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

Antero Resources is our most significant customer and has accounted for substantially all of our revenue since inception, and we expect to derive most of our revenues from Antero Resources in the near term. As a result, any event, whether in our area of operations or otherwise, that adversely affects Antero Resources’ production, drilling and completion schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our business and results of operations. Accordingly, we are indirectly subject to the business risks of Antero Resources, including, among others:

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 Appalachian region in recent years. Because Antero Resources’ production and reserves predominantly consist of natural gas and NGLs (59%61% and 38% of equivalent proved reservesreserves, respectively), changes in natural gas and NGLs prices have a significantly greater impact on Antero Resources’ financial results than oil prices. 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 Antero Resources’ ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.

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 and negative impacts on our stock price and 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 or our customers, including Antero Resources 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. And whileWhile we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations, we cannot guarantee that such participation or certification will have the intended results on our ESG profile.

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. Additionally,In addition, while we may also announce various voluntary ESGsustainability targets, including ourcertain goals to achieve a 100% reduction in pipelineGHG emissions by 2025 and to achieve net zero Scope 1 (direct) and Scope 2 (indirect from the purchase of energy) emissions by 2050,goals, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESGsustainability impact instead of actual changes in our ESGsustainability performance. However, 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 or implement or adequately make progress toward 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, we cannot guarantee that such participation or certification will have the intended results on our ESGsustainability profile. Also, despite these 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 ESGsustainability plans or goals or stakeholder perceptions of certain statements made by us, others in our industry, 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 ESGsustainability matters are becoming increasingly subject to heightened scrutiny from public and governmental authoritiesauthorities, as well as other parties, related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESGsustainability benefits. Additionally, certain employment practices and social initiatives are the subject of scrutiny by both those calling of the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that we face increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on our environmental commitments or our pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of sustainability and social-related factors in our decision making could be subject to increasing scrutiny and objection from such anti-ESG parties. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESGsustainability 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, Antero Resources 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 Resources and our customers, which may adversely impact our business, financial condition or results of operations.

Acquisitions and TakeoversDivestitures

In addition, new or additional regulations, new interpretations of existing requirements or changes in our operations could also trigger the need for Environmental Assessments or more detailed Environmental Impact Statements under the National Environmental Policy Act (“NEPA”) and analogous state laws, or that impose new permitting requirements on our operations could result in increased costs or delays of, or denial of rights to conduct, our development programs. For instance, there have been several recent developments regarding the 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 its opinion in Seven County Infrastructure Coalition v. Eagle County, emphasizing the “substantial judicial deference” that courts must grant agencies when considering NEPA challenges. And, 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 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 full 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.

Further, in April 2020, the federal district court for the District of Montana determined that the CWA Section 404 NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court’s order has subsequently been limited to the particular pipeline in that case pending appeal, we cannot predict the ultimate outcome of this case and its impacts to the NWP program. Relatedly, in response to the vacatur, the Corps reissued NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, an October 2021 decision by the District Court for the Northern District of California resulted in a vacatur of a 2020 rule revising the CWA Section 401 certification process. The U.S. Supreme Court has since stayed this vacatur and the EPA published a rule to update and replace the relevant regulations in September 2023. Several states challenged the rule. In January 2026, the EPA published a proposed rule revising its regulations governing the CWA Section 401 certification process. Additionally, in March 2022, the Corps announced that it was seeking stakeholder input on a formal review of NWP 12. While the full extent and impact of these developments is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. This in turn could have an adverse effect on our business, financial condition and results of operation.

Separately, the definition of WOTUS has been subject to substantial controversy, with the Corps and EPA pursuing several WOTUS rulemakings since 2015. MostIn recently,September 2023, the EPA issued a WOTUS rule in September 2023 that is currently only implemented in 24 states due to ongoing litigation. Thus,However, in November 2025, the operativeEPA and the Corps proposed a rule to further update and narrow this September 2023 definition of WOTUSWOTUS, variesguided by state.the Sackett v. EPA decision. To the extent any judicial ruling, administrative rulemaking, or other action further expandschanges the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our business, financial condition and results of operations. We cannot predict what, when or how the Trump administration may take action with respect to any of these regulations. Further, any discharges of natural gas, NGLs, oil and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See “Item 1. Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.

