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

The first of month prices for NYMEX Henry Hub natural gas ranged from a high of $3.43$4.42 per MMBtu to a low of $1.58$2.84 per MMBtu in 2024,2025, and the calendar month average prices for NYMEX West Texas Intermediate crude oil ranged from a high of $84.39$75.10 per barrel to a low of $69.37$57.87 per barrel during the same period. Natural gas prices were substantially lowerhigher in 20242025 than they were in 2023,2024, while oil prices weredecreased relatively consistentsubstantially in 20242025 andas 2023.compared to 2024. The markets for these commodities have historically been volatile, and these markets will likely continue to be volatile in the future. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. 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. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, oil and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.

To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, we havemay historically enteredenter into fixed swap hedgingderivative contracts for a significant percentage of our expected production volumes. ForAssuming example,our 2026 production is the same as our production in 20212025, weapproximately hedged 91%, 36% and 29%42% of our naturaltotal gas,production NGLsis andhedged oilthrough production,commodity respectively.derivatives. Additionally,In in 2022addition, we hedgedhave 49%commodity of our natural gas production, and our NGLs and oil production was unhedged. Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. For example, in 2023 and 2024, substantially all of our production was unhedged, and as of December 31, 2024, we had fixed swap and collarderivative contracts in place for a nominal portion of our natural2027 gasproduction. productionOur in 2025current and 2026.potential To the extent that we engage infuture hedging activity in the future, we may beprevent preventedus from realizing the near-term benefits of price increases above the levels of the hedges.hedges for the portion of our production that is hedged. If we choose not to engage in, or otherwise reduce our future use of, hedging arrangements or are unable to engage in hedging arrangements due to lack of acceptable counterparties, we may be more adversely affected by changes in commodity prices than our competitors who engage in hedging arrangements to a greater extent than we do. Conversely, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

As of December 31, 2024,2025, we had 1,1371,279 identified potential horizontal well locations in our proved, probable and possible reserve base and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024.base. As a result of the limitations described above, we may be unable to drill many of our potential well locations. In addition, we will require significant additional capital over a prolonged period to pursue the development of these locations, and we may not be able to obtain or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves, or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified potential well locations, see “Item 1. Business and Properties—Our Properties and Operations—Estimated Proved Reserves—Identification of Potential Well Locations.”

ESGSustainability matters and conservation measures may adversely impact our business.

Stakeholder attention to climate risks, societal expectations on companies related to climate risks, investor, regulatory and societal expectations regarding voluntary and mandatory ESGsustainability disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, negative impacts on our stock price and reduced access to capital markets. Any increased attention to climate risks and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us and, depending on the nature of the claims asserted and other factors, such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Moreover, while we create and publish voluntary disclosures regarding ESGsustainability matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions or hypothetical scenarios 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. Mandatory ESG-relatedsustainability-related disclosure is also emergingevolving as an area where we may be, or may become, subject to required disclosures in certain jurisdictions, depending on our purported nexus to such jurisdictions and any such mandatory disclosures may similarly necessitate the use of hypothetical, projected or estimated data, some of which is not controlled by us and is inherently subject to imprecision. Disclosures reliant upon such expectations and assumptions or hypothetical scenarios 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 ESGsustainability matters. In addition, we havemay establishedannounce avarious netvoluntary zerosustainability goaltargets, byincluding 2025 with respect to our Scope 1 (direct) and Scope 2 (indirect from the purchase of energy)certain GHG emissions,emissions goals, and we could face unexpected material costs as a result of our efforts to meetmaintain this goal and any future revisions to it. We continue to evaluate a range of technology and other measures, such as carbon offsets, that could assist with meeting this goal. Given uncertainties related to the use of emerging technologies, the state of markets for and the availability of verified carbon offsets, we cannot predict whether or not we will be able to timely meet these goals, if at all. A failure or a perception of failure (whether or not valid) to pursue, implement or adequately make progress against such sustainability strategies or achieve such sustainability goals or commitments could result in private litigation and damage to our reputation. In addition, while we may seek to only purchase carbon offsets verified by reputable third parties, we cannot guarantee that any carbon offsets we purchase will achieve the GHG emission reductions represented, and we could face increased costs to purchase additional carbon offsets to cover any gap or loss, particularly if carbon offset markets face capacity constraints as a result of increased demand.demand or heightened scrutiny of their methodologies. Moreover, certain stakeholders may object to the use of offsets generally or with respect to specific transactions we engage in as to any carbon reduction benefits we may claim resulting from such offsets. Furthermore, certain jurisdictions, including California, arehave institutinginstituted new laws that require disclosures related to voluntary carbon offsets and similar constructs. Disclosures under these regimes are novel and it is uncertain whether any disclosures we may make in connection therewith will satisfy the laws and may lead to uncertain consequences, such as private parties criticizing such projects, whether via litigation or otherwise. While we may participate in various voluntary frameworks and certification programs to improve the ESGsustainability profile or transparency of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESGsustainability profile. Also, despite any aspirational goals, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-relatedsustainability-related goals, but we cannot guarantee that we will be able to implement such goals in whole or in part because of potential costs or technical or operational obstacles.

