UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024
For the fiscal year ended December 31, 2025
or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 001-38075

ANTERO MIDSTREAM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

61-1748605
(IRS Employer
Identification No.)

1615 Wynkoop Street Denver, Colorado
(Address of principal executive offices)

80202
(Zip Code)

(303) 357-7310

(Registrant’s telephone number, including area code)




Securities registered pursuant to section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01	AM	New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ⌧ Yes ◻ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ◻ Yes ⌧ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ⌧ Yes ◻ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ⌧ Yes ◻ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ⌧

Emerging growth company ☐

Accelerated filer ◻

Non-accelerated filer ◻

Smaller reporting company ☐

If an emerging growth company, indicate by checkmark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ⌧ No

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, ~~2024~~2025, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $56.04 billion based on the $1418.7495 per share closing price of Antero Midstream Corporation’s common stock as reported on that day on the New York Stock Exchange.

Number of shares of the registrant’s common stock outstanding as of February 76, ~~2025~~2026 (in thousands): ~~478~~473,~~606~~081

Documents incorporated by reference: Portions of the registrant’s proxy statement for its annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end are incorporated by reference into Part III of this Annual Report on Form 10-K.

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TABLE OF CONTENTS

		Page
GLOSSARY OF COMMONLY USED TERMS		i
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		iii
SUMMARY RISK FACTORS		v

PART I		1
Items 1 and 2.	Business and Properties	1
Item 1A.	Risk Factors	1514
Item 1B.	Unresolved Staff Comments	3938
Item 1C.	Cybersecurity	3938
Item 3.	Legal Proceedings	4140
Item 4.	Mine Safety Disclosures	4140
PART II		4140
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	4140
Item 6.	Reserved	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4342
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	5352
Item 8.	Financial Statements and Supplementary Data	5453
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	5453
Item 9A.	Controls and Procedures	5453
Item 9B.	Other Information	5554
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	5554
PART III		55
Item 10.	Directors, Executive Officers and Corporate Governance	55
Item 11.	Executive Compensation	5655
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	5655
Item 13.	Certain Relationships and Related Transactions and Director Independence	5655
Item 14.	Principal Accountant Fees and Services	5655
PART IV		56
Item 15.	Exhibit and Financial Statement Schedules	56
SIGNATURES		60

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GLOSSARY OF COMMONLY USED TERMS

The following are abbreviations and definitions of certain terms used in this document, some of which are commonly used in the midstream oil and gas industry:

ASC. Accounting Standards Codification.

ASU. Accounting Standards Update.

Antero Midstream Partners. Antero Midstream Partners LP.

Antero Resources. Antero Resources Corporation.

Antero Treatment. Antero Treatment LLC.

Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, NGLs or water.

Bbl/d” Bbl per day.

Bcf. One billion cubic feet of natural gas.

Bcf/d. Bcf per day.

Bcfe. One billion cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.

Bcfe/d. Bcfe per day.

CPI. Consumer Price Index.

Credit Facility. As the context requires, (i) for any date prior to July 30, 2024, the senior secured revolving credit facility pursuant to the Second Amended and Restated Credit Agreement, dated as of October 26, 2021, and (ii) for July 30, 2024 and thereafter, the ~~New~~senior secured revolving credit facility pursuant to the Third Amended and Restated Credit ~~Facility~~Agreement, dated as of July 30, 2024, as amended to date.

DOT. Department of Transportation.

Dry gas. A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

EPA. Environmental Protection Agency.

ESG. Environmental, social and governance.

Expansion capital. Cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.

FASB. Financial Accounting Standards Board.

FERC. Federal Energy Regulatory Commission.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Finance Corp. Antero Midstream Finance Corporation.

Fresh water. Water that is either (i) raw fresh water or (ii) produced or flowback water that has been treated, including through blending operations.

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GAAP. Generally accepted accounting principles in the United States of America.

GHG. Greenhouse gas.

HG Acquisition. Our acquisition of 100% of the issued and outstanding equity interests of HG Energy II Midstream Holdings, LLC, a Delaware limited liability company, from HG Energy II LLC, a Delaware limited liability company.

High pressure pipelines. Pipelines gathering or transporting natural gas that has been dehydrated and compressed to the pressure of the downstream pipelines or processing plants.

Hydrocarbon. An organic compound containing only carbon and hydrogen.

IRS. The Internal Revenue Service of the United States of America.

Joint Venture. The joint venture entered into on February 6, 2017 between Antero Midstream Partners, which is our wholly owned subsidiary, and MarkWest, a wholly owned subsidiary of MPLX, LP, to develop processing and fractionation assets in Appalachia.

Low pressure pipelines. Pipelines gathering natural gas at or near wellhead pressure that has yet to be compressed (other than by well pad gas lift compression or dedicated well pad compressors) and dehydrated.

Maintenance capital. Cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue.

