EQT 10-K & 10-Q changes, risk factors and insider trading

In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors make an investment in us speculative or risky and should be considered in evaluating our business and future prospects. Note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occur, our business, financial condition or results of operations could suffer and the trading price of ourEQT common stock or other securities could decline.

Risks Associated with Natural Gas Production,Upstream, Midstream and Processing Operations

Additionally, our investment in midstream infrastructure development and maintenance programs is intended, among other items, to connect our wells to other existing gathering and transmission pipelines and can involve significant risks, including those relating to timing, cost overruns and operational efficiency.inefficiency. Significant portions of our natural gas production are dependent on a small number of key compression and processing stations. An operational issue at any of those stations would materially impact our production, cash flows and results of operation.

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 andor 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.

•the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof, including as a result of inflation and/or tariffstariffs, particularly on steel and aluminum);

•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,injury, significant damage to property or environmental contamination. Most notably, certain of these risks have been realized in the construction of theMVP MVP,Mainline, 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 theMVP Mainline, MVP Southgate and MVP Southgate (defined in Note 11 to the Consolidated Financial Statements).Boost.

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 cancould prevent or delay the construction of such infrastructure and realization of associated revenues.

Growing geopolitical instability and armed conflicts (including betweenin Venezuela, Russia and UkraineUkraine, and in the Middle East) has resulted in energy infrastructure becoming a more prominent target of attack by terrorists and conflicting countries. Natural gas, NGLs and oil related facilities, including those operated by us or our service providers, could be direct targets of physical or cyber-attacks, and, if infrastructure integral to our operations is destroyed or damaged, we may experience a significant disruption in our operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash flows. Costs for insurance and other security may increase as a result of increased threats, and certain insurance coverage may become more difficult to obtain, if available at all.

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

SomeMany 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, fires, floods, droughts, and other extreme climatic events. If any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our operations. Potential adverse effects could include disruption of our production activities; delays in getting our 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 and midstream services or cause us to incur significant costs in preparing for, or responding to, the effects of climatic or weather events themselves. Further, energy demand could increase or decrease as a result of extreme weather conditions. A decrease in energy use due to weather or climatic changes may affect our financial condition through decreased revenues. Any one of these factors has the potential to have a material adverse effect on our business, financial condition, results of operations, and cash flow. Our ability to mitigate the physical impacts of adverse weather conditions depends in part upon our disaster preparedness and response along with our business continuity planning.

Mineral rights are typically owned by individuals who may enter into property leases with us to allow for the development of natural gas. Such leases expire after an initial term, typically five years, unless certain actions are taken to preserve the lease. If we cannot preserve a lease, the lease terminates. ApproximatelyAs 6%of December 31, 2025, approximately 5% of our net undeveloped acres are subject to leases that could expire over the next three years. Lack of access to capital, changes in government regulations, changes in future development plans or commodity prices, reduced drilling activity, or the reduction in the fair value of undeveloped properties in the areas in which we operate could impact our ability to preserve, trade or sell our leases prior to their expiration, resulting in the termination or impairment of leases for properties that we have not developed.

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

Because the rate of production from natural gas and oil wells, and associated NGLs, generally declines as reserves are depleted, our future success depends upon our ability to develop additional reserves that are economically recoverable and to optimize existing well production, and our failure to do so may reduce our earnings. Additionally, a failure to effectively and efficiently operate existing wells may cause our production volume to fall short of our projections. Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency,inefficiency, and these risks can be affected by the availability of capital, leases, rigs, equipment, a qualified work force, and adequate capacity for the treatment and recycling or disposal of wastewater generated in our operations, as well as weather conditions, natural gas, NGLs and oil price volatility, regulatory approvals, title and property access problems, geology, equipment failure or accidents and other factors. Drilling for natural gas and oil can be unprofitable, not only due to dry wells, but also as a result of productive wells that perform below expectations or that do not produce sufficient revenues to return a profit. Low natural gas, NGLs and oil prices may further limit the types of reserves that we can develop and produce economically.

Our primary business involves the exploration, production, gathering, transmission and sale of hydrocarbons, and in particular, natural gas. Consequently, our revenue, profitability, future rate of growth, liquidity and financial position depend upon the market prices for natural gas and, to a lesser extent, NGLs and oil. Because our production and reserves predominantly consist of natural gas (approximately 93% of our equivalent proved developed reserves as of December 31, 2025), changes in natural gas prices have a significantly greater impact on our financial results than oil prices.

The prices for natural gas, NGLs and oil have historically been volatile and have been particularly volatile in recent years. The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.40$9.86 per MMBtu to a low of $1.21$2.65 per MMBtu between the period from January 1, 20242025 through December 31, 2024,2025, and the daily spot prices for NYMEX West Texas IntermediateWTI oil ranged from a high of $87.69$80.73 per barrel to a low of $66.73$55.44 per barrel during the same period. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. We expect commodity price volatility to continue or increase in the future due to rising macroeconomic uncertainty and geopolitical tensions.

