2024, Equitrans, L.P. received from the FERC an extension until January 31, 2025 to complete plugging and abandonment of the Hupp Well.

On January 24, 2025, Equitrans, L.P. requested an additional extension of time, until July 31, 2025, to complete the plugging and abandonment of the Hupp Well.

On October 30, 2023, Equitrans, L.P. received a criminal complaint from the State Attorney General's Office charging Equitrans, L.P. with violations of Pennsylvania's Clean Streams Law (the Pratt Complaint), and generally alleging that: (i) natural gas leaked from the Hupp Well and into a water well and (ii) Equitrans, L.P. failed to conduct a stray gas investigation of the Pratt Incident.

The Pratt Complaint carries the possibility of a monetary sanction, that if imposed could result in a fine in excess of $300,000; however, we expect that the resolution of this matter will not have a material adverse impact on our financial condition, results of operations or liquidity.

*Rager Mountain Storage Field Venting, Jackson Township, Pennsylvania.* On November 6, 2022, Equitrans Midstream became aware of natural gas venting from one of the storage wells, well 2244, at Equitrans, L.P.'s Rager Mountain natural gas storage facility (the Rager Mountain Facility), located in Jackson Township, a remote section of Cambria County, Pennsylvania.

Venting at the Rager Mountain Facility was halted on November 19, 2022.

Since the time of the incident, the PADEP has concluded its investigation and the PHMSA and other investigators are continuing to conduct civil and criminal investigations of the incident, and we are cooperating in such investigations.

On December 29, 2022, the PHMSA issued Equitrans Midstream a Notice of Proposed Safety Order that included proposed remedial requirements related to the Rager Mountain Facility incident, including, but not limited to, completing a root cause analysis, and subsequently, on May 26, 2023, the PHMSA issued a consent order to Equitrans Midstream requiring the completion of a root cause analysis and a remedial work plan and providing that Equitrans Midstream may not resume injection operations at the Rager Mountain Facility until authorized by the PHMSA.

In August 2023, Equitrans Midstream submitted a root cause analysis to the PHMSA and later submitted a remedial work plan and injection plan seeking authority to resume injections at the Rager Mountain Facility using all wells in the facility except three, which remained disconnected from the storage field.

On October 2, 2023, the PHMSA approved Equitrans Midstream's injection plan and Equitrans Midstream restarted injections at the Rager Mountain Facility on October 5, 2023, subject to certain pressure restrictions and other requirements in the PHMSA consent agreement.

On November 16, 2023, the PHMSA issued a letter to Equitrans Midstream approving Equitrans Midstream's request to remove all pressure restrictions at the Rager Mountain Facility.

On May 30, 2024, the PHMSA approved resuming operations for one of the three remaining wells excluded from the injection plan.

We plan to continue working with the PHMSA, pursuant to the consent order between PHSMA and Equitrans Midstream, regarding the remaining two disconnected wells at the Rager Mountain Facility.

If additional penalties are pursued and ultimately imposed related to the Rager Mountain Facility incident, the penalties, individually and/or in the aggregate, may exceed $300,000; however, we expect that the resolution of this matter will not have a material adverse impact on our financial condition, results of operations or liquidity.

*Plugging and Abandoning of Wells at the Holbrook Storage Reservoir, Center Township, Pennsylvania.* One of our wholly owned subsidiaries, EQT Gathering, LLC, is the owner of fifteen inactive storage wells within the Holbrook storage reservoir located in Center Township, Pennsylvania.

The wells have been inactive since 2021.

On June 10, 2024, we were notified by the PADEP of alleged violations of the 2012 Oil and Gas Act, which requires wells located in Pennsylvania which are inactive for a period of twelve months to be reported to the PADEP as "inactive" and plugged.

We are actively working with the PADEP to plug the inactive wells in accordance with the 2012 Oil and Gas Act and resolve this matter, and in connection therewith, we may be assessed a monetary penalty in excess of $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.

| | | | FOR THE FISCAL YEAR ENDED DECEMBER 31, [removed: 2023] [added: 2024] | | | | | |

COMMISSION FILE [removed: NUMBER] [added: NUMBER:] 001-03551

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T [removed: (§ 232.405] [added: (§232.405] of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting [removed: company] [added: company,] or an emerging growth company.