Furthermore, our reputation, as well as our stakeholder relationships, could be adversely impacted as a result of, among other things, any failure to meet our ESG plans or goals or stakeholder perceptions of statements made by us, our employees and executives, agents, or other third parties or public pressure from investors or policy groups to change our policies. Such statements with respect to ESG matters are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. Moreover, any alleged claims of greenwashing against us or others in our industry may lead to negative sentiment towards our company or industry. To the extent that the Company is unable to respond timely and appropriately to any negative publicity, our reputation could be harmed. Damage to our overall reputation could have a negative impact on our financial results and require additional resources for the Company to rebuild its reputation. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings and proxy voting recommendations processes for evaluating companies on their approach to ESGsustainability matters. Such ratingsratings, proxy advisory services, and reports may be used by some investors to inform their investment and voting decisions. UnfavorableWhile ESGsuch ratings do not impact all investors’ investments or voting decisions, unfavorable sustainability ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward 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 costs of capital. Also, certain institutional lenders may decide not to provide funding for oil and natural gas companies or the corresponding infrastructure projects based on climate related concerns, which could affect our access to capital for potential growth projects. Moreover, to the extent ESGsustainability matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations. Such ESGsustainability matters may also impact Antero Midstream and our customers, which may adversely impact our business, financial condition or results of operations.

The oil and gas industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures for the exploration, development, production, and acquisition of oil and gas reserves. Our cash flow used in investing activities for 20242025 included drilling and completion costs of $615$685 million and leasehold expenditures of $91$129 million. Our net capital budget for 20252026 is $725$1.1 millionbillion to $800$1.3 million.billion Our budgetand includes: a$1.0 range of $650 million to $700 millionbillion for drilling and completion and $75 million tocompletions, $100 million for leasehold expenditures.expenditures and up to $200 million for discretionary growth capital that is dependent on commodity prices. Our capital budget excludesreflects acquisitions,the exceptclosing of the HG Acquisition on February 3, 2026 and assumes the closing of the Utica Shale Divestiture during February 2026. We do not budget for leasehold acquisitions. We expect to fund these capital expenditures with cash generated by operations, and dividends from Antero Midstream, which we do not control the timing or amount of, if any; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The actual amount and timing of our future capital expenditures may differ materially from our capital budget as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological, and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to maintain production.

Our ability to make scheduled payments on, or to refinance, our indebtedness, including the Credit Facility, the Term Loan A Facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the Senior Notes.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness, including the Credit Facility, the Term Loan A Facility or the Senior Notes. For example, the proceeds of our asset sale program were used to retire a portion of our indebtedness. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital and credit markets, including the markets for debt securities and credit facilities, and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including the Credit Facility, the Term Loan A Facility and certain of the indentures governing our Senior Notes, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness, could result in more onerous restrictions in our debt securities and facilities and may result in us having to post collateral with, or provide letters of credit to, certain transactional counterparties. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our debt documents place certain restrictions on our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

The Credit Facility containsand the Term Loan A Facility contain a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

The indentures governing certain of our Senior Notes contain similar restrictive covenants as well as restrictive covenants that may limit our ability to sell assets and make investments. In addition, the Credit Facility requiresand the Term Loan A Facility require us to maintain a ratio of total indebtedness to capitalization of 65% or less. These restrictions, together with those in the indentures governing our Senior Notes may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing our Senior NotesNotes, the Credit Facility and the CreditTerm Loan A Facility impose on us.

A breach of any covenant in the Credit Facility or the Term Loan A Facility would result in a default under thatthe relevant agreement after any applicable grace periods. A default, if not waived, could result in our inability to access loans under the Credit Facility or acceleration of the indebtedness outstanding under the Credit Facility or the Term Loan A Facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. In addition, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

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. New legislation regulating hydraulic fracturing may be considered again in future, though we cannot predict when or the scope of any such legislation at this time. 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. For example, the Ohio legislature has adopted a law requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drill baseline water quality sampling of certain water wells near a proposed horizontal well. 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 banned and others seek 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 drilling wells.