•risks associated with drilling, completion and productionupstream operations; and

We use financial models to attempt to project future prices for the hydrocarbons we produce and sell, and we make decisions regarding our production, operations and hedging strategy in part based on such modelling.modeling. However, due to the volatility of commodity prices and the multitude of external factors that impact commodity prices, many of which are unknown and unforeseeable, we are unable to predict with certainty future potential movements in the market prices for natural gas, NGLs and oil. The success of our plans and strategies could be negatively affected if our projections of future hydrocarbon prices are significantly different from the ultimate actual price.prices.

Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash flows, financial projections, and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices. Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings. Other producers could be similarly impacted by declines in natural gas prices, potentially resulting in decreased demand for our gathering and transmission services, thereby reducing our cash flows from such operations. Reductions in cash flows from lower commodity prices may require us to incur additional debt or reduce our capital spending, which could reduce our production and our reserves, negatively affecting our future rate of growth. Reduced cash flows could also result in us having to make downward adjustments to our financial projections, such as free cash flow, and could cause us to revise our shareholder returns initiatives, including the amount of dividends paid on ourEQT common stock, which could negatively impact the price of ourEQT common stock and our ability to access the capital markets. Lower prices for natural gas, NGLs and oil may also adversely affect our credit ratings and result in a reduction in our borrowing capacity and access to other capital. See "Critical Accounting Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties.

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

It is possible that costs to perform services under our midstream contracts with "negotiated rates" could exceed the negotiated rates we have agreed to with our customers. If this occurs, it could decrease the cash flow realized by our midstream systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, and cash flows. Under FERC policy, a regulated service provider and a customer may mutually agree to a "negotiated rate," and that contract must be filed with and accepted by the FERC. As of December 31, 2024,2025, approximately 99%95% of theour Transmission segment's contracted firm transmission capacity on our systems was subscribed under such "negotiated rate" contracts.agreements. Unless the parties to these "negotiated rate" contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could be caused by inflation, GHG emission cost (such as carbon taxes, fees, or assessments) or other factors relating to the specific facilities being used to perform the services.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues (including continuedin hostilitiesand betweenrelating to Venezuela, Russia and UkraineUkraine, as well as other conflicts, including inand the Middle East), 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 adjustments in response thereto, and the availability and cost of credit, have contributed and may continue to contribute to increased economic uncertainty and diminished expectations for the global economy. Global economic conditions, geopolitical issues and inflation have constrained global and domestic supply chains, which has impacted and could in the future continue to impact our ability to develop our reserves in accordance with our drilling and completions schedule and could impact the development schedule of our midstream customers, thereby resulting in decreased demand for, and revenue from, our midstream services. Additionally, global economic conditions have a significant impact on commodity prices and any stagnation or deterioration in global economic conditions could result in decreased demand and, thus, lower prices for natural gas, NGLs or oil. Such uncertainty could also result in higher natural gas, NGLs and oil prices, which could potentially result in increased inflation worldwide and could negatively impact demand for natural gas, NGLs and oil.

Governmental and regulatory bodies, investors, consumers, industry participants and other stakeholders have been increasingly focused on combating the effects of climate change. This focus, together with changes in consumer, industrial and commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, and the use of products manufactured with, or powered by, fossil fuels, has led to, and in the long-term is anticipated to continue to result in, (i) the enactment of climate change-related regulations, policies and initiatives, 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-intensitycarbon intensity of various fossil fuels, including the natural gas and NGLs that we produce, transport and sell. If we are not able to demonstrate that our products and services align with a transition to a low-carbon economy, the demand and prices for our products and services could be negatively impacted depending on the pace of such transition and potential future demands for low-carbon products. Such developments may also adversely impact, among other things, the availability of third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of, or our access to, raw materials such as energy, iron, sand and water and therefore result in increased costs to our business.

Further, there have been efforts to influence the investment community, including investment advisors, insurance companies, and certain sovereign wealth, pension and endowment funds and other groups, byto promotingdivest divestmentthemselves of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coveragescoverage to companies engaged in the extraction of fossil fuel 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.securities and make it more difficult or expensive to secure funding for our activities. Limitation of investments in and financings for energy companies could also result in the restriction, delay or cancellation of infrastructure projects and energy production activities.