See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting [removed: company"] [added: company,"] and "emerging growth company" in Rule 12b-2 of the Exchange Act.

The aggregate market value of common stock, no par value, held by non-affiliates of the registrant as of June [removed: 30, 2023: $14.7] [added: 28, 2024: $16.2] billion

The number of shares of common stock, no par value, of the registrant outstanding (in thousands) as of February [removed: 9, 2024: 440,427][added: 14, 2025: 597,441]

EQT Corporation's definitive proxy statement relating to its [removed: 2024] [added: 2025] annual meeting of shareholders will be filed with the Securities and Exchange Commission within 120 days after the [removed: close] [added: end] of EQT Corporation's fiscal year ended December 31, [removed: 2023] [added: 2024] and is incorporated by reference into Part III of this Annual Report on Form 10-K to the extent described therein.

| [Glossary of Commonly Used Terms, Abbreviations and [removed: Measurements](#ie0b378c37216402fa1fab6dafbf447c8_10)] [added: Measurements](#iebd86f14a05b4d17bef97d4752e32e1d_10)] | | | | | | [removed: [3](#ie0b378c37216402fa1fab6dafbf447c8_10)] [added: [3](#iebd86f14a05b4d17bef97d4752e32e1d_10)] | | |

| [Summary of Risk [removed: Factors](#ie0b378c37216402fa1fab6dafbf447c8_13)] [added: Factors](#iebd86f14a05b4d17bef97d4752e32e1d_13)] | | | | | | [removed: [6](#ie0b378c37216402fa1fab6dafbf447c8_13)] [added: [6](#iebd86f14a05b4d17bef97d4752e32e1d_13)] | | |

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*Unless the context otherwise indicates, all references in this report to [removed: "EQT,"] [added: "EQT" are to EQT Corporation, and all references in this report to] the "Company," "we," "us," or "our" are to EQT Corporation and its [added: consolidated] subsidiaries, collectively*.

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

These risks are not necessarily unique to us, but rather, these are risks [removed: that] [added: to which] most operators in our industry have at least some [removed: exposure to.][added: exposure.]

- Financial and Market Risks. Given that our primary product and source of revenue is the [added: gathering, transmission and] sale of natural gas and NGLs, one of our most material risks is the commodity market and the price of natural gas and NGLs, which is often volatile.

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

| [Signatures](#iebd86f14a05b4d17bef97d4752e32e1d_193) | | | | | | [162](#iebd86f14a05b4d17bef97d4752e32e1d_193) | | |

delivery point – the point where gas is delivered into a downstream gathering system or transmission pipeline.

minimum volume commitment (MVC) – contract for gathering services that obligate the customer to pay for a fixed amount of volume daily, monthly, annually or over the life of the contract.

throughput – the volume of natural gas transported through a pipeline, plant, terminal or other facility.

working gas – the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility.

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

We maintain [removed: an] [added: a management-level] Enterprise Risk Committee, composed of our Chief Financial Officer, [removed: General Counsel,] Chief [removed: Information] [added: Legal and Policy] 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.

Cybersecurity risk was classified as a Tier 1 enterprise risk for our [removed: company] [added: Company] by our Enterprise Risk Committee for [removed: 2023.][added: 2024.]

Our Board of Directors has delegated to its Audit Committee [added: (the 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 [removed: of our Board of Directors] regarding cybersecurity matters and our enterprise cybersecurity program.

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

We maintain a Cybersecurity Incident Management Policy (Cybersecurity Policy), which provides guidance and processes for [added: preventing,] identifying, [removed: reporting,] assessing, [added: mitigating,] resolving and ensuring timely public disclosure, when appropriate, of cybersecurity threats, including both cybersecurity threats directed at our [removed: company] [added: 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 [removed: integration vendors] [added: technology providers] to help us recover or rebuild technology systems in the event of a large-scale cybersecurity incident.

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

We also own or lease office space in Pennsylvania, West [removed: Virginia] [added: Virginia, Ohio] and Texas.