Our oil and gas exploration, production, processing and transportation operations are subject to complex and stringent laws and regulations. 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. We may incur substantial costs to maintain compliance with these existing laws and regulations. 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. For instance, there have been several recent developments regarding the National Environmental Policy Act (“NEPA”) regulatory regime. Most recently, following a Trump administration Executive Order, in JanuaryFebruary 2023,2025, the White House’s Council on Environmental Quality (“CEQ”) released an interim final rule rescinding its regulations implementing NEPA. Federal agencies have begun the process of preparing their own new or updated NEPA-implementing rules or guidelines, with the first batch of updates released in July 2025. In May 2025, the Supreme Court issued an opinion in Seven County Infrastructure Coalition v. Eagle County emphasizing the “substantial judicial deference” that courts must grant agencies when considering NEPA challenges. In September 2025, CEQ issued new guidance to assist federal agencies inimplementing assessingNEPA encouraging them to limit their NEPA reviews, rely more heavily on sponsor-prepared documents, and streamline the GHG emissions and climate change effects of their proposed actions under the National Environmental Policy Act (“NEPA”). In May 2024, the CEQ published a final rule which, in the second and final “phase” of updates, revised the implementing regulations of procedural provisions of NEPA and implements NEPA amendments included in the Financial Responsibility Act of 2023.process. The final rule was challenged by various states. In the U.S. District Court for the District of North Dakota in February 2025, the court issued an order vacating the May 2024 rule citing a November 2024 opinion of the U.S. Court of Appeals for the D.C. Circuit, which held that the CEQ lacks authority to issue NEPA regulations. As a result of these rulings and the recent change in presidential administration, there is significant uncertainty with respect to current and future NEPA regulations. For example, on January 20, 2025, President Trump issued an Executive Order directing the CEQ to issue guidance and propose rescinding existing NEPA regulations to “expedite and simplify the permitting process.” While the impact of these developments isremains unclear at this time, but any disruption in our ability to obtain permits could result in costs that could have a material adverse effect on our business, financial condition and results of operations.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production, processing and transportation of natural gas, NGLs and oil. While the Trump administration may make changes to President Biden’s environmental and climate change initiatives, we cannot predict what, when, or how the newTrump administration may take actions to revise existing environmental laws or regulations, if at all, or the ultimate impact such changes may have on our business. For more information on these matters, see “Item 1. Business and Properties—Regulation of the Oil and Natural Gas Industry—Regulation of Environmental and Occupational Safety and Health Matters.” Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In August 2022, President Biden signed the IRA 2022 into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. However, on January 20, 2025, President Trump issued an Executive Order directing agencies to immediately pause the disbursement of funds appropriated through the IRA 2022. The full impact of this Executive Order and related administrative actions is uncertain at this time. In addition, the IRA 2022 imposesimposed the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amendsamended the federal Clean Air Act to impose a fee on the excess emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. On November 12, 2024, the EPA finalized the methane emissions charge rule, which applies to oil and gas facilities emitting more than 25,000 metric tons of CO2 per year. The charge is set to starthowever, in calendar year 2024 at $900 per ton of methane, increase to $1,200 inFebruary 2025, andCongress berepealed setthe atrule $1,500under forthe 2026Congressional andReview eachAct. yearAdditionally, after.under Calculationthe OBBB, Congress delayed the implementation of the feemethane isemissions basedcharge onuntil certain2034. thresholdsCompliance established inwith the IRAmethane 2022. The methaneemissions charge and theother incentivesair forpollution renewablecontrol energyand infrastructurepermitting developmentrequirements could impose additional costs on our operations and further reduce demand for oil and natural gas. This could decrease demand for oil and gas and consequently adversely affect our business and results of operations. Congress may seek to revise the IRA 2022 to remove this rule, but weWe cannot predict whether,if when, or how Congress might seek to do so. Thethe Trump administration may also seek to challenge, repeal, and/or revise this rule, and Congress may attempttake tofurther repeal or amend the IRA 2022, includingactions with respect to the IRA 2022 or the methane emissions charge;charge, however,nor can we cannot predict what, when, or how the new administration or Congress may take actions to rollback or otherwise revise existing laws, rules, or regulations or the ultimate impact such changes may have on our business or results of operations.

The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years. In June 2016, the EPA finalized NSPS, known as Subpart OOOOa, that establish emission standards for methane and VOCs from new and modified oil and natural gas production and natural gas processing and transmission facilities. Most recently, in December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc. UnderHowever, in March 2025, the finalEPA rules, states have two years to prepare and submit theirannounced plans to imposereconsider methaneOOOOb emissionand controlsOOOOc, onin existingline sources. The presumptive standards established underwith the finalTrump administration’s deregulatory agenda. Additionally, in November 2025, the EPA finalized an interim rule are generallyextending the samecompliance deadlines for bothcertain provisions provided in OOOOb and OOOOc. Litigation challenging the EPA’s final interim rule extending such compliance deadlines for new and existing sources.oil The requirements include enhanced leak detection survey requirements using opticaland gas imagingsources andremains otherpending. advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems and zero-emission requirements for certain devices. The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. The rules are currently subject to legal challenges, and the Trump administration may seek to revise or repeal these rules; however, weWe cannot predict what additional actions the newTrump administration may take or how they might affect our business or results of operations. Moreover, compliance with the new rules may affect the amount we owe under the IRA 2022’s methane fee described above because compliance with EPA’s methane rules would exempt an otherwise covered facility from the requirement to pay the methane fee. The requirements of the EPA’s final methane rules have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. Moreover,However, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states, including West Virginia and Ohio, have separately imposed or are considering imposing their own regulations on methane emissions from oil and gas production activities.

Additionally, companies in the oil and natural gas industry may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-oil and natural gas related sectors. Certain institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to lending practices, and some of them may elect in future not to provide funding for oil and natural gas companies.companies, although this trend has been decreasing. To the extent implemented or pursued, such policies and commitments could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. While we cannot predict how or to what extent sustainable lending and investment practices may impact our operations, a material reduction in the capital available to the oil and natural gas industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our products or otherwise adversely impact our financial performance.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including PaulMichael M.N. Rady,Kennedy, our Chairman, President and Chief Executive Officer,Officer and President, could have a material adverse effect on our business, financial condition and results of operations.