MarkWest. MarkWest Energy Partners, L.P.

MBbl. One thousand Bbls.

MBbl/d. One thousand Bbls per day.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcf/d. One million cubic feet per day.

Natural gas. Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

New Credit Facility. The senior secured revolving credit facility pursuant to the Third Amended and Restated Credit Agreement, dated as of July 30, 2024

NGLs. Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutane, normal butane and natural gasoline.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil and condensate.

Other fluid handling services. Flowback and produced water services, including blending and storage operations, and transportation away from the well site.

SEC. United States Securities and Exchange Commission.

Stonewall. Stonewall Gas Gathering LLC.

Tcfe. One trillion cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.

Throughput. The volume of product transported or passing through a pipeline, plant, terminal or other facility.

Utica Shale Divestiture. Our divestiture of substantially all of our Utica Shale midstream assets located in Ohio.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this Annual Report on Form 10-K may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact, included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

● Antero Resources’ expected production and development plan;

●

our ability to execute our business strategy;

●

impacts to producer customers of insufficient storage capacity;

●

our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

●

natural gas, NGLs and oil prices;

●

our ability to realize the anticipated benefits of our investments in unconsolidated affiliates;

●

our ability to execute our share repurchase and dividend programs;

●

our ability to complete the construction of or purchase new gathering and compression, processing, water handling or other assets on schedule, at the budgeted cost or at all and the ability of such assets to operate as designed or at expected levels;

●

risks associated with the successful integration and future performance of the HG Acquisition;

●

risks associated with the Utica Shale Divestiture, including the risk that it is not consummated on the terms expected or on the anticipated schedule, or at all;

●

costs of conducting our operations;

● impacts of geopolitical events, including the conflicts in Ukraine, Venezuela and in the Middle East, and world health events;

●

actions taken by third-party producers, operators, processors and transporters;

●

competition;

●

government regulations and changes in laws;

●

operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

●

expectations regarding the amount and timing of litigation awards;

●

pending legal or environmental matters;

●

uncertainty regarding our future operating results;

●

credit markets;

● our ability to achieve our greenhouse gas reduction targets and the costs associated therewith;

● general economic conditions; and

● our other plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K.

iii

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●

our ability to achieve our greenhouse gas reduction targets and the costs associated therewith;

●

general economic conditions; and

●

our other plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K.

We caution investors that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, supply chain or other disruptions, environmental risks, Antero Resources’ drilling and completion and other operating risks, regulatory changes or changes in law, the uncertainty inherent in projecting Antero Resources’ future rates of production, cash flows and access to capital, the timing of development expenditures, impacts of world health events, cybersecurity risks, the state of markets for, and availability of, verified quality carbon offsets and the other risks described or referenced under the heading “Risk Factors” in this Annual Report on Form 10-K.

Should one or more of the risks or uncertainties described or referenced in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K.

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Summary Risk Factors

Customer Concentration

●

Because substantially all of our revenue is currently derived from Antero Resources, any development that materially and adversely affects Antero Resources’ operations, financial condition or market reputation could have a material and adverse impact on us.

●

Because of the natural decline in production from existing wells, our success depends, in part, on Antero Resources’ ability to replace declining production and our ability to secure new sources of natural gas from Antero Resources or third parties. Additionally, our water handling services are directly associated with Antero Resources’ well completion activities and water needs, which are largely driven by the amount of water used in completing each well. Finally, under certain circumstances, Antero Resources may dispose of acreage dedicated to us free from such dedication without our consent. Any decrease in volumes of natural gas that Antero Resources produces, any decrease in the number of wells that Antero Resources completes, or any decrease in the number of acres that are dedicated to us could adversely affect our business and operating results.

Business Operations

●

A material shut-in of production by Antero Resources or any of our other customers could adversely affect our business.

●

Our gathering and compression agreements include minimum volume commitments only under certain circumstances.

●

Our construction or purchase of new gathering and compression, processing, water handling or other assets may not be completed on schedule, at the budgeted cost or at all, may not operate as designed or at the expected levels, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, all of which could adversely affect our financial condition, cash flows and results of operations.

●

Recent action and the possibility of future action on trade by U.S. and foreign governments has increased the costs of certain equipment and materials used in the construction of our assets and has created uncertainty in global markets, which may adversely affect our income from operations and cash flows.

●

If third-party pipelines or other midstream facilities interconnected to our gathering and compression systems become partially or fully unavailable, our operating margin and cash flows could be adversely affected.

●

Our exposure to commodity price risk may change over time.

●

The fees charged to our customers may not escalate sufficiently to cover increases in costs, or the agreements may be amended with less favorable terms, may not be renewed or may be suspended in some circumstances.

●

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water.

● ~~ESG~~Sustainability matters and conservation measures may adversely impact our business.