All of Antero Resources’ natural gas, NGLs and oil production is developed from unconventional sources, such as shale formations. These reservoirs require hydraulic fracturing completion processes to release the liquids and natural gas from the rock so it can flow through casing to the surface. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand (or other proppant) combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities. For example, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

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 EPA finalized a rule implementing this charge in November 2024. Congress may seek to revise the IRA to remove this charge, but we cannot predict whether, when or how Congress might seek to do so. The IRA 2022 amendsamended the federal Clean Air Act to impose a fee on the emission of excess 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. The EPA finalized a rule implementing this charge in November 2024; however, in February 2025, Congress repealed the rule under the Congressional Review Act. Additionally, under the OBBB, Congress delayed the implementation of the methane emissions charge woulduntil start2034. inCompliance calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation ofwith the feemethane is based on certain thresholds established in the IRA 2022. The methaneemissions charge and theother incentivesair forpollution renewablecontrol energyand infrastructurepermitting developmentrequirements could impose additional costs on our operations and reduce demand for oil and natural gas. ThisConsequently, this could decrease demand for oil and gas and consequently, adversely affect our business and results of operations and those of our customers. The Trump administration may seek to challenge, repeal, or revise this rule; however weWe cannot predict what, when, or how the newTrump administration makeor Congress may take further actions to rollback or otherwise revise existing laws, rules, or regulations or the ultimate impact such changes may have on our business operations.

Climate risks continue to attract considerable attention in the United States and in foreign countries. In the United States, no comprehensive climate legislation has been implemented at the federal level. Federal regulators, state and local governments and private parties have taken (or announced that they plan to take) actions that have or may have a significant influence on our operations. The EPA has adopted regulations under existing provisions of the federal CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. However,Although existingthe EPA has proposed to delay GHG reporting for the oil and gas sector until 2034, and to otherwise repeal GHG reporting requirements for other sectors, we cannot predict whether these efforts will ultimately be successful or that GHG reporting will not be required again in the future. Existing climate change-related regulation hashave already becomebeen a focus of the new Trump Administration.administration. On his first day in office, President Trump signed several Executive Orders rescinding many of the previous administration’s Executive Orders and associated climate-related initiatives. President Trump’s directives included, amongst others, directing the EPA to reconsider its 2009 endangerment findings relating to GHGs, which provides regulatory justification for federal GHG permitting and methane emission control requirements, and directing the EPA to reconsider its use of Social Cost of GHG estimates in federal permitting decisions. To that end, in March 2025, the EPA announced formal reconsideration of both the Social Cost of GHG estimates and the 2009 endangerment finding and, in July 2025, released a proposal to rescind the latter. We cannot predict the ultimate impact of these Executive Ordersactions or any similar future changes 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 established 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. These rules are currently subject to legal challenges, and weWe cannot predict thewhat finaladditional outcome. However,actions the OOOOb rules are currently in effect. The Trump administration may seek to revise or repeal these rules; however, we cannot predict what actions the new administration may take, if at all, or on what timelines,take or how they may affect our business operations. Moreover, compliance with the new rules may affect the amount we owe under the IRA’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 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 industries. Certain institutional lenders who provide financing to oil and natural gas 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. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the oil and natural gas industry. 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 midstream services.

Following legislation enacted by Congress, PHMSA has issued or proposed regulations that either seek to impose new obligations on pipeline operations or expand existing pipeline safety requirements to previously unregulated pipelines. For example, in November 2021, PHMSA issued a final rule that imposes safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities, in accordance with the PIPES Act of 2020. PHMSA, together with state regulators, are expected to commence and complete inspection of these plans in 2022. In August 2022, PHMSA finalized the rule entitled “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change and Other Related Amendments” which adjusted the repair criteria for pipelines in HCAs, created new criteria for pipelines in non-HCAs and strengthened integrity management assessment requirements, among other items. However, in August 2024, the U.S. Court of Appeals for the D.C. Circuit vacated various aspects of the 2022 rule relating to high-frequency-electric resistance welding, repair requirements of cracks relating to maximum allowable operating pressure, corrosive constituents, and the dent-safety-factor standard.rule. In April 2024, PHMSA promulgated a final rule that amended Federal pipeline safety regulations to incorporate more than 20 new or updated voluntary, consensus industry technical standards to allow pipeline operators to use current technologies and improved materials. In January 2025, PHMSA finalized a rule that enhances the safety requirements for gas distribution pipelines and requires updates to distribution integrity management programs, emergency response plans, operations and maintenance manuals and other safety practices. However, the Trump administration withdrew the final rule shortly thereafter, and, accordingly, it has not been codified. We do not expect our operations to be affected by these new rules or rule changes any differently than other similarly situated midstream companies. Separately, in the Fiscal Year 2021 Omnibus Appropriations Bill, Congress directed PHMSA to move forward with several regulatory actions, the promulgation of rules related to changes in class location of existing pipelines, pipeline leak detection and repair and the management of idled pipelines, amongst other matters. A Notice of Proposed Rulemaking was published in May 2023 to address management of methane emissions and other matters and PHMSA is in the process of analyzing comments. While we cannot predict the full scope of these regulations at this time, more stringent requirements may require us to incur significant costs to maintain compliance, which may have a negative impact on our business performance and results of operations.