As of December 31, 2024,2025, we have U.S. federal and state NOL carryforwards of $0.6approximately billion$960 million and $1.9 billion, respectively, and U.S. federal tax credit carryforwards of $148$153 million. We have recorded a reserve for uncertain tax positions related to our U.S. federal tax credits of $54$51 million as of December 31, 2024.2025. Some of the U.S. federal NOL carryforwards expire in 2037 while others have no expiration date. We expect to fully utilize our U.S. federal NOL carryforwards and U.S. federal tax credit carryforwards prior to expiration. The state NOL carryforwards expire at various dates from 20252026 to 2044 while others have no expiration date. We do not expect to utilize certain of these NOL carryforwards due to changes in state tax law. Therefore, we have placed a valuation allowance against $1.2 billion of these state NOL carryforwards. These expectations are based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and upon our NOL carryforwards not becoming subject to future limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), or otherwise.

From time to time, U.S. federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently applicable to natural gas and oil exploration and development companies. Such proposed legislative changes include, but are not limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations. It is unclear whether theseany or similarsuch changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction. The passage of any such legislation as a result of these proposals andor other changes in tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could increase our future tax liabilities and adversely affect our operating results and cash flows.

We have assembled a portfolio of long-lived properties that are ancharacterized independentby oilwhat we believe to be high repeatability and naturallow gasgeologic company engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin.risk. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations.locations in the Appalachian Basin. As of December 31, 2025, we held approximately 537,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 168,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.

As of December 31, 2024,2025, our estimated proved reserves were 17.919.1 Tcfe, consisting of 10.611.8 Tcf of natural gas, 674679 MMBbl of assumed recovered ethane, 519529 MMBbl of C3+ NGLs and 23 MMBbl of oil. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2024,2025, we had 1,1371,279 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024.possible.

We have three reportable segments: (i) the exploration, developmentexploration and production of natural gas, NGLs and oil; (ii) marketing of excess firm transportation capacity; and (iii) midstream services throughproduction, our equity method investment in Antero Midstream.Midstream and marketing. All of our operations are conducted in the United States. See Note 17—Reportable Segments to our consolidated financial statements for additional information.

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas and ethane decreasedincreased significantly, while benchmark prices for oil remained consistent and benchmark prices for C3+ NGLs increasedand oil decreased, during the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. As a result of the lowerhigher benchmark natural gas and ethane prices and higher benchmark C3+ NGLs prices during the year ended December 31, 2024,2025, we experienced a decrease in price realizations for natural gas and ethane products and an increase in price realization for C3+natural gas and ethane products, partially offset by the effects of decreased benchmark NGLs productsand duringoil prices as compared to the sameyear period.ended December 31, 2024. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in UkraineUkraine, Venezuela and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. However, we use derivative instruments when circumstances warrant to manage our exposure to commodity price risk. See “—Hedge Position” and Note 11—Derivative Instruments to our consolidated financial statements for additional information on our derivative instruments.

Antero Resources (Excluding Martica)

We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. DueFor tothe ouryears improvedended liquidityDecember 31, 2024 and leverage2025, position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For 20234% and 2024,8%, substantially allrespectively, of our production was unhedged.hedged through commodity derivatives. Assuming our 20252026 production is the same as our production in 2024,2025, approximately 3%42% of our total production for 2025 is hedged through fixed price commodity swaps.derivatives. In addition, we also have derivative contracts in place for a portion of our 2027 production. As of December 31, 2024,2025, the estimated fair value of our commodity derivative contracts, excluding Martica,contracts was a net liabilityasset of $45$81 million. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

Our consolidated VIE, Martica, alsopreviously maintainsmaintained a portfolio of fixed priceswap swapnatural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio arewere fully attributable to the noncontrolling interests in Martica. During the three months ended March 31, 2025, all of Martica’s derivative contracts expired. As of December 31, 2024,2025, theMartica estimatedhad fair value of Martica’s commodityno derivative contracts was a net liability of $2 million.instruments. See Note 11—Derivative Instruments to our consolidated financial statements for additional information.

The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2024. For example, CPI for all urban consumers increased 4.1% from December 2022 to December 2023 and an additional 2.9% from December 2023 to December 2024. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.0%1.75% betweenin September2024 and December 2024.2025. While inflationary pressures in the United States’ economy have begun to subside, weit continueis touncertain bewhat impactedimpact recent tariff activity by the increasedUnited federalStates fundsand interestforeign rate.governments will have on inflation. See “—Results of Operations” for additional information.

The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctionssanctions, on Russia andtariffs, other global trade restrictions,restrictions and conflicts, including those in the Middle East, Iran and Venezuela, among others. However,While our supply chain has not experienced any significant interruptions as a result of such events.events, there can be no assurance that we will not experience interruptions in the future.

We have three reportable segments: (i) the exploration, developmentexploration and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services throughproduction, our equity method investment in Antero Midstream.Midstream and marketing. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 17—Reportable Segments to our consolidated financial statements for additional information.