Information about our Executive Officers (as of February [removed: 14, 2024)][added: 19, 2025)]

| Tony Duran [removed: (45)] [added: (46)] | | | | | | Chief Information Officer (2019) | | | | | | Mr. Duran was appointed as [removed: the] Chief Information Officer of EQT Corporation in July 2019. Prior to joining [removed: EQT Corporation,] [added: EQT,] Mr. Duran ran PH6 Labs, a technology incubator he founded, from December 2017 to July 2019. Prior to that, he served as [removed: the] Chief Information Officer of Rice Energy Inc. (independent natural gas and oil company acquired by EQT [removed: Corporation] in November 2017) from January 2016 to November 2017; and as [removed: 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. [removed: 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: (46)] [added: (47)] | | | | | | Chief Human Resources Officer (2019) | | | | | | Ms. Evancho was appointed as [removed: the] Chief Human Resources Officer of EQT Corporation in July 2019. Prior to joining [removed: EQT Corporation,] [added: EQT,] 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. [removed: 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: (41)] [added: (42)] | | | | | | Chief Accounting Officer (2019) | | | | | | Mr. James was appointed as [removed: the] Chief Accounting Officer of EQT Corporation in November 2019. Prior to joining [removed: EQT Corporation,] [added: EQT,] Mr. James served as [removed: 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 [removed: the] Senior Director, Technical Accounting and Financial Reporting at Rice Energy Inc. from December 2014 through its acquisition by EQT [removed: 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: (43)] [added: (44)] | | | | | | [removed: Executive Vice President, General Counsel] [added: Chief Legal] and [added: Policy Officer and] Corporate Secretary (2019) | | | | | | Mr. Jordan was appointed as [removed: the Executive Vice President] [added: Chief Legal] and [removed: General Counsel] [added: Policy Officer] of EQT Corporation in [removed: July 2019] [added: October 2024] and assumed the role of Corporate Secretary in November 2020. [added: Prior to his current role,] Mr. Jordan served as [added: EQT’s Executive Vice President and General Counsel from July 2019 through September 2024. Mr. Jordan served as] an advisor to the Rice Investment Group (multi-strategy investment fund investing in all verticals of the oil and gas sector) from May 2018 [removed: until] [added: to] July 2019. Prior to that, he served as [removed: 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 [removed: Corporation] in November 2017. From September 2005 to December 2013, Mr. Jordan was an [removed: associate] [added: Associate] at Vinson & Elkins LLP [removed: (an international] [added: (international] law firm) representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. | | |

| Jeremy T. Knop [removed: (35)] [added: (36)] | | | | | | Chief Financial Officer (2023) | | | | | | Mr. Knop was appointed as [removed: 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 [removed: EQT Corporation’s] [added: EQT’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 [removed: through] [added: to] March 2022. Prior to joining [removed: EQT Corporation,] [added: EQT,] 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. | | |

| Toby Z. Rice [removed: (42)] [added: (43)] | | | | | | 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 [removed: EQT Corporation's] [added: EQT'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 [removed: 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 [removed: Inc.] from October 2013 to November 2017. Prior to that, he served in a number of positions with Rice [removed: Energy Inc.,] [added: Energy,] its affiliates and predecessor entities beginning in February 2007, including as President and Chief Executive Officer of a predecessor entity from February 2008 through September 2013. Mr. Rice is the brother of Daniel J. Rice IV, a member of [removed: EQT Corporation's] [added: EQT's] Board of Directors since November 2017. | | |

| J.E.B. Bolen (46) | | | | | | Executive Vice President Operations (2024) | | | | | | Mr. Bolen was appointed as Executive Vice President Operations of EQT Corporation in October 2024. Before moving to that role, he served as EQT’s Senior Vice President Operations Planning from February 2023 to October 2024, and Vice President Operations Planning from July 2019 to February 2023. Prior to joining EQT, Mr. Bolen was Director, Upstream Development for the Shalennial Group LLC (digital oilfield solutions company), from March 2018 to July 2019. | | |

| Sarah Fenton (46) | | | | | | Executive Vice President Upstream (2024) | | | | | | Ms. Fenton was appointed as Executive Vice President Upstream of EQT Corporation in October 2024. Previously, Ms. Fenton served as EQT’s Senior Vice President Asset Performance from February 2023 to October 2024, and Vice President Asset Performance from July 2019 to February 2023. | | |