In 2024, we published, and in 2025 we updated, our Debt Retirement Plan. We intend to fund our Debt Retirement Plan through asset monetizations, such as the NEPA Non-Operated Asset Divestitures and the Midstream Joint Venture Transaction,monetizations and free cash flow; however, there can be no assurance that we will be able to generate sufficient monetization proceeds and free cash flow to execute our Debt Retirement Plan on our anticipated timeframe, if at all. Our ability to de-lever and the pace thereof will depend on our future financial and operating performance, which will be affected by the prevailing economic conditions and financial, business, regulatory and other factors, as well as the MVP Joint Venture's (defined in Note 11 to the Consolidated Financial Statements) ability to execute on project-level financing, some of which are beyond our control. If we are not able to successfully execute our Debt Retirement Plan or otherwise reduce our debt to a level we believe appropriate, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise our shareholder returns strategy or other strategic plans.

In addition, our level of indebtedness may be viewed negatively by credit rating agencies and our credit ratings may be lowered. Changes in our credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on our revolving credit facilities and our senior notes with adjustable rates, the rates available on new debt, our pool of investors and funding sources, and the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. As of February 14,11, 2025,2026, EQT'sour senior notes were rated "Baa3" with a "NegativeStable" outlook by Moody's Investors Services (Moody's), "BBB–" with a "Stable" outlook by Standard & Poor's Ratings Service (S&P) and "BBB–" with a "Stable" outlook by Fitch Ratings Service (Fitch). As of February 14, 2025, EQM Midstream Partners, LP's (our wholly-owned subsidiary, EQM) senior notes were rated "Ba2" with a "Stable" outlook by Moody's, "BBB–" with a "Stable" outlook by S&P and "BB+" with a "Stable" outlook by Fitch. Although we are not aware of any current plans of Moody's, S&P or Fitch to downgrade its rating of EQT’s or EQM’sour senior notes, we cannot be assured that one or more of these rating agencies will not downgrade or withdraw entirely its rating of EQT’s or EQM'sour senior notes. Low prices for natural gas, NGLs and oil, an increase in the level of our indebtedness or other factors may result in Moody's, S&P or Fitch downgrading its rating of our senior notes. Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our lines of credit, the interest rate on our senior notes with adjustable rates, the rates available on new debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts.

Our debt agreements require us to comply with certain covenants. 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." If the price that we receive for our natural gas, NGLs and oil production deteriorates from current levels and continues for an extended period, or if demand for our midstream services decreases for a prolonged period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and in turn our shareholders could experience a partial or total loss of their investment. EQT's revolving credit facility, Eureka'sEureka Midstream, LLC's (Eureka) revolving credit facility,facility and certain of EQT's and EQM'sour senior notes each contain a cross defaultcross-default provision that applies to a default related to any other indebtedness the applicable borrower may have with an aggregate principal amount in excess of a specified threshold as set forth in the applicable debt documentsdocuments.

•our ability to obtain and/or maintain necessary rights-of-way, real-estatereal estate rights or permits or other government approvals, including approvals by regulatory agencies;

Our business and operating results can be adversely affected by increases in interest rates or other increases in the cost of capital resulting from a reduction in EQT's or EQM'sour credit ratings or otherwise. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for operating and capital expenditures and place us at a competitive disadvantage.

Disruptions or volatility in the financial markets may lead to a contraction in credit availability impacting our ability to finance our operations.availability. A significant reduction in the availability of credit could materially and adversely affect our ability to implement our business strategy and achieve favorable operating results. In addition, we are exposed to credit risk related to EQT's revolving credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under EQT's existing line of credit if we experience liquidity problems.

Derivative transactions also expose us to a risk of financial loss if a counterparty fails to perform under a derivative contract or enters bankruptcy or encounters some other similar proceeding or liquidity constraint. In this case, we may not be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity pricesprices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Our future prospects are dependent upon our ability to identify optimal strategies for our business. Our operational strategy focuses on developing several multi-well pads in tandem through a process known as combo-development. In addition, we are pursuing opportunities geared at enhancing our core operational strategy, including LNG exports, midstream growth projects, the development of data centers and other energy-adjacent or infrastructure-oriented initiatives, as well as sustainability and energy transition initiatives. We have allocated a substantial portion of our financial, human capital and other resources to pursuing thisour strategy,strategy and these initiatives, including investing in new technologies and equipment, restructuring our workforce, building and acquiring new infrastructure, entering into new commercial arrangements, and pursuing variousprojects ESGthat may involve new markets, counterparties, regulatory regimes and energyexecution transition initiatives geared towards enhancing our strategy.risks. We may not realize some or any of the anticipated strategic, financial, operational, environmental and other anticipated benefits from our operational strategy or strategic initiatives and the corresponding investments we have made in pursuing such opportunities. Our strategic initiatives may expose us to risks that differ from or exceed those associated with our strategy.traditional Additionally,operations. weSuch cannotprojects may be certaindelayed, thatcost wemore willthan be able to successfully execute combo-development projects at the pace and scale that we project, which may delay or reduce our production and our reserves, negatively affecting our associated revenues. If weexpected, fail to identifyreach andfinal successfullyinvestment execute optimal business strategies, including the appropriate operational strategy and corresponding initiatives, ordecisions, fail to optimizeachieve ourcommercial capitaloperations, investmentsor be terminated altogether, and theeven useif of our other resources in furtherance of optimal business strategies, our financial position and growthcompleted, may benot adverselygenerate affected.the Moreover,expected economicreturns or othercash circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.flows.