We depend on the services of a relatively small group of 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, Chairman, President andKennedy, Chief Executive Officer,Officer and President, could have a material adverse effect on our business, financial condition and results of operations.

If a holder sells our common stock, the holder will recognize gain or loss equal to the difference between the amount realized and the holder’s tax basis in the shares of common stock sold. To the extent that the amount of distributions on our common stock exceeds our current and accumulated earnings and profits, such distributions will be treated as a tax free return of capital and will reduce a holder’s tax basis in its common stock. We expect thea majorityportion of our distributions to be in excess of our earnings and profits through 2027.2028. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in our common stock, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of our common stock.

We are a growth-oriented midstream energy company formed to own, operate and develop midstream energy assets to primarily service Antero Resources’ production and completion activity. We believe that our strategically located assets and our relationship with Antero Resources have allowed us to become a leading midstream energy company serving the Appalachian Basin and present opportunities to expand our midstream services to other operators in the Appalachian Basin. Our assets consist of gathering pipelines, compressor stations and interests in processing and fractionation plants that collect and process production from Antero Resources’ wells in the Appalachian Basin in West Virginia and Ohio. Our assets also include two independent water handling systems that deliver water from the Ohio River and several regional waterways. These water handling systems consist of permanent buried pipelines, surface pipelines and water storage facilities, as well as pumping stations, blending facilities and impoundments. Portions of these water handling systems are also utilized to transport flowback and produced water. These services are provided by us directly or through third-parties with which we contract.

AssetAcquisition Acquisitionand Divestiture

Issuance of Senior Notes

RepurchaseIssuance of Senior2033 Notes

During the year ended December 31, 2024,2025, we repurchased or otherwise fully redeemed $550$650 million aggregate principal amount of our 7.875%5.75% senior notes due MayMarch 15,1, 20262027 (the “20262027 Notes”) at a weighted average premium of 101.975% of the principal amount thereof,par, plus accrued and unpaid interest. The 20262027 Notes were retired as of MaySeptember 16,23, 2024.2025. See Note 89—Long-Term Debt to our consolidated financial statements for additional information.

On February 13, 2024,Through our Board authorized a share repurchase programprogram, that allows us to repurchase up to $500 million of shares of our outstanding common stock. Duringduring the year ended December 31, 2024,2025, we repurchased and retired approximately 28 million shares of our common stock through our share repurchase program for a total cost of $29$135 million. As of December 31, 2024,2025, we have $471approximately $336 million of capacity remaining under our share repurchase program. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The exact number of shares to be repurchased by us is not guaranteed and the program may be suspended, modified or discontinued at any time without prior notice. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program.

Benchmark prices for natural gas decreasedand ethane increased significantly, while benchmark prices for oilC3+ remained relatively consistentNGL’s and NGLsoil increaseddecreased during the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. While substantially all of our revenues are based on fixed-fee contracts that are not directly impacted by changes in commodity prices, commodity price changes do impact the revenues and cash flows of Antero Resources, and Antero Resources’ drilling and development plan does have a direct impact on our gathering, compression and water handling services, revenues and cash flows. In the current economic environment, we expect that commodity prices for some or all of the commodities produced by Antero Resources could remain volatile. However, due to Antero Resources’ improvedincreased scale, liquidity and leverage position as compared to historical levels,levels together with Antero Resources’ increased commodity derivative portfolio, we do not expect to experience significant variability in our throughput volumes resulting from volatile commodity prices.

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 the year ended December 31, 2022 to the year ended December 31, 2023 and an additional 2.9% from the year ended December 31, 2023 to the year ended December 31, 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 Seewill “—Resultshave ofon Operations” for additional information.inflation.