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

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

| Name and Age | | | | | | Current Title (Year Initially Elected an Executive Officer) | | | | | | Business Experience | | |

| Robert R. Wingo (46) | | | | | | Executive Vice President Corporate Ventures & Midstream (2024) | | | | | | Mr. Wingo was appointed as Executive Vice President Corporate Ventures & Midstream of EQT Corporation in October 2024. Prior to his current role, Mr. Wingo was EQT’s Executive Vice President Corporate Ventures from September 2021 to October 2024. Prior to joining EQT, Mr. Wingo served as Managing Director at Encap Flatrock Midstream (venture capital and private equity investment fund) from March 2018 through August 2021. Prior to that he was Senior Vice President of Midstream and Marketing at Rice Energy Inc., as well as Chief Operating Officer and a member of the Board of Directors for Rice Midstream Partners LP, from June 2013 and December 2014, respectively, until their acquisition by EQT in November 2017. | | |

As of February [removed: 9, 2024,] [added: 14, 2025,] there were [removed: 1,735] [added: 3,084] shareholders of record of our common stock.

On February [removed: 8, 2024,] [added: 6, 2025,] our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT [removed: Corporation] common stock, payable on March [removed: 1, 2024,] [added: 3, 2025,] to shareholders of record at the close of business on February [removed: 20, 2024.][added: 18, 2025.]

We did not repurchase any equity securities registered under Section 12 of the Exchange Act during the three months ended December 31, [removed: 2023.][added: 2024.]

Repurchases under the Share Repurchase Program may be made from time to time in amounts [removed: and] at prices we deem appropriate and will be subject to a variety of factors, including the market price of our common stock, general market and economic conditions, applicable legal requirements and other considerations.

As a result of [removed: such] [added: the most recent] extension, the Share Repurchase Program will expire on December 31, [removed: 2024,] [added: 2026,] but it may be suspended, modified or discontinued at any time without prior notice.

As of December 31, [removed: 2023,] [added: 2024,] we had purchased shares for an aggregate purchase price of $622.1 million, excluding fees, commissions and expenses, under the Share Repurchase Program since its inception, and the approximate dollar value of shares that may yet be purchased under the Share Repurchase Program is $1.4 billion.

The [added: following] graph [removed: 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: 2022] [added: 2023] Self-Constructed Peer Group and the [removed: 2023] [added: 2024] Self-Constructed Peer Group, whose company composition is discussed in footnotes (a) and (b), respectively, below.

Our common stock was included in the S&P [removed: 500 Index] [added: MidCap 400 index] until [removed: November 2018,] [added: October 2022,] at which time our common stock was added to the S&P [removed: MidCap 400] [added: 500] Index.

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: 2018] [added: 2019] and its relative performance is tracked through December 31, [removed: 2023.][added: 2024.]

[removed: ![2023 Stock] [added: ![Stock] Performance [removed: Graph.jpg](https://www.sec.gov/Archives/edgar/data/33213/000003321324000008/eqt-20231231_g1.jpg)][added: Graph.jpg](https://www.sec.gov/Archives/edgar/data/33213/000003321325000011/eqt-20241231_g1.jpg)]

[removed: (a)The 2022] [added: (b)The 2024] Self-Constructed Peer Group includes the following [removed: fourteen] [added: eleven] companies: Antero Resources Corp., APA Corp. (US), [removed: Chesapeake Energy Corp.,] CNX Resources Corp., Comstock [removed: Resources,] [added: Resources] Inc., Coterra Energy Inc., Devon Energy Corp., Diamondback [removed: Energy,] [added: Energy] Inc., [removed: Marathon Oil Corp.,] Matador Resources Co., Murphy Oil Corp., Ovintiv [removed: Inc.,] [added: Inc. and] Range Resources Corp. [removed: and Southwestern Energy Co.] The [removed: 2022] [added: 2024] Self-Constructed Peer Group is comprised of the companies included in our [removed: 2022] [added: 2024] performance peer group (with the exception of (i) [removed: Continental Resources, Inc.,] [added: Chesapeake Energy Corp,] which was excluded for purposes of the stock performance graph because [removed: its stock ceased to be publicly traded beginning] [added: it merged with Southwestern Energy Co.] in [removed: November 2022,] [added: October 2024,] and (ii) [removed: PDC Energy Inc.,] [added: Marathon Oil Corp.,] which was excluded for purposes of the stock performance graph because it was acquired by [removed: Chevron Corp.] [added: ConocoPhillips] in [removed: August 2023),] [added: November 2024),] 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: 2024] Incentive Performance Share Unit Program.