The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber or other security or physical threats, and the continuing armed conflict between Russia and Ukraine and associated economic sanctions on RussiaRussia, as well as evolving geopolitical unrest in other parts of the world, may have increased the likelihood of such threats. We can provide no assurance that we will not suffer such attacks in the future. Deliberate attacks on, or unintentional events affecting, our digital work environment or other technologies and infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, NGLs and oil, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. The cost to remedy an unintended dissemination of sensitive information or data may be significant. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

Our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. However, opposition towards oil and natural gas drilling and pipeline construction generally has been growing globally and is particularly pronounced in the U.S.globally. Failure to successfully manage expectations across these varied stakeholder interests could erode our stakeholder trust and thereby affect our reputation. Negative public perception regarding us and/or our industry may adversely affect our ability to successfully carry out our operations and business strategy. Such negative perception could, for example, adversely affect our access to and cost of capital and lead to increased litigation and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new local, state and federal laws, regulations, guidelines and enforcement interpretations in safety, environmental, royalty and surface use areas. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, challenged or burdened by requirements that restrict our ability to profitably conduct our business. In addition, anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations, such as drilling and pipeline construction. If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations.

Moreover, while we publish voluntary disclosures regarding ESG and sustainability matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG and sustainability matters. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG and sustainability matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG or sustainability ratings could lead to increased negative investor sentiment towards us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and cost of capital. In addition, failure or a perception (whether or not valid) of failure to implement our ESGsustainability strategy or achieve sustainability goals and targets we have set, could damage our reputation, causing our investors or consumers to lose confidence in our company, and negatively impact our operations. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESGsustainability strategy, including any climate or other ESGsustainability goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. For example, growing interest on the part of investors and regulators in ESG factors and increased demand for, and scrutiny of, ESG-relatedESG and sustainability-related disclosure by stakeholders has also increased the risk that companies could be perceived as, or accused of, making inaccurate or misleading statements regarding their ESG-relatedESG and sustainability-related claims, goals, targets, efforts or initiatives, often referred to as "greenwashing." Such perception or allegation could damage our reputation and result in litigation or regulatory actions.

AtIn addition, regulations requiring the disclosure of GHG emissions and other climate-related information or information substantiating climate-related claims are being adopted or proposed at the state level,level (e.g., although subject to ongoing legal challenges and certain requirements are currently enjoined, California has enacted legislation in October 2023 that will ultimately require certain companies that do business in California to publicly disclose theircertain GHGclimate-related emissions,information, with third-party assurance of such data, and issue public reports summarizing their climate-related financial riskrisks and related mitigation measures,measures). asIf wellwe asbecome legislation that requires companies operating in Californiasubject to disclosesuch informationregulations, that supports certain climate-related claims. Compliance with these and any other federal, state or local disclosure requirementswe may cause us to incur additional (and potentially accelerate) compliance and reporting costs, certain of which could be material, including related to monitoring, collecting, analyzing and reporting new metrics and implementing systems and procuring additional necessary attestation. Such costs may adversely affect our future business, financial condition, results of operations,operations and liquidity.

Laws and regulations directed at restricting emissions of methane and other GHGs could result in increased operating costs and reduced demand for the natural gas, NGLs and oil that we produce and our midstream services.systems service.

It is not possible at this time to predict how legislation or regulations that may be adopted to reduce or restrict methane and other GHG emissions would impact our business. However, any legislation or regulatory programs at the international, federal, state or city levels designed to reduce methane or other GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas, NGLs and oil we produce and our midstream services.systems service. Existing laws and regulations and any future laws and regulations of this nature, including those imposing reporting obligations, or imposing a tax or fee or otherwise limiting emissions of methane or other GHGs from our equipment and operations could require us to incur costs to comply with such regulations, including costs to monitor and report on GHG emissions, install new equipment to reduce emissions of GHGs associated with our operations, acquire emissions allowances or comply with new regulatory requirements. Substantial limitations or taxes or fees on methane or other GHG emissions, as well as other regulatory incentives or requirements to conserve energy, use alternative sources or reduce GHG emissions in product supply chains, could also adversely affect demand for the natural gas, NGLs and oil we produce and our midstream services,systems service, stimulate demand for alternative forms of energy that do not rely on combustion of fossil fuels, and lower the value of our reserves.