The economy also continues to be impacted by 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 neither our nor Antero Resources’ supply chain has experienced any significant interruptions due to such events.events, there can be no assurance that we will not experience interruptions in the future.

The operating results of our reportable segments wereare as follows:

Revenues. Total revenues increased by 6%,7%, 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. Total revenues included amortization of customer relationships of $71 million duringfor each of the years ended December 31, 20232024 and 2024.2025. Gathering and processing revenues increased by 10%,7%, from $805 million for the year ended December 31, 2023 to $889 million for the year ended December 31, 2024.2024 Waterto handling revenues decreased by 8%, from $237$950 million for the year ended December 31, 20232025. toWater handling revenues increased by 10%, from $217 million for the year ended December 31, 2024.2024 to $238 million for the year ended December 31, 2025. These fluctuations primarily resulted from the following:

Direct operating expenses. Direct operating expenses increased by 2%,6%, from $213 million for the year ended December 31, 2023 to $218 million for the year ended December 31, 2024.2024 to $232 million for the year ended December 31, 2025. Gathering and processing direct operating expenses increased by 8%5% from $96 million for the year ended December 31, 2023 to $103 million for the year ended December 31, 2024 to $108 million for the year ended December 31, 2025 primarily due to increased high pressure gathering and compression volumesvolumes, betweenhigher periodscosts andfor our acquisition ofthe two compressor stations and 48 miles of high pressure gathering lines acquired during the second quarter of 2024.2024 and increased heavy maintenance expense between periods. Water handling direct operating expenses decreasedincreased by 2%,8%, from $117 million for the year ended December 31, 2023 to $115 million for the year ended December 31, 2024 to $124 million for the year ended December 31, 2025 primarily due to decreased fresh water andincreased other fluid handling volumesvolumes, higher wastewater trucking and disposal costs, and increased blending costs between periods, partially offset by increased pipeline maintenance, repair and monitoring activities.periods.

General and administrative (excluding equity-based compensation) expenses. General and administrative expenses (excluding equity-based compensation expense) increasedremained byconsistent 6%, from $39 million for the year ended December 31, 2023 toat $42 million for the year ended December 31, 2024 primarilyand due2025, to higher costs allocated to us from Antero Resources.respectively.

Equity-based compensation expenses. Equity-based compensation expenses increasedremained byrelatively 40%consistent fromat $32$44 million forand the year ended December 31, 2023 to $44$46 million for the year ended December 31, 2024 primarilyand due2025, to annual equity-based awards granted during the first quarter of 2024. Our equity-based awards vest over three or four year service periods.respectively. See Note 1011—Equity-Based Compensation to our consolidated financial statements for additional information.

Depreciation expense. Depreciation expense increaseddecreased by 3%4%, from $136 million for the year ended December 31, 2023 to $140 million for the year ended December 31, 2024.2024 Thisto increase$134 wasmillion for the year ended December 31, 2025 primarily due to $5lower milliondepreciation related to assets placed in service between periods and $1 million for our assets acquired during the second quarterexpense of 2024, partially offset by $2$11 million of lower expense between periods related to our program to repurpose underutilized compressor units to expand existing or construct new compressor stations.stations between periods, partially offset by depreciation expense of $4 million related to assets placed in service between periods and higher depreciation expense of $1 million for our assets acquired during the second quarter of 2024.

Interest expense. Interest expense decreased by 5%,8%, from $217 million for the year ended December 31, 2023 to $207 million for the year ended December 31, 2024 to $190 million for the year ended December 31, 2025 primarily due to lower Creditinterest Facilityexpense borrowingson betweenour periodssenior andnotes due to the repurchase and redemption of $550the million7.875% principalsenior amountnotes due May 15, 2026 (the “2026 Notes”) during the year ended December 31, 2024, and the redemption of the 20262027 Notes during the year ended December 31, 2024,2025, as well as lower interest rates on our Credit Facility between periods, partially offset by the issuanceissuances of $600the million6.625% principalsenior amountnotes ofdue February 1, 2032 (the “2032 Notes”), 2033 Notes duringand the2034 yearNotes endedand Decemberhigher 31,average 2024.borrowing on our Credit Facility between periods. See Note 9—Long-Term Debt to our consolidated financial statements for additional information.