NGLsNatural gas sales. Revenues from sales of NGLsnatural gas increased from $1.8 billion for the year ended December 31, 20232024 to $2.1$2.9 billion for the year ended December 31, 2024,2025, an increase of $0.3$1.1 billion, or 13%.58%. Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 20242025 accounted for an approximate $153$1.0 millionbillion increase in year-over-year revenuesnatural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Higher NGLsnatural gas production volumes during the year ended December 31, 2024 accounted for an approximate $77$34 million increase in year-over-year NGLsnatural revenuesgas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value gains. Our commodity derivatives included fixed price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income. For the years ended December 31, 20232024 and 2024,2025, our commodity hedges resulted in derivative fair value gains of $166$1 million and $1$111 million, respectively. For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled derivative losses, as well as $202 million for payments on derivatives that were settled prior to their contractual settlement dates. For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains. For the year ended December 31, 2025, commodity derivative fair value gains included $17 million of net cash payments for settled derivative losses.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled, monetized or terminated prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. Additionally, substantially all of our production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remainedincreased relatively consistent at $2.6 billion andfrom $2.7 billion for the yearsyear ended December 31, 20232024 andto 2024,$2.9 respectively.billion for the year ended December 31, 2025, an increase of $0.2 billion, or 6%. This fluctuation was primarily a result of the following:

Production and ad valorem tax expense. Production and ad valorem taxes increaseddecreased from $159 million for the year ended December 31, 2023 to $208 million for the year ended December 31, 2024,2024 anto increase$163 million for the year ended December 31, 2025, a decrease of $49$45 million or 31%,21%, primarily due to higherlower ad valorem taxes,taxes of $115 million between periods, partially offset by lowerhigher severance taxes of $70 million as a result of increased natural gas and oil prices during the year ended December 31, 2024.2025. Production and ad valorem taxes as a percentage of natural gas revenues increaseddecreased from 7% for the year ended December 31, 2023 to 11% for the year ended December 31, 2024,2024 to 6% for the year ended December 31, 2025, primarily as a result of higherlower ad valorem taxes,taxes whichbetween 2024periods. West Virginia ad valorem taxes in 2024 were based on commodity prices during 2022, and West Virginia ad valorem taxes in 2025 are based on commodity prices during 2022.2023.

Depletion, depreciationGeneral and amortizationadministrative expense. DD&AGeneral and administrative expense (excluding equity-based compensation expense) increased from $747$163 million for the year ended December 31, 20232024 to $762$172 million for the year ended December 31, 2024,2025, an increase of $15$9 millionmillion, or 2%,5%, primarily due to higher productionprofessional volumesservice fees and increased salary and wage expense as a result of increased employee headcount between periods. OnWe had 616 and 632 employees as of December 31, 2024 and 2025, respectively. General and administrative expense on a per-unitper basis,unit DD&Abasis expense(excluding remainedequity-based consistentcompensation) atincreased $0.61from $0.13 per Mcfe for the yearsyear ended December 31, 20232024 andto 2024.$0.14 per Mcfe for the year ended December 31, 2025 primarily as a result of higher overall costs between periods.

Impairment of property and equipment. Impairment of property and equipment decreased from $51 million for the year ended December 31, 2023 to $47 million for the year ended December 31, 2024,2024 to $29 million for the year ended December 31, 2025, a decrease of $4$18 million, or 8%,38%, primarily due to lower impairments of expiring leases between periods.periods as a result of our maintenance capital program. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to utilize.

Contract termination, loss contingency, settlements and other operating expenses. Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment decreasedincreased from $29 million for the year ended December 31, 2023 to $5 million for the year ended December 31, 2024.2024 to $28 million for the year ended December 31, 2025, an increase of $23 million. This decreaseincrease was primarily due to a loss contingencycontingencies recorded during the year ended December 31, 20232025. andSee lowerNote expense15—Contingencies associatedto withour theconsolidated earlyfinancial terminationstatements offor certainadditional drilling and completion contracts between periods.information.

Net marketing expense decreasedremained fromrelatively $79consistent million, or $0.06 per Mcfe, for the year ended December 31, 2023 toat $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024,2024 primarilyand due$64 tomillion, loweror firm$0.05 transportationper commitmentsMcfe, betweenfor periods.the year ended December 31, 2025.

Marketing expense. Marketing expense decreased from $285 million for the year ended December 31, 2023 to $245 million for the year ended December 31, 2024,2024 to $190 million for the year ended December 31, 2025, a decrease of $40$55 million, or 14%.22%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gascommodity purchases decreased $62by $60 million between periods, partially offset by increased oil and NGLs purchases of $37 million and $4 million, respectively. The total cost of third-party commodity purchases decreasedperiods primarily due to lower natural gas marketing volumes and oil prices between periods, partially offset by higher oilnatural andgas NGLs marketing volumesprices during the year ended December 31, 2024.2025. Firm transportation costs decreasedincreased $19$5 million frombetween $105periods millionprimarily fordue to the increase in fuel costs and lower pipeline utilization due to maintenance during the year ended December 31, 2023 to $86 million for the year ended December 31, 2024, primarily due to the reduction in firm transportation commitments between periods.2025.

Equity Method Investment in Antero Midstream Segment

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $1.0 billion for the year ended December 31, 2023 to $1.1 billion for the year ended December 31, 2024,2024 to $1.2 billion for the year ended December 31, 2025, an increase of $0.1 billion, or 6%.billion. This increase is primarily due to higher gathering and compressionprocessing revenues of $84$61 million,million partiallyand offset by lowerhigher water handling revenues of $20$21 million. The increased gathering and compressionprocessing revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The decreasedincreased water handling revenues between periods is primarily due to lowerhigher wastewater trucking and blending volumes, increased wastewater trucking and disposal costs that are billed at cost plus 3% higher fresh water delivery volumes and other fluid handling volumes, partially offset by an increased freshblending watercost deliveryof rateservice due to an annual CPI-based adjustmentfees during the year ended December 31, 2024.2025, as well as an increase to the fresh water delivery rate as a result of the annual CPI-based rate adjustment between periods.