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

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

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

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

Our exploration and productionupstream operations are subject to various types of federal, state and local laws and regulations, including regulations related to the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of water and other fluids and materials, including solid and hazardous wastes, incidental to natural gas and oil operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances.

To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Maintaining compliance with the laws, regulations and other legal requirements applicable to our business and any delays in obtaining related authorizations may affect the costs and timing of developing our natural gas, NGLs and oil resources. These requirements could also subject us to claims for personal injuries,injury, property damage and other damages. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could materially adversely affect our results of operations, cash flows and financial position. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages as well as corrective action costs.

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

Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.6 million (as of February 11, 2026 and adjusted periodically for inflation) per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes.

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

We are subject to taxation by various governmental authorities at the federal, state and local levels in the jurisdictions in which we operate. New legislation could be enacted by these governmental authorities, which could increase our tax burden and increase the cost to produce, gather and transport natural gas. Members of Congress periodically introduce legislation to revise U.S. federal income tax lawslaws, which could have a material impact on us. In prior years, legislation has been proposed that would, if enacted, make significant changes to U.S. tax laws, including the reduction or elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These proposed changes have included,included (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions or credits that are currently available with respect to our operations, which could adversely impact our earnings, cash flows and financial position. Additionally, state and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil, or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position. Lastly, our tax returns are subject to audit by taxing authorities, and there is no assurance that tax authorities or courts will agree with the positions that we have reflected in our tax filings. Disagreements with tax authorities or courts could result in additional tax liabilities recorded by us or interest and penalties imposed on us, which could adversely impact our earnings, cash flow and financial position.

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows. As disclosed in Item 1., "Business-Regulation,Business – Regulation – Regulation of Our Operations," the Dodd-Frank Act, the rules adopted thereunder and various other foreign regulations could increase the cost of our derivative contracts, alter the terms of our derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or such foreign regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material adverse effect on our business, financial position and results of operations. We have experienced increased, and anticipate additional, compliance costs and changes to current market practices as participants continue to adapt to a changing financial regulatory environment.

We use hydraulic fracturing in the completion of our wells. Hydraulic fracturing typically is regulated by state natural gas and oil commissions, but the EPA prohibits the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Certain governmental reviews have been conducted or are underway that focus on the environmental aspects of hydraulic fracturing practices. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from constructing wells. See Item 1., "Business-Regulation-Environmental,Business – Regulation – Environmental, Health and Safety Regulation" for more information.

ResultsBeginning May 31, 2024, our results of operations forreflect 2024 include the results of(i) our operationdivestiture of assets received as consideration for (the First NEPA Non-Operated Asset Divestiture,Divestiture) whichof closedan onundivided May 31, 2024. Such assets received included the remaining 16.25% equity40% interest in our non-operated natural gas assets in Northeast Pennsylvania and (ii) our 100% ownership of the NEPA Gathering System (defined in Note 611 to the Consolidated Financial Statements) (which was the sole remaining minority interest following our acquisition of aadditional 33.75%ownership equityinterests interesttherein in connection with the NEPA Gathering System Acquisition (defined in Note 611 to the Consolidated Financial Statements) on April 11, 2024), resulting in our 100% ownership ofand the First NEPA GatheringNon-Operated System.Asset See Note 7 to the Consolidated Financial Statements.Divestiture.

ResultsBeginning July 22, 2024, our results of operations for 2024 and the second half of 2023 include the results ofreflect our operation of the assets acquired in the Tug Hill and XcLEquitrans Midstream AcquisitionMerger (defined in Note 611 to the Consolidated Financial Statements), which closed on August 22, 2023..

Lastly,Commodity prices were volatile in 2025, and we expect commodity prices to continue to be volatile throughin 20252026 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical instability and tensions, including developmentsin pertainingVenezuela, toRussia, Russia'sUkraine invasion of Ukraine, conflicts inand the Middle EastEast, and potential further imposition of domestic and foreign tariffs. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.

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

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

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

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

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

The following sections summarizepresent operating income and certainkey operational measures byfor our three reportable segments.segments of Upstream, Gathering and Transmission. We believe this information isprovides useful information to investors for evaluatingregarding our financial condition, results of operations and trends and uncertainties of our segments.uncertainties. See Note 2 to the Consolidated Financial Statements for financial information by business segment.

CertainItems amounts,that are managed on a consolidated basis, including cash and cash equivalents, debt, income taxes and other amounts related to our headquarterscorporate functionfunction, asand well as amountsitems related to our energy transition initiatives are managed on a consolidated basis and, as such, have not been allocated to our reportable segments. ChangesThese to these amountsitems are discussed under "Other Income Statement Items."

(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast for our change in reportable segments from one reportable segment to three reportable segments as the necessary information iswas not available and the cost to develop such information would be excessive.