Equity in earnings of unconsolidated affiliates. Equity in earnings in unconsolidated affiliates increased by 5%, from $105 million for the year ended December 31, 2023 to $111 million for the year ended December 31, 2024 to $116 million for the year ended December 31, 2025 primarily due to increased processing and fractionation volumes and higher processing and fractionation fees as a result of annual CPI-based adjustments between periods.

Loss on early extinguishment of debt. During the year ended December 31, 2024, we repurchasedrecognized a loss on early extinguishment of debt of $14 million related to the premium paid to repurchase or otherwise fully redeemedredeem the $550 million aggregate principal amountall of our 2026 Notes at a weighted average premium of 101.975% of the principal amount thereof, plus accrued and unpaid interest, andas well as the write-off of unamortized deferred financing costs. During the year ended December 31, 2025, we recognized a loss on early debt extinguishment of $14 million. There was no loss on early extinguishment of debt forof $1 million related to the yearwrite-off endedof Decemberunamortized 31,deferred 2023.financing costs and premium attributable to our 2027 Notes that were fully redeemed at par, plus accrued and unpaid interest. See Note 89—Long-Term Debt to our consolidated financial statements for additional information.

Income tax expense. Income tax expense increased by 15%2%, from $128 million for the year ended December 31, 2023 to $148 million for the year ended December 31, 2024,2024 to $151 million for the year ended December 31, 2025, which reflects effective tax rates of 25.7%26.9% and 26.9%,26.8%, respectively. This income tax expense increase was primarily due to higher pre-taxincome before income taxes between periods. TheSee increaseNote in8—Income Taxes to our effectiveconsolidated taxfinancial ratestatement betweenfor periodsadditional was primarily due to changes in apportionment of state income taxes during the year ended December 31, 2024.information.

Capital resources and liquidity are provided by operating cash flows, available borrowings under our Credit FacilityFacility, our Utica Shale Divestiture and capital market transactions. See Note 83—Transactions and Note 9—Long-Term Debt to our consolidated financial statements for additional information. We expect that the combination of these capital resources will be adequate to meet our working capital requirements, capital expenditures program and expected quarterly cash dividends for at least the next 12 months.

We expect our future cash requirements relating to working capital, capital expenditures, acquisitions and quarterly cash dividends to our stockholders will be funded from cash flows internally generated from our operationsoperations, orthe net proceeds from the offering of the 2034 Notes, proceeds from our Utica Shale Divestiture and borrowings under the Credit Facility.

On February 12,11, 2025,2026, we announced a 20252026 capital budget with a range of $170$190 million to $200$220 million. ThisOur capital budget supportsreflects Anterothe Resources’closing maintenanceof capitalthe programHG forAcquisition 2025.on February 3, 2026 and assumes the closing of the Utica Shale Divestiture during February 2026. Our capital budgets may be adjusted as business conditions warrant. If natural gas, NGLs and oil prices decline to levels below acceptable levels or costs increase to levels above acceptable levels, Antero Resources could choose to defer a significant portion of its budgeted capital expenditures until later periods. As a result, we may also defer a significant portion of our budgeted capital expenditures to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate consistent cash flows. We routinely monitor and adjust our capital expenditures in response to changes in Antero Resources’ development plans, changes in prices, availability of financing, acquisition costs, industry conditions, the timing of regulatory approvals, success or lack of success in Antero Resources’ drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Additionally, we monitor our existing assets and look for opportunities to reuse or otherwise repurpose assets in an effort to optimize our capital efficiency.

We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities,purchases, open market purchases, privately negotiated transactions or otherwise. Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved could be material. We were in compliance with all covenants and ratios applicable to our debt agreements as of December 31, 20232024 and 2024.2025. The amounts involved could be material. See Note 89—Long-Term Debt to our consolidated financial statements for additional information.

Income taxes are accounted for using the asset and liability approach. Under this approach, deferred income tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. We record deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. We record a deferred income tax benefit to the extent our deferred income tax assets exceed our deferred income tax liabilities. We are subject to state and U.S. federal income taxes, but are currently not in a cash tax paying position with respect to U.S. federal income taxes.

On December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Midstream for cash consideration of $1.1 billion, subject to the terms and conditions thereof. The HG Acquisition included gathering pipelines and integrated water handling assets in the core of the Marcellus Shale in West Virginia. This acquisition closed on Februarythe 3,Closing 2026.Date. 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.