InterestTransaction expense. InterestThere expensewere remainedno consistenttransaction atexpenses $118incurred million forduring the yearsyear ended December 31, 20232024. andDuring 2024.the year ended December 31, 2025, we incurred $4 million of transaction expense related to the HG Acquisition. See Note 73—Long-Term DebtTransactions to our consolidated financial statements for additional information.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations in the Appalachian Basin. As of MarchJune 31,30, 2026, we held approximately 855,000858,000 net acres in the Appalachian Basin.

On December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Production for total cash consideration of $2.8 billion, subject to the terms and conditions thereof. The HG Acquisition included approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. This acquisition closed on Februarythe 3,Closing 2026.Date. The HG Acquisition was funded with borrowings under the Term Loan, net proceeds of the 2036 Notes, borrowings under the Credit Facility and restricted cash. See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information. The Company’s condensed consolidated statement of operations for the threesix months ended MarchJune 31,30, 2026 included results of operations from the assets and operations acquired in the HG Acquisition from Februarythe 3,Closing 2026Date through MarchJune 31,30, 2026.

In light of the nature and location of the assets and operations acquired in the HG Acquisition, we and Antero Midstream agreed in principle to certain updates to, and intend to modify, our existing commercial arrangements to provide for on-padwell pad compression with respect to certain wells and to provide certain water services. See Note 15—Related Parties to our unaudited condensed consolidated financial statements for additional information.

On January 28, 2026, we issued $750 million of 5.400% senior notes due February 1, 2036 at a price of 99.869% of par. The 2036 Notes are unsecured and rank pari passu to our Credit Facility, Term Loan and other outstanding senior notes. The 2036 Notes are not guaranteed by any of our subsidiaries. The net proceeds from this offering were used to partially fund the HG Acquisition. See Note 3—Transactions and Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

On February 3, 2026, substantially concurrently with the consummation of the HG Acquisition, we entered into an unsecured three year term loan facility in an aggregate principal amount of $1.5 billion with the lenders party thereto and Royal Bank of Canada, as administrative agent. Borrowings are unsecured and are not guaranteed by any of our subsidiaries. On February 3, 2026, we borrowed $1.5 billion in a single borrowing to partially fund the HG Acquisition. The Term Loan is scheduled to mature on February 3, 2029. As of June 30, 2026, we have $1.1 billion outstanding on the Term Loan. See Note 3—Transactions and Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

DuringOn theFebruary three months ended March 31,24, 2026, we redeemed the remaining $365 million principal amount of the 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest, and the 2029 Notes were fully retired on such date. See Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for naturalC3+ gasNGLs and oil increased significantly, while benchmark prices for ethanenatural gas and C3+ NGLsethane decreased and benchmark prices for oil remained relatively consistent during the three months ended MarchJune 31,30, 2026 as compared to the same period of 2025. As a result of the higher benchmark natural gasBenchmark prices during the three months ended March 31, 2026, we experienced an increase in price realization for natural gas products,and partiallyoil offsetincreased bysignificantly, the effects of decreasedwhile benchmark prices for ethane decreased and C3+ NGLs pricesremained consistent during the six months ended June 30, 2026 as compared to the threesame monthsperiod ended March 31,of 2025. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine, Venezuela and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows. However, we use derivative instruments when circumstances warrant to manage our exposure to commodity price risk. See “—Hedge Position” and Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information on our derivative instruments.

We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. For the three months ended MarchJune 31,30, 2025 and 2026, 4% and 42%,47%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. For the six months ended June 30, 2025 and 2026, 4% and 44%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps. Assuming our 2026 production is the same as our production in 2025, approximately 54% of our total production for 2026 is hedged through commodity derivatives, excluding basis swaps. In addition, for the three and six months ended MarchJune 31,30, 20252026, 18% and 2026, zero and 12%,15%, respectively, of our production was hedged with basis swap commodity derivatives. We did not have any basis swap commodity derivatives for the three and six months ended June 30, 2025. Assuming our 2026 production is the same as our production in 2025, approximately 20% of our total production for 2026 is hedged with basis swap commodity derivatives. As of MarchJune 31,30, 2026, the estimated fair value of our commodity derivative contracts was a net asset of $202$228 million. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information.

Three Months Ended MarchJune 31,30, 2025 Compared to Three Months Ended MarchJune 31,30, 2026

Natural gas sales. Revenues from sales of natural gas increasedremained fromrelatively $0.8consistent billionat $689 million and $688 million for the three months ended MarchJune 31,30, 2025 to $1.3 billion for the three months ended March 31,and 2026, an increase of $0.5 billion, or 68%,respectively, primarily due to an additional $178$143 million of natural gas sales revenue attributable to the HG Acquisition properties,properties as well asand higher commodity prices and natural gas production volumes between periods.periods, Higherpartially offset by the Utica Shale Divestiture and lower natural gas commodity prices (excludingbetween the effects of derivative settlements) during the three months ended March 31, 2026 accounted for an approximate $367 million increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).periods. Higher natural gas production volumes accounted for an approximate $164$190 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price). Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $189 million decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