●

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our business, financial condition and results of operations.

●

An impairment of our assets, including property and equipment and/or intangible assets, could reduce our earnings.

Capital Structure and Access to Capital

●

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.

●

We will be required to make capital expenditures to increase our asset base. If we cannot obtain needed capital or financing on satisfactory terms, we may be unable to expand our business operations and/or our financial leverage could increase.

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●

Restrictions in our existing and future debt agreements could adversely affect our business, financial condition and results of operations.

Acquisitions and ~~Takeovers~~Divestitures

● We may benot ~~unable~~achieve tothe ~~make~~intended ~~attractive~~benefits ~~acquisitions~~of orthe ~~successfully~~HG ~~integrate acquired businesses~~Acquisition, and ~~any~~the ~~inability~~HG toAcquisition ~~do so~~ may disrupt our ~~business~~existing ~~and~~plans ~~hinder~~or ~~our ability to grow~~operations.

●

We may not complete the Utica Shale Divestiture within the anticipated timeframe or at all.

Joint Ventures

●

We own a 50% interest in the Joint Venture, which is operated by MarkWest. While we have the ability to influence certain business decisions affecting the Joint Venture, the success of our investment in the Joint Venture will depend on MarkWest’s operation of the Joint Venture.

●

If the Joint Venture is not successful or if the Joint Venture does not perform as expected, our future financial performance may be negatively impacted.

Compliance with Regulations

●

We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

●

If our assets become subject to FERC regulation or federal, state or local regulations or policies change, or if we fail to comply with market behavior rules, our financial condition, cash flows and results of operations could be materially and adversely affected.

●

Increased regulation of hydraulic fracturing could result in reductions or delays in production by our customers, which could reduce the throughput on our gathering and processing systems and the number of wells for which we provide water handling services, which could adversely impact our revenues.

●

Our operations are subject to a series of risks related to climate that could result in increased operating costs, limit the areas in which our customers may conduct oil and gas exploration and production activities, and reduce demand for the services we provide.

Related Parties

●

Antero Resources owns a significant interest in us and, as a result, conflicts of interest will arise from time to time between it and us, and Antero Resources may favor their own interests to the detriment of us and our other stockholders. Additionally, Antero Resources is under no obligation to adopt a business strategy that favors us.

● Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders.

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PART I

Items 1 and 2. Business and Properties

Overview

Antero Midstream Corporation together with its consolidated subsidiaries (“Antero Midstream,” the “Company,” “we,” “us” or “our”) is a growth-oriented midstream energy company formed to own, operate and develop midstream energy assets that primarily service Antero Resources’ production and completion activity in the Appalachian Basin located in West Virginia and Ohio. Our assets consist of gathering systems and compression facilities, water handling and blending facilities and interests in processing and fractionation plants. We conduct our operations and own our operating assets and ownership interests in the Joint Venture and Stonewall through Antero Midstream Partners and its subsidiaries, all of which are wholly-owned. Additionally, Antero Resources has a 29% ownership interest in us as of December 31, ~~2024~~2025. Unless expressly stated otherwise, the operating and financial information presented in this Annual Report on Form 10-K does not give effect to the HG Acquisition or the Utica Shale Divestiture.

Business Strategy and Competitive Strengths

Scalable Business Model

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. Our significant investment in West Virginia and Ohio infrastructure makes us well positioned to deliver returns on capital and grow the business in a capital efficient manner.

Additionally, we own a 50% equity interest in the Joint Venture to develop processing and fractionation assets in Appalachia and a 15% equity interest in the Stonewall gas gathering system. These investments provide us with greater exposure to the midstream value chain.

Disciplined Capital Investment

We utilize a flexible, just-in-time capital budgeting approach through integrated planning with Antero Resources, which allows us to avoid long lead-times in our capital investments in order to maximize our returns on invested capital. We believe this just-in-time capital budgeting approach is unique to Antero Midstream and allows us to generate sustainable free cash flow.

Fixed Fee Business with Long-Term Customer Contracts

We provide gathering, compression, processing, fractionation and integrated water services, including fresh water delivery services and other fluid handling services, to Antero Resources under long-term, fixed-fee and cost of service fee contracts, limiting our direct exposure to commodity price risk. We have agreements in place to provide gathering and compression services through 2038 and water services through 2035. Both our 2019 gathering and compression agreement (as defined below in “—Our Relationship with Antero Resources—Operational and Managerial Arrangements with Antero Resources”) and water service agreement are subject to automatic annual renewal with rights by either party to terminate on or before the 180th day prior to the effective date of such automatic renewal. Additionally, Antero Resources has (i) dedicated to us all of its current and future acreage in the Appalachian Basin for gathering and compression services and all of its acreage within defined service areas in the Appalachian Basin for water services, subject to any pre-existing dedications or other third-party commitments, and (ii) granted us certain rights of first offer with respect to gathering, compression, processing and fractionation services and water services for acreage located outside of the existing dedicated areas under our existing agreements. See “—Our Relationship with Antero Resources” for further information.