The HG Acquisition was funded with net proceeds of the 2034 Notes, borrowing under the Credit Facility and restricted cash. See Note 3—Transactions to our condensed consolidated financial statements for additional information. In light of the nature and location of the assets and operations acquired in the HG Acquisition, we and Antero Resources agreed in principle to certain updates to, and intend to modify, our existing commercial arrangements with Antero Resources to provide for on-padwell pad compression with respect to certain wells and to provide certain water services. See Note 6—Revenue to our condensed consolidated financial statements for additional information.

Through our share repurchase program, during the three and six months ended MarchJune 31,30, 2026, we repurchased and retired approximately 0.4 million shares of our common stock for a total cost of $8 million and approximately 1 million shares of our common stock for a total cost of $18$26 million.million, respectively. As of MarchJune 31,30, 2026, we have approximately $318$310 million of remaining capacity under our share repurchase program. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The exact number of shares to be repurchased by us is not guaranteed and the program may be suspended, modified or discontinued at any time without prior notice.

Benchmark prices for naturaloil gasand C3+ NGLs increased significantly, while benchmark prices for oilnatural remained relatively consistent and benchmark prices for C3+ NGLsgas and ethane decreased during the three months ended MarchJune 31,30, 2026 as compared to the same periodsperiod of 2025. Benchmark prices for oil and natural gas increased, while benchmark prices for C3+ NGLs remained relatively consistent and benchmark prices for ethane decreased during the six months ended June 30, 2026 as compared to the same period of 2025. While substantially all of our revenues are based on fixed-fee contracts that are not directly impacted by changes in commodity prices, commodity price changes do impact the revenues and cash flows of Antero Resources, and Antero Resources’ drilling and development plan does have a direct impact on our gathering, compression and water handling services, revenues and cash flows. In the current economic environment, we expect that commodity prices for some or all of the commodities produced by Antero Resources could remain volatile. However, due to Antero Resources’ increased scale, liquidity and leverage position as compared to historical levels together with Antero Resources’ increased commodity derivative portfolio, we do not expect to experience significant variability in our throughput volumes resulting from volatile commodity prices.

We have two reportable segments: (i) gathering and processing and (ii) water handling. The gathering and processing segment includes a network of gathering pipelines and centralized compressor stations and on-padwell pad compressors that collect and process production from Antero Resources’ wells in the Appalachian Basin, as well as equity in earnings from our investments in the Joint Venture and Stonewall. The Joint Venture and Stonewall provide processing and fractionation services and high-pressure gas gathering services, respectively, in the Appalachian Basin. The water handling segment includes (i) an independent system that delivers water from sources including the Ohio River, local reservoirs and several regional waterways, and (ii) other fluid handling services, which include high rate transfer, wastewater transportation, disposal and blending. See Note 17—Reportable Segments 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

Revenues. Total revenues increased by 8%,7%, 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. Total revenues included amortization of customer relationships of $18 million and $21$23 million for the three months ended MarchJune 31,30, 2025 and 2026, respectively. Gathering and processing revenues increased by 9%,8%, from $229$240 million for the three months ended MarchJune 31,30, 2025 to $250$258 million for the three months ended MarchJune 31,30, 2026. Water handlinghanding revenues increased by 3%,6%, from $62$65 million for the three months ended MarchJune 31,30, 2025 to $64$69 million for the three months ended MarchJune 31,30, 2026. These fluctuations primarily resulted from the following:

Direct operating expenses. Direct operating expenses increased by 24%,34%, from $57$63 million for the three months ended MarchJune 31,30, 2025 to $71$85 million for the three months ended MarchJune 31,30, 2026. Gathering and processing direct operating expenses increased by 15%42% from $26 million for the three months ended MarchJune 31,30, 2025 to $30$37 million for the three months ended MarchJune 31,30, 2026 primarily due to increased gathering volumesand well pad compression costs between periods related to assets acquired with the HG Acquisition.Acquisition, partially offset by the Utica Shale Divestiture. Water handling direct operating expenses increased by 33%,28%, from $31$37 million for the three months ended MarchJune 31,30, 2025 to $41$48 million for the three months ended MarchJune 31,30, 2026 primarily due to fresh water delivery volumes provided by Antero Resources on acreage it acquired from HG Production,Production during the second quarter of 2026, increased wastewater trucking and disposal volumes between periods and increased blending costs between periods.

General and administrative (excluding equity-based compensation) expenses. General and administrative expenses (excluding equity-based compensation expense) remained relatively consistent at $11 million and $12 million for each of the three months ended MarchJune 31,30, 2025 and 2026, respectively.