ProductionGain on Derivatives. For 2025, we recognized a gain on derivatives.derivatives of approximately $291 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $291 million due to decreases in NYMEX forward prices and increases in the fair market value of our basis and liquids swaps of approximately $45 million, partly offset by premiums paid for derivative settlements of $45 million. For 2024, we recognized a gain on derivatives of approximately $68 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $377$422 million due to decreases in NYMEX forward prices, partly offset by decreases in the fair market value of our basis and liquids swaps of approximately $309 million.million Forand 2023,premiums wepaid recognizedfor aderivative gain on derivativessettlements of approximately $1,839 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $1,830 million due to decreases in NYMEX forward prices as well as increases in the fair market value of our basis swaps of approximately $9$45 million.

Gathering.Gathering Expense. Gathering expense decreased on an absolute and per Mcfe basis for 20242025 compared to 20232024 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the First NEPA Non-Operated Asset Divestiture. In addition, gathering expense decreased due to our divestiture of assets in the NEPA Non-Operated Asset Divestitures.

Transmission.Transmission Expense. Transmission expense increased on an absolute and per Mcfe basis for 20242025 compared to 20232024 due primarily to capacity charges relatedof toapproximately the$193 inmillion service ofon the MVP (Mainline, which commencedentered long-terminto firmservice capacityin obligationsJune on2024, July 1, 2024) of approximately $165 million,and additional contracted capacity on the Columbia Gas and Transco pipelines of an aggregate approximate $47 million and credits received in 2023 from pipeline credits of approximately $14$33 million.million, Wepartly recordoffset ourby equitycapacity earnings from our investmentreleased in connection with the MVPNEPA JointNon-Operated VentureAsset in income from investments in our StatementsDivestitures of Consolidatedapproximately Operations.$57 million.

Processing.Processing Expense. Processing expense increased on an absolute and per Mcfe basis for 20242025 compared to 20232024 due primarily to increased processing expense from the liquids-rich properties acquired in the Tug Hill and XcL Midstream Acquisition of approximately $40 million and increased volumesproduction of gas requiring processing from wells that we turned-in-line insince 2024.

Transportation and processingProcessing Expense to affiliate.Affiliate. Affiliate transportation and processing expense increased on an absolute and per Mcfe basis for 20242025 compared to 20232024 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger,Merger and the Olympus Energy Acquisition, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the First NEPA Non-Operated Asset Divestiture. In addition, affiliate transportation and processing expense increased on a per Mcfe basis for 2024 compared to 2023 due to our Gathering segment's ownership of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023.

Production taxes.Taxes. Production tax expense increaseddecreased on an absolute and per Mcfe basis for 20242025 compared to 20232024 due to increaseddecreased property tax expense of approximately $63$53 million primarily from thelower assetsproperty acquiredtax invalue thebased Tugon Hillprior andyear XcLpricing, Midstreampartly Acquisitionoffset and higher price as well asby increased severance tax expense of approximately $24$35 million from increased sales volume inand Westhigher Virginia.sales prices.

(Gain) losson Sale/Exchange of Long-Lived Assets. During 2025, we recognized a net gain on sale/exchange of long-lived assets.assets of approximately $36 million related to acreage trade transactions. During 2024, we recognized a gain on the First NEPA Non-Operated Asset Divestiture of approximately $299 million and a gain on the Second NEPA Non-Operated Asset Divestiture of approximately $463 million. See Note 712 to the Consolidated Financial Statements. During 2023, we recognized a loss on sale/exchange of long-lived assets of approximately $17 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.

Impairment and expirationExpiration of leases.Leases. During 20242025 and 2023,2024, we recognized impairment and expiration of leases of approximately $50 million and $97 million, respectively, related to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.

Other operatingOperating expenses. We recognized approximately $13 million and $9 million of other operating expenses for 2024 and 2023, respectively.Expenses. Other operating expenses increased for 20242025 compared to 20232024 due primarily to increased rig release expense and increased legal and environmental reserves, including from settlements, partly offset by proceeds received in 2024 from business interruption insurance claim recoveries.recoveries and increased expense from changes in legal and environmental reserves, including settlements. See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses.