[removed: (b)The] [added: (a)The] 2023 Self-Constructed Peer Group includes the following [removed: sixteen] [added: twelve] companies: Antero Resources Corp., APA Corp. (US), [removed: Chesapeake Energy Corp.,] CNX Resources Corp., Comstock Resources Inc., Coterra Energy Inc., Devon Energy Corp., Diamondback Energy, Inc., Hess Corp., [removed: Marathon Oil Corp.,] Matador Resources Co., Murphy Oil Corp., Ovintiv [removed: Inc., Pioneer Natural Resources Co.,] [added: Inc. and] Range Resources Corp. [removed: and Southwestern Energy Co.] The 2023 Self-Constructed Peer Group is comprised of the companies included in our 2023 performance peer group (with the exception of [added: (i)] PDC Energy Inc., which was excluded for purposes of the stock performance graph because it was acquired by Chevron Corp. in August [removed: 2023),] [added: 2023, (ii) Pioneer Natural Resources Co., which was excluded for purposes of the stock performance graph because it was acquired by ExxonMobil in May 2024, (iii) Chesapeake Energy Corp. and Southwestern Energy Co., which were excluded for purposes of the stock performance graph because they completed a merger with each other in October 2024 and formed a new company which does not have five years of stock performance history, and (iv) Marathon Oil Corp., which was excluded for purposes of the stock performance graph because it was acquired by ConocoPhillips in November 2024),] 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 2023 Incentive Performance Share Unit Program.

Further, on December 18, 2024, we announced that our Board of Directors approved an additional two-year extension of the Share Repurchase Program.

| | | | 12/19 | | | | | | 12/20 | | | | | | 12/21 | | | | | | 12/22 | | | | | | 12/23 | | | | | | 12/24 | | |

| EQT Corporation | | | $ | 100.00 | | | | | $ | 117.25 | | | | | $ | 201.20 | | | | | $ | 317.08 | | | | | $ | 368.48 | | | | | $ | 447.25 | |

| S&P 500 Index | | | 100.00 | | | | | | 118.40 | | | | | | 152.39 | | | | | | 124.79 | | | | | | 157.59 | | | | | | 197.02 | | |

| S&P MidCap 400 Index | | | 100.00 | | | | | | 113.66 | | | | | | 141.80 | | | | | | 123.28 | | | | | | 143.54 | | | | | | 163.54 | | |

| 2023 Self-Constructed Peer Group (a) | | | 100.00 | | | | | | 71.23 | | | | | | 139.11 | | | | | | 220.34 | | | | | | 212.19 | | | | | | 209.41 | | |

| 2024 Self-Constructed Peer Group (b) | | | 100.00 | | | | | | 67.93 | | | | | | 147.63 | | | | | | 222.46 | | | | | | 209.88 | | | | | | 210.77 | | |

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

| | | | 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 | | |

| [Reports of Independent Registered Public Accounting Firm (PCAOB [removed: ID:](#ie0b378c37216402fa1fab6dafbf447c8_64) 42[)](#ie0b378c37216402fa1fab6dafbf447c8_64)] [added: ID:](#iebd86f14a05b4d17bef97d4752e32e1d_67) 42[)](#iebd86f14a05b4d17bef97d4752e32e1d_67)] | | | | | | [removed: [65](#ie0b378c37216402fa1fab6dafbf447c8_64)] [added: [84](#iebd86f14a05b4d17bef97d4752e32e1d_67)] | | |

| [Statements of Consolidated [removed: Operations](#ie0b378c37216402fa1fab6dafbf447c8_67)] [added: Operations](#iebd86f14a05b4d17bef97d4752e32e1d_70)] | | | | | | [removed: [69](#ie0b378c37216402fa1fab6dafbf447c8_67)] [added: [90](#iebd86f14a05b4d17bef97d4752e32e1d_70)] | | |