Equity-based compensation expenses. Equity-based compensation expenses remained relatively consistent at $12 million and $11 million for the three months ended MarchJune 31,30, 2025 and 2026, respectively. Our equity-based awards vest over three or four year service periods.2026. See Note 11—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

Depreciation expense. Depreciation expense increased by 6%,12%, from $33 million for the three months ended MarchJune 31,30, 2025 to $35$37 million for the three months ended MarchJune 31,30, 2026 primarily due to incremental depreciation expense of $3$4 million related to gathering and water pipelines acquired in the HG Acquisition and $3 million for assets placed in service duringbetween the year,periods, partially offset by lower depreciation as a result of the Utica Shale Divestiture of $3 million between periods.

Interest expense, net. Interest expense, net increased by 12%,16%, from $48 million for the three months ended MarchJune 31,30, 2025 to $54$56 million for the three months ended MarchJune 31,30, 2026 primarily due to issuance of the 2033 Notes and 2034 Notes during the second half of 2025, partially offset by the redemption of the 2027 Notes,Notes and lower average daily Credit Facility borrowings and higher interest income on cash equivalents and restricted cashrates between periods. See Note 9—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

Equity in earnings of unconsolidated affiliates. Equity in earnings of unconsolidated affiliates increasedremained byrelatively 7%,consistent fromat $28$30 million and $29 million for the three months ended MarchJune 31,30, 2025 to $30 million for the three months ended March 31, 2026 primarily due to increased processing volumes and higher2026, processing and fractionation fees as a result of annual CPI-based adjustments between periods.respectively.

Income tax expense. Income tax expense increasedremained byrelatively 4%,consistent fromat $36$44 million and $41 million for the three months ended MarchJune 31,30, 2025 to $38 million for the three months ended March 31,and 2026, which reflects effective tax rates of approximately 23%26% andfor 24%,each respectively.respective This income tax increase was primarily due to the effects of equity-based compensation expense between periods.period.

Our Board declared a cash dividend on the shares of our common stock of $0.225 per share for the quarter ended MarchJune 31,30, 2026. The dividend is payable on MayAugust 13,12, 2026 to stockholders of record as of AprilJuly 29, 2026. Our Board also declared a cash dividend of $137,500 on the shares of Series A Preferred Stock that is payable on MayAugust 15,14, 2026 in accordance with their terms as discussed in Note 13—Equity and Net Income Per Common Share. As of MarchJune 31,30, 2026, there were dividends in the amount of $68,750 accumulated in arrears on our Series A Preferred Stock.

As of MarchJune 31,30, 2026, we did not have any off-balance sheet arrangements.

The following table summarizes our cash flows for the threesix months ended MarchJune 31,30, 2025 and 2026:

Operating activities. Net cash provided by operating activities was $199$464 million and $239$493 million for the threesix months ended MarchJune 31,30, 2025 and 2026, respectively. This increase in cash flows provided by operating activities between periods was primarily the result of lower cash used for working capital,capital and increased gathering and processing and water handling revenues during the threesix months ended MarchJune 31,30, 2026,2026 attributable to the HG Acquisition and decreased direct operating expenses for the Utica Shale Divestiture, partially offset by increased gathering and processing and water handling direct operating expenses attributable to the HG Acquisition and lower gathering and processing revenues for the Utica Shale Divestiture between periods.

Investing activities. Net cash flows used in investing activities was $32$72 million and $781$816 million for the threesix months ended MarchJune 31,30, 2025 and 2026, respectively. The increase in cash flows used in investing activities between periods was primarily due to cash paid for the HG Acquisition of $1.1 billion during the threesix months ended MarchJune 31,30, 2026, as well as increased capital spending for gathering systems and facilities of $12 million and water handling systems of $10$12 million, partially offset by proceeds from the Utica Shale Divestiture of $379 million during the threesix months ended MarchJune 31,30, 2026.

Financing activities. Net cash used in financing activities was $167$392 million for the threesix months ended MarchJune 31,30, 2025 and net cash provided by financing activities was $279$60 million for the threesix months ended MarchJune 31,30, 2026, respectively. The increase in cash flows provided by financing activities between periods was primarily due to the increase in net borrowings on our Credit Facility of $449$437 million and lower share repurchases of $11$19 million between periods, partially offset by higher payments for employee tax withholding for settlement of equity-based compensation awards of $14$6 million and higher payments of deferred financing costs of $2 million.