Experienced Management Team

Our management team has worked together for many years and has established a successful track record of developing integrated business models that are capable of delivering consistent returns on invested capital. We intend to leverage our management team’s significant industry expertise and experience developing natural gas resource plays to continue building out our premier midstream ~~energy company to service Antero Resources and the other operators in the Appalachian Basin~~system.

Fixed Fee Business with Long-Term Contracts

We provide gathering, compression, processing, fractionation and integrated water services to Antero Resources under long-term, fixed-fee and cost of service fee contracts with certain minimum volume commitments, limiting our direct exposure to commodity price risk. We have agreements in place to provide gathering and compression services through 2038 and water services through 2035.

Integrated Business Model

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. Our significant investment in West Virginia and Ohio infrastructure makes us well positioned to expand our operations in a capital efficient manner.

Disciplined Capital Investment

We utilize a flexible, just-in-time capital budgeting approach through integrated planning with Antero Resources, which allows us to avoid long lead-times in our capital investments in order to maximize our asset utilization and returns on invested capital. We believe this just-in-time capital investment approach is unique to Antero Midstream and allows us to generate consistent free cash flow.

Strong Balance Sheet and Sustainable Leverage Profile

We are focused on maintaining a strong balance sheet, which includes maintaining a sustainable leverage profile. In recent years, we have significantly reduced our leverage profile and will prioritize it on an ongoing basis.

Operating Segments

Our operations are located in the United States and are organized into two reportable segments: (1) gathering and processing and (2) water handling. Financial information for our reportable segments is located under Note 17—Reportable Segments to our consolidated financial statements.

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~~Culture~~Acquisitions ~~of Continuous Improvement~~ and ~~Responsible Stewardship~~Divestiture

WeHG are committed to a culture of continuous improvement, which serves as our foundation to develop and achieve our ESG goals as well as further our goal of environmental stewardship. Innovation, collaboration, technology and establishing meaningful goals have enabled us to improve our safety record, recycle or reuse a substantial majority of Antero Resources’ produced and flowback water and further our commitment to lowering GHG emissions intensity across our operations. Our 2023 ESG Report, available on our website at www.anteromidstream.com/esg, includes more information on our ESG goals, as well as specific initiatives we have in place to help achieve these goals. Our 2023 ESG Report and other information on our website are not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and are not a part of them. Additionally, see “—Regulation of Environmental and Occupational Safety and Health Matters” for additional information on GHG emissions and “Item 1A. Risk Factors” for risks and uncertainties related to our business operations.Acquisition

~~Operating~~On ~~Segments~~December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Energy II Midstream Holdings, LLC (“HG Midstream”) from HG Energy II LLC (“HG Energy”) for cash consideration of $1.1 billion, subject to the terms and conditions thereof. The HG Acquisition includes gathering pipelines and integrated water handling assets in the core of the Marcellus Shale in West Virginia. Pursuant to the same agreement, Antero Resources agreed to acquire 100% of the issued and outstanding equity interests of HG Energy II Production Holdings, LLC (“HG Production”) from HG Energy for total cash consideration of $2.8 billion, subject to the terms and conditions thereof (the “HG Upstream Acquisition”). The HG Upstream Acquisition includes approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. These acquisitions closed on February 3, 2026. See Note 3—Transactions to our consolidated financial statements for additional information.

~~Our~~Summit ~~operations~~Asset are located in the United States and are organized into two reportable segments: (1) gathering and processing and (2) water handling. Financial information for our reportable segments is located under Note 16—Reportable Segments to our consolidated financial statements.Acquisition

~~Asset~~On ~~Acquisition~~May 1, 2024, we acquired certain Marcellus Shale gas gathering and compression assets from Summit Midstream Partners, LP (NYSE: SMLP) (“Summit”) for $70 million in cash, before closing adjustments, with an effective date of April 1, 2024. The acquired assets include 48 miles of high pressure gathering pipelines and two compressor stations with 100 MMcf/d of compression capacity. These assets were already interconnected to our low pressure and high pressure gas gathering systems at the time of acquisition and service Antero Resources’ production. Currently, we do not expect to make any significant capital investments related to the acquired assets. See Note 3—Transactions to our consolidated financial statements for additional information.

OnUtica ~~May 1,~~Shale 2024, we acquired certain Marcellus gas gathering and compression assets from Summit Midstream Partners, LP (NYSE: SMLP) (“Summit”) for $70 million in cash, before closing adjustments, with an effective date of April 1, 2024. The acquired assets include 48 miles of high pressure gathering pipelines and two compressor stations with 100 MMcf/d of compression capacity