[removed: | [Statements of Consolidated Comprehensive Income (Loss)](#ie0b378c37216402fa1fab6dafbf447c8_73) | | | | | | [70](#ie0b378c37216402fa1fab6dafbf447c8_73) | | |][added: STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME]

| [Consolidated Balance [removed: Sheets](#ie0b378c37216402fa1fab6dafbf447c8_76)] [added: Sheets](#iebd86f14a05b4d17bef97d4752e32e1d_79)] | | | | | | [removed: [71](#ie0b378c37216402fa1fab6dafbf447c8_76)] [added: [92](#iebd86f14a05b4d17bef97d4752e32e1d_79)] | | |

| [Statements of Consolidated Cash [removed: Flows](#ie0b378c37216402fa1fab6dafbf447c8_79)] [added: Flows](#iebd86f14a05b4d17bef97d4752e32e1d_82)] | | | | | | [removed: [72](#ie0b378c37216402fa1fab6dafbf447c8_79)] [added: [93](#iebd86f14a05b4d17bef97d4752e32e1d_82)] | | |

| [Statements of Consolidated [removed: Equity](#ie0b378c37216402fa1fab6dafbf447c8_82)] [added: Equity](#iebd86f14a05b4d17bef97d4752e32e1d_85)] | | | | | | [removed: [73](#ie0b378c37216402fa1fab6dafbf447c8_82)] [added: [94](#iebd86f14a05b4d17bef97d4752e32e1d_85)] | | |

| [Notes to the Consolidated Financial [removed: Statements](#ie0b378c37216402fa1fab6dafbf447c8_85)] [added: Statements](#iebd86f14a05b4d17bef97d4752e32e1d_88)] | | | | | | [removed: [74](#ie0b378c37216402fa1fab6dafbf447c8_85)] [added: [95](#iebd86f14a05b4d17bef97d4752e32e1d_88)] | | |

We have audited the accompanying consolidated balance sheets of EQT Corporation and subsidiaries (the Company) as of December 31, [removed: 2023] [added: 2024] and [removed: 2022,] [added: 2023,] the related consolidated statements of operations, comprehensive income (loss), cash flows and equity for each of the three years in the period ended December 31, [removed: 2023,] [added: 2024,] and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements").

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, [removed: 2023] [added: 2024] and [removed: 2022,] [added: 2023,] and the results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2023,] [added: 2024,] in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, [removed: 2023,] [added: 2024,] based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February [removed: 14, 2024] [added: 19, 2025] expressed an unqualified opinion thereon.

| *Description of the Matter* | | | At December 31, [removed: 2023,] [added: 2024,] the net book value of the Company's proved oil and natural gas properties was [removed: $19,737] [added: $19,497] million, and [removed: depreciation, depletion] [added: depreciation] and [removed: amortization] [added: depletion] (DD&A) expense [added: of the Company's Production segment] was [removed: $1,732] [added: $2,017] million for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A is recorded on a cost center basis using the units-of-production method. Proved developed reserves, as estimated by the [removed: Company's] [added: Company’s] internal engineers, are used to calculate depreciation of wells and related equipment and facilities and amortization of intangible drilling costs. Total proved reserves, also estimated by the Company's engineers, are used to calculate depletion on property acquisitions. Proved natural gas, natural gas liquids (NGLs) and oil reserve estimates are [removed: prepared using standard] [added: based on] geological and engineering [removed: methods generally recognized in the petroleum industry based on] evaluations of [removed: estimated] in-place hydrocarbon [removed: volumes using financial and non-financial inputs.] [added: volumes.] Significant judgment is required by the [removed: Company's] [added: Company’s] engineers in [removed: interpreting the] [added: evaluating geological and engineering] data when estimating proved natural gas, NGLs and oil reserves. Estimating reserves also requires the selection of inputs, including natural gas, NGLs and oil price [removed: assumptions,] [added: 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: 2023.] [added: 2024.] Auditing the Company's DD&A calculation is especially complex because of the use of the work of the internal engineers and the independent engineers and the evaluation of management's determination of the inputs described above used by [removed: the specialists] [added: those engineers] in estimating proved natural gas, NGLs and oil reserves. | | |