NGLs sales. Revenues from sales of NGLs decreasedincreased from $561$481 million for the three months ended MarchJune 31,30, 2025 to $504$588 million for the three months ended MarchJune 31,30, 2026, aan decreaseincrease of $57$107 million, or 10%,22%, primarily due to loweran commodityadditional prices, partially offset by higher production volumes between periods and $16$38 million of NGLs revenue attributable to the HG Acquisition properties.properties Lowerand higher NGLs commodity prices and production volumes between periods, partially offset by the Utica Shale Divestiture. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended MarchJune 31,30, 2026 accounted for an approximate $79$80 million decreaseincrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher C3+NGLs production volumes accounted for an approximate $22$27 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Oil sales. Revenues from sales of oil decreasedincreased from $50$34 million for the three months ended MarchJune 31,30, 2025 to $47$60 million for the three months ended MarchJune 31,30, 2026, aan decreaseincrease of $3$26 million, or 7%,77%, primarily due to loweran oiladditional prices and production volumes, partially offset by $3$10 million of oil revenue attributable to the HG Acquisition properties.properties Lowerand higher oil prices,commodity prices between periods, partially offset by the Utica Shale Divestiture. Higher commodity prices (excluding the effects of derivative settlements,settlements) during the three months ended June 30, 2026 accounted for an approximate $2$22 million decreaseincrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes). LowerHigher oil production volumes during the three months ended June 30, 2026 accounted for an approximate $1$4 million decreaseincrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value gains (losses).gains. Our commodity derivatives included fixed price swaps, collars, basis swaps and three-way collars, among others. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our unaudited condensed consolidated statements of operations and comprehensive income. For the three months ended MarchJune 31,30, 2025 and 2026, our commodity hedges resulted in derivative fair value lossesgains of $72$53 million and fair value gains of $35$161 million, respectively. For the three months ended MarchJune 31,30, 2025, commodity derivative fair value lossesgains included $11$6 million of net cash payments for settled commodity derivative losses. For the three months ended MarchJune 31,30, 2026, commodity derivative fair value gains included $165$134 million of net cash paymentsproceeds for settled derivative losses.gains.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.

Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP remained relatively consistent at $6 million for the three months ended MarchJune 31,30, 2025 and 2026. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Lease operating expense. Lease operating expense per Mcfe increased 8% from $34 million, or $0.11$0.12 per Mcfe,Mcfe for the three months ended MarchJune 31,30, 2025 to $45 million, or $0.13 per Mcfe,Mcfe for the three months ended MarchJune 31,30, 2026 primarily due to higher wastewater trucking and disposal costs due to the timing of well completions activity between periods. Lease operating expense increased from $37 million for the three months ended June 30, 2025 to $48 million for the three months ended June 30, 2026, an increase of $11 millionmillion, or 29%, primarily due to incremental lease operating expense of $6$8 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods.periods, partially offset by the Utica Shale Divestiture.

Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense increasedper Mcfe decreased 12% from $695$2.25 million,per orMcfe $2.27for the three months ended June 30, 2025 to $1.99 per Mcfe, for the three months ended MarchJune 31,30, 20252026 primarily due to $789the million,HG orAcquisition $2.28properties perthat Mcfe,have a lower compression, processing and transportation costs. Gathering, compression, processing and transportation expense increased from $702 million for the three months ended MarchJune 31,30, 2025 to $748 million for the three months ended June 30, 2026, an increase of $94$46 millionmillion, or 7%, primarily due to higher production volumes between periods and incremental gathering, compression, processing and transportation expense of $39$70 million related to the HG Acquisition properties.properties and higher production volumes between periods, partially offset the Utica Shale Divestiture. The fluctuation of our gathering, compression, processing and transportation expense on a per unit basis was primarily a result of the following:

Depletion, depreciationProduction and amortizationad valorem tax expense. DD&AProduction expenseand ad valorem taxes as a percentage of natural gas revenues remained consistent at 5% for the three months ended June 30, 2025 and 2026. Production and ad valorem taxes increased from $186$35 million for the three months ended MarchJune 31,30, 2025 to $206$38 million for the three months ended MarchJune 31,30, 2026, an increase of $20$3 million, or 11%,8%, primarily due to incremental expense of $6 million related to the HG Acquisition properties and higher production volumes between periodsperiods, relatedpartially tooffset ourby HGthe AcquisitionUtica properties.Shale On a per-unit basis, DD&A expense remained relatively consistent at $0.61 per McfeDivestiture and $0.60lower pernatural Mcfegas forprices during the three months ended MarchJune 31,30, 2025 and 2026, respectively.2026.

ContractEquity-based termination,compensation lossexpense. contingencyNon-cash andequity-based settlements.compensation Contractexpense termination,decreased lossfrom contingency and settlements was a gain of $1$16 million for the three months ended MarchJune 31,30, 2025.2025 Contractto termination, loss contingency and settlements was a loss of $12$13 million for the three months ended MarchJune 31,30, 20262026, a decrease of $3 million or 16%. This decrease was primarily due to losslower contingenciesRSU and settlementsPSU recordedaward during the first quarterexpense of 2026.$2 million and $1 million, respectively, between periods. See Note 149—ContingenciesEquity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

GainContract ontermination, saleloss ofcontingency assets.and Gainsettlements. onContract saletermination, ofloss assetscontingency wasand lesssettlements thandecreased $1from $14 million for the three months ended MarchJune 31,30, 2025.2025 Gainto on sale of assets was $46$2 million for the three months ended MarchJune 31,30, 20262026, a decrease of $12 million. This decrease was primarily due to thelower Uticaloss Shalecontingencies Divestiture that closed on February 23, 2026.recorded. See Note 314—TransactionsContingencies to the unaudited condensed consolidated financial statements for additional information.