This Quarterly Report on Form 10-Q contains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and are usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe" and other words of similar meaning, or the negative thereof. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report on Form 10-Q include the matters discussed in the section "Trends and Uncertainties" in Item 2., "Management's Discussion and Analysis of Financial Condition and Results of Operations," and expectations of our plans, strategies, objectives and growth and anticipated financial and operational performance, including guidance regarding our strategy to develop our reserves; drilling plans and programs, including availability of capital to complete these plans and programs; total resource potential and drilling inventory duration; projected production and sales volume, including natural gas liquids (NGLs) and liquifiedliquefied natural gas (LNG) volumes and sales; the projected volume and timing of LNG offtake and tolling commitments subject to final investment decisions; potential curtailments and the anticipated volume and duration thereof; natural gas prices; changes in basis and the impact of commodity prices on our business; potential future impairments of our assets; projected well costs and capital expenditures; infrastructure projects; the cost, capacity and timing of obtaining regulatory approvals; our ability to successfully implement and execute our operational and organizational initiatives, and achieve the anticipated results of such initiatives; projected gathering and compression rates; potential acquisitions or other strategic transactions, the timing thereof and our ability to achieve the intended operational, financial and strategic benefits from any such transactions or from any recently completed strategic transactionstransactions, including the Company's acquisition of all of the operating subsidiaries of Blackline Midstream, LLC; the amount and timing of any repayments, redemptions or repurchases of EQT common stock, outstanding debt securities or other debt instruments; our ability to retire our debt and the timing of such retirements, if any; the projected amount and timing of dividends; projected cash flows and free cash flow, and the timing thereof; liquidity and financing requirements, including funding sources and availability; our ability to maintain or improve our credit ratings, leverage levels and financial profile; our hedging strategy and projected margin posting obligations; the effects of litigation, government regulation and tax position; and the expected impact of changes to tax laws.

The forward-looking statements included in this Quarterly Report on Form 10-Q involveare subject to risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. We have based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently known by us. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond our control. These risks and uncertainties include, but are not limited to, volatility of commodity prices; the costs and results of drilling and operations; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying production forecasts; the quality of technical data; our ability to appropriately allocate capital and other resources among our strategic opportunities; access to and cost of capital; our hedging and other financial contracts; inherent hazards and risks normally incidental to drilling for, producing, transporting and storing natural gas, natural gas liquids (NGLs) and oil; operational risks and hazards incidental to the gathering, transmission and storage of natural gas as well as unforeseen interruptions; cyber security risks and acts of sabotage; availability and cost of drilling rigs, completion services, equipment, supplies, personnel, oilfield services and sand and water required to execute our exploration and development plans, including as a result of inflationary pressures or tariffs; risks associated with operating primarily in the Appalachian Basin; the ability to obtain environmental and other permits and the timing thereof; construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties related to the development and construction by us or our joint ventures of pipeline and storage facilities and transmission assets and the optimization of such assets; our ability to renew or replace expiring gathering, transmission or storage contracts at favorable rates on a long-term basis or at all; risks relating to our joint venture arrangements; government regulation or action, including regulations pertaining to methane and other greenhouse gas emissions; negative public perception of the fossil fuels industry; increased consumer demand for alternatives to natural gas; environmental and weather risks, including the possible impacts of climate change; and disruptions to our business due to recently completed divestitures, acquisitions and other significant strategic transactions. These and other risks and uncertainties are described under the "Risk Factors" section and elsewhere in EQT's Annual Report on Form 10-K for the year ended December 31, 2025, and may be updated by other documents we subsequently file from time to time with the Securities and Exchange Commission (the SEC).

On March 30, 2026, we completed our acquisitions (the MVP A and MVP C Interest Acquisitions) of an approximately 3.94% interest in each of MVP A and MVP C (each defined in Note 8 to the Condensed Consolidated Financial Statements) from an affiliate of Con Edison Gas Pipeline and Storage, LLC pursuant to a preferential buy-out right under the MVP LLC Agreement (defined in Note 8 to the Condensed Consolidated Financial Statements). Total consideration for our acquisition of equity interests in MVP A (MVP A Interest Acquisition), excluding transaction costs, was $198.3 million, of which $98.4 million was funded by the BXCI Affiliate (defined in Note 9 to the Condensed Consolidated Financial Statements). Total consideration for our acquisition of equity interests in MVP C was $15.6 million. We funded our share of the consideration for the MVP A and MVP C Interest Acquisitions with cash on hand.

Commodity prices were volatile in the first quarterhalf of 2026 and we expect commodity prices to continue to be volatile for the remainder of 2026 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical instability and tensions, including in the Middle East, Venezuela, Russia and Ukraine, and potential further imposition of domestic and foreign tariffs. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.

In response to natural gas price volatility and to optimize in-basin pricing, we implement strategic curtailments from time to time. Strategic curtailments during the second quarter of 2026 were below our previously disclosed guidance and were not significant to our results. Low natural gas prices or volatility in the natural gas market may result in further adjustments to our 2026 planned development schedule and/or adjustments to the development schedule of non-operated wells in which we have a working interest. We cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our 2026 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.

Net income attributable to EQT Corporation for the three months ended MarchJune 31,30, 2026 was approximately $1,487$211 million, $2.36$0.34 per diluted share, compared to approximately $242$784 million, $0.40$1.30 per diluted share, for the same period in 2025. The increasedecrease was driven primarily by higherlower derivative gains and lower average realized natural gas prices and lower derivative losses,prices, partly offset by higherlower income tax expense.expense and lower legal reserves.