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

[removed: Valuation] [added: | Sales] of [removed: Acquired Natural Gas] [added: natural gas, NGLs] and [removed: Oil Properties][added: oil | | | | | | | | | | | | | | | | | |]

| *How We Addressed the Matter in Our Audit* | | | We obtained an understanding, evaluated the [removed: design,] [added: 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 [removed: 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 [removed: specialist] [added: advisors] used to assist with the determination of the fair value of certain acquired assets. Our testing of the [removed: Company’s] [added: Company's] estimate of fair value of the [removed: acquired natural gas] [added: PP&E] and [removed: oil properties] [added: investment in the MVP Joint Venture] included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. The audit [removed: effort] [added: procedures] involved the use of our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as testing the significant market-related assumptions described above used to develop the fair value estimate. We [removed: evaluated] [added: assessed] the reasonableness of management's assumptions by comparing the key market-related [removed: assumptions (including future natural gas prices and WACC rates) used in] [added: assumptions, such as] the [removed: cash flow model to external market and third-party data and anticipated production volumes] [added: market-based discount rate used] to [removed: the reserve estimates audited by] [added: develop] the [removed: independent engineers.] [added: fair value estimates.] | | |

We have audited EQT Corporation and subsidiaries' internal control over financial reporting as of December 31, [removed: 2023,] [added: 2024,] based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria).

In our opinion, EQT Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, [removed: 2023,] [added: 2024,] 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: 2023] [added: 2024] and [removed: 2022,] [added: 2023,] the related consolidated statements of operations, comprehensive [removed: income (loss),] [added: income,] cash flows and equity for each of the three years in the period ended December 31, [removed: 2023] [added: 2024] and the related notes and the financial statement schedule listed in the Index at Item 15(a), and our report dated February [removed: 14, 2024] [added: 19, 2025] expressed an unqualified opinion thereon.

| | | | [removed: 2023] [added: 2024] | | | | | | [added: 2023 (a) | | | | | |] 2022 | | | | | | [removed: 2021] [added: 2021 (a)] | | | [added: | | | 2020 (b) | | |]

| Sales of natural gas, natural gas liquids and oil | | | $ | [removed: 5,044,768] [added: 4,934,366] | | | | | $ | [removed: 12,114,168] [added: 5,044,768] | | | | | $ | [removed: 6,804,020] [added: 12,114,168] | |

| Gain (loss) on derivatives | | | [removed: 1,838,941] [added: 51,117] | | | | | | [removed: (4,642,932)] [added: 1,838,941] | | | | | | [removed: (3,775,042)] [added: (4,642,932)] | | |

| [removed: Net] [added: Pipeline, net] marketing services and other | | | [removed: 25,214] [added: 287,826] | | | | | | [removed: 26,453] [added: 25,214] | | | | | | [removed: 35,685] [added: 26,453] | | |

| Total operating revenues | | | [removed: 6,908,923] [added: 5,273,309] | | | | | | [removed: 7,497,689] [added: 6,908,923] | | | | | | [removed: 3,064,663] [added: 7,497,689] | | |

| Transportation and processing | | | [removed: 2,157,260] [added: 1,915,616] | | | | | | [removed: 2,116,976] [added: 2,157,260] | | | | | | [removed: 1,942,165] [added: 2,116,976] | | |

| Production | | | [removed: 254,700] [added: 377,007] | | | | | | [removed: 300,985] [added: 254,700] | | | | | | [removed: 225,279] [added: 300,985] | | |

| Exploration | | | [removed: 3,330] [added: 2,735] | | | | | | [removed: 3,438] [added: 3,330] | | | | | | [removed: 24,403] [added: 3,438] | | |

| Selling, general and administrative | | | [removed: 236,171] [added: 336,724] | | | | | | [removed: 252,645] [added: 236,171] | | | | | | [removed: 196,315] [added: 252,645] | | |

| Depreciation and depletion | | | [removed: 1,732,142] [added: 2,016,670] | | | | | | [removed: 1,665,962] [added: 1,732,142] | | | | | | [removed: 1,676,702] [added: 1,665,962] | | |

| [removed: Loss (gain)] [added: (Gain) loss] on sale/exchange of long-lived assets | | | [removed: 17,445] [added: (764,044)] | | | | | | [removed: (8,446)] [added: 17,445] | | | | | | [removed: (21,124)] [added: (8,446)] | | |

| Impairment of contract asset | | | — | | | | | | [removed: 214,195] [added: —] | | | | | | [removed: —] [added: 214,195] | | |