Net marketing expense increaseddecreased from $17 million, or $0.06 per Mcfe, or $18 million, for the three months ended MarchJune 31,30, 2025 to $21 million, or $0.06$0.04 per Mcfe, or $16 million, for the three months ended MarchJune 31,30, 2026, primarily due to higher pipeline utilization and lower fuel costs between periods, partially offset by higher demand fees on certain pipelines and lower pipeline utilization due to maintenance between periods.pipelines.

Marketing revenue. Marketing revenue increased from $26$34 million for the three months ended MarchJune 31,30, 2025 to $42$56 million for the three months ended MarchJune 31,30, 2026, an increase of $16$22 million, or 63%.66%. This fluctuation primarily resulted from the following:

Marketing expense. Marketing expense increased from $43$52 million for the three months ended MarchJune 31,30, 2025 to $63$72 million for the three months ended MarchJune 31,30, 2026, an increase of $20 million, or 46%.39%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party oil purchases increased $11$23 million between periods,periods primarily due to higher oil marketing prices and volumes during the three months ended June 30, 2026, partially offset by lower natural gas marketing volumes during the three months ended MarchJune 31,30, 2026. Firm transportation costs increaseddecreased $9$3 million between periods primarily due to lowerhigher pipeline utilization asbetween a result of higher pricing in the Appalachian Basinperiods and alower pipelinefuel force majeurecosts during the three months ended MarchJune 31,30, 2026.

Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $291$305 million for the three months ended MarchJune 31,30, 2025 to $314$327 million for the three months ended MarchJune 31,30, 2026, an increase of $23$22 million. This increase is primarily due to higher gathering and processing revenues of $21$18 million and higher water handling revenues of $2$4 million. The increased gathering and processing revenues between periods is primarily due to higher low pressure gathering and compression volumes from the HG Acquisition and 80 wells connected to their system between periods and increased gathering and centralized compression rates as a result of annual CPI-based adjustments.adjustments, partially offset by the Utica Shale Divestiture and natural production decline of the wells connected to their system between periods. The increased water handling revenues between periods is primarily due to higher blending cost of service fees, increased volumes and costs for wastewater trucking and disposal volumes, a higher fresh water delivery fee as a result of an annual CPI-based adjustment and fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the three months ended MarchJune 31,30, 2026, partiallyas offsetwell byas decreasedhigher blending cost of service fees, increased costs for wastewater trucking and disposal volumes and an increase to the fresh water delivery volumesrate as a result of an annual CPI-based rate adjustment between periods due to the timing and location of our completions activity.periods.

Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $114$119 million for the three months ended MarchJune 31,30, 2025 to $126$145 million for the three months ended MarchJune 31,30, 2026, an increase of $12$26 million. This increase is primarily due to higher direct operating expenses as a result of increased gathering volumesand betweenwell periodspad compression costs related to assets acquired with the HG Acquisition andduring the three months ended June 30, 2026, as well as increased fresh water delivery services on our acreage acquired in the HG Acquisition,Acquisition asduring wellthe asthree month ended June 30, 2026, increased wastewater trucking and disposal volumes between periods and higherincreased blending volumes and costs between periods.periods, partially offset by the Utica Shale Divestiture.

Interest expense, net.expense. Interest expense, netexpense increased from $23$20 million for the three months ended MarchJune 31,30, 2025 to $37$38 million for the three months ended MarchJune 31,30, 2026, an increase of $14$18 millionmillion, or 58%,88%, primarily due to borrowings to fund our HG Acquisition under the Term Loan and issuance of the 2036 Notes during the threefirst monthsquarter ended March 31,of 2026, partially offset by the redemption of the 2029 Notes.Notes on February 24, 2026 and lower Credit Facility borrowings and rates between periods. See Note 7—Long-Term Debt to ourthe unaudited condensed consolidated financial statements for more information.

Loss on early extinguishment of debt. During the three months ended MarchJune 31,30, 2025, we recognizedrepurchased a loss on early debt extinguishment of $3 million primarily related to the redemption of the remaining $97$23 million aggregate principal amount of our 20262029 Notes through open market transactions at a redemptionweighted priceaverage premium of 102.094%approximately 102% of the principal amount thereof, plus accrued and unpaid interest.interest, During the three months ended March 31, 2026, weand recognized a loss on early debt extinguishment of $7$1 millionmillion. relatedThere towas no loss on early extinguishment of debt for the redemptionthree ofmonths theended remainingJune $36530, million principal amount of our 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest.2026. See Note 7—Long-Term Debt to ourthe unaudited condensed consolidated financial statements for more information.

Income tax expense. For the three months ended March 31, 2025, we recognized an incomeIncome tax expense ofincreased $54from $48 million, with an effective tax rate of 20%,22%, related to our income before income taxes of $274 million. Forfor the three months ended MarchJune 31,30, 2026,2025 weto recognized income tax expense of $146$79 million, with an effective tax rate of 21%,22%, relatedfor the three months ended June 30, 2026 primarily due to ourthe increase in income before income taxes ofbetween $694 million.periods.