(a)Net cash settlements received (paid) on derivatives are included in average realized price but may not be included in operating revenues. For the three months ended MarchJune 31,30, 2026, net cash settlements paidreceived on derivatives consisted of net cash settlements paidreceived on NYMEX natural gas hedge positions of approximately $114$76 million and net cash settlements paid on basis and liquids hedge positions of approximately $190$3 million. For the three months ended MarchJune 31,30, 2025, net cash settlements paid on derivatives consisted of net cash settlements paid on NYMEX natural gas hedge positions of approximately $43$102 million and net cash settlements paidreceived on basis and liquids hedge positions of approximately $49$1 million.

Sales of Natural Gas, NGLs and Oil. Sales of natural gas, NGLs and oil increaseddecreased by approximately $1,195$90 million for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025, reflecting ana increasedecrease of approximately $1,010$288 million from higherlower average sales priceprice, andpartly offset by approximately $185$198 million from increased sales volumes.

Average sales price increaseddecreased for the three months ended MarchJune 31,30, 2026 compared to the same period for 2025 due primarily to a higherlower NYMEX priceprice, andpartly offset by a favorable basis differential,differential partlyand offsethigher by lower NGLsliquids prices. Sales volume increased for the three months ended MarchJune 31,30, 2026 compared to the same period for 2025 due primarily to a 48 billion cubic feet equivalent (Bcfe) increase from the assets acquired in the Olympus Energy Acquisition.Acquisition, increases from wells turned-in-line since the second quarter of 2025 and increases from well performance optimization.

LossGain on Derivatives. For the three months ended MarchJune 31,30, 2026, we recognized a lossgain on derivatives of approximately $238$45 million related primarily to decreasesincreases in the fair market value of our NYMEX swaps and options of approximately $73$37 million due to increasesdecreases in NYMEX forward prices and decreasesincreases in the fair market value of our basis and liquids swaps of approximately $165$8 million. For the three months ended MarchJune 31,30, 2025, we recognized a lossgain on derivatives of approximately $679$720 million related primarily to decreasesincreases in the fair market value of our NYMEX swaps and options of approximately $783$682 million due to increasesdecreases in NYMEX forward prices,prices partly offset byand increases in the fair market value of our basis and liquids swaps of approximately $104$38 million.

Gathering Expense. Gathering expense increased on an absolute and per Mcfe basis for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025 due primarily to higher volumes gathered by third parties from wells turned-in-line sincein the first quarter of 2025.2026.

Production DepletionProcessing Expense. Production depletionProcessing expense increaseddecreased on an absolute and per Mcfe basis for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025 due primarily to higherdecreased salesproduction volumes,of partlygas offsetthat byrequires aprocessing. lowerIn annualaddition, depletion rate. Onon a per Mcfe basis, production depletionprocessing expense decreased due primarily to thehigher lowersales depletion rate.volume.

OtherLease Operating Expenses.Expense. OtherLease operating expensesexpense increased on an absolute and per Mcfe basis for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025 due primarily to increased expensecosts from changesthe assets acquired in legalthe Olympus Energy Acquisition as well as higher water network and environmentalwinter reserves,maintenance including settlements.expenses.

(a)For agreements structured with minimum volume commitments (MVCs), firm capacity includes volumes up to the contractual MVC and volumetric-based servicesvolumes includes volumes in excess of the contractual MVC.

Volumetric-Based Fees. Volumetric-based fee revenue increased for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025 due to increased affiliate revenue, partly offset by decreased third-party revenue. Affiliate revenue increased approximately $25 million due primarily to the gathering assets acquired in the Olympus Energy AcquisitionAcquisition. ofThird-party revenue decreased approximately $23$6 million,million partlydue offsetprimarily byto lower usage under certain gas gathering agreements with our Upstream segment.usage.

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

Volumetric-BasedFirm Reservation Fees. Volumetric-basedFirm reservation fee revenue increased for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025 due primarily to increased overrunaffiliate chargesrevenue fromof approximately $8 million related to an increase in contracted firm reservation capacity and higher average reservation rates under certain agreements with our Upstream segment of approximately $5 million.segment.

Income from Investments. Income from investments decreased for the three months ended June 30, 2026 compared to the same period in 2025 due primarily to lower equity earnings from our investment in Laurel Mountain Midstream, LLC (LMM). Income from investments increased for the threesix months ended MarchJune 31,30, 2026 compared to the same period in 2025 due primarily to higher equity earnings from our investment in the MVP Joint Venture (defined in Note 8 to the Condensed Consolidated Financial Statements) of approximately $32$35 million and an increase in the fair value of our investment in the Investment Fund (defined in Note 8 to the Condensed Consolidated Financial Statements) of approximately $16$15 million.million, partly offset by lower equity earnings from our investment in LMM.