| Impairment and expiration of leases | | | [removed: 109,421] [added: 97,368] | | | | | | [removed: 176,606] [added: 109,421] | | | | | | [removed: 311,835] [added: 176,606] | | |

| Other operating expenses | | | [removed: 84,043] [added: 349,864] | | | | | | [removed: 57,331] [added: 84,043] | | | | | | [removed: 70,063] [added: 57,331] | | |

| Total operating expenses | | | [removed: 4,594,512] [added: 4,588,013] | | | | | | [removed: 4,779,692] [added: 4,594,512] | | | | | | [removed: 4,425,638] [added: 4,779,692] | | |

| Operating income [removed: (loss)] | | | [removed: 2,314,411] [added: 685,296] | | | | | | [removed: 2,717,997] [added: 2,314,411] | | | | | | [removed: (1,360,975)] [added: 2,717,997] | | |

| (Income) loss from investments | | | [removed: (7,596)] [added: (76,039)] | | | | | | [removed: 4,931] [added: (7,596)] | | | | | | [removed: (71,841)] [added: 4,931] | | |

| [removed: Dividend and other] [added: Other] income | | | [removed: (1,231)] [added: (25,983)] | | | | | | [removed: (11,280)] [added: (1,231)] | | | | | | [removed: (19,105)] [added: (11,280)] | | |

| Loss on debt extinguishment | | | [removed: 80] [added: 68,299] | | | | | | [removed: 140,029] [added: 80] | | | | | | [removed: 9,756] [added: 140,029] | | |

| Interest expense, net | | | [removed: 219,660] [added: 454,825] | | | | | | [removed: 249,655] [added: 219,660] | | | | | | [removed: 289,753] [added: 249,655] | | |

| Income [removed: (loss)] before income taxes | | | [removed: 2,103,498] [added: 264,194] | | | | | | [removed: 2,334,662] [added: 2,103,498] | | | | | | [removed: (1,569,538)] [added: 2,334,662] | | |

| Income tax expense [removed: (benefit)] | | | [removed: 368,954] [added: 22,079] | | | | | | [removed: 553,720] [added: 368,954] | | | | | | [removed: (428,037)] [added: 553,720] | | |

| Net income [removed: (loss)] | | | [removed: 1,734,544] [added: 242,115] | | | | | | [removed: 1,780,942] [added: 1,734,544] | | | | | | [removed: (1,141,501)] [added: 1,780,942] | | |

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

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

Accounting for the new Midstream Joint Venture

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

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

February 19, 2025

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

Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Equitrans Midstream.

February 19, 2025

| Production | | | 377,007 | | | | | | 239,001 | | | | | | 298,388 | | |

| Operating and maintenance | | | 110,393 | | | | | | 15,699 | | | | | | 2,597 | | |

| Depreciation, depletion and amortization | | | 2,162,350 | | | | | | 1,732,142 | | | | | | 1,665,962 | | |

| | | | 2024 | | | | | | 2023 | | |

| Investments in unconsolidated entities | | | 3,617,397 | | | | | | 92,666 | | |

| Net intangible assets | | | 215,257 | | | | | | 22,595 | | |

| Goodwill | | | 2,079,481 | | | | | | — | | |

| Other assets | | | 455,623 | | | | | | 206,692 | | |

| Total assets | | | $ | 39,830,255 | | | | | $ | 25,285,098 | |

| Other current liabilities | | | 349,417 | | | | | | 205,003 | | |

| Revolving credit facility borrowings | | | 150,000 | | | | | | — | | |

| Net income | | | $ | 242,115 | | | | | $ | 1,734,544 | | | | | $ | 1,780,942 | |

| Depreciation, depletion and amortization | | | 2,162,350 | | | | | | 1,732,142 | | | | | | 1,665,962 | | |

| (Gain) loss on sale/exchange of long-lived assets | | | (764,044) | | | | | | 17,445 | | | | | | (8,446) | | |

| Impairments | | | 97,368 | | | | | | 109,421 | | | | | | 390,801 | | |

| (Income) loss from investments | | | (76,039) | | | | | | (7,596) | | | | | | 4,931 | | |

| Loss on debt extinguishment | | | 68,299 | | | | | | 80 | | | | | | 140,029 | | |

| Other | | | 15,069 | | | | | | 16,943 | | | | | | 32,645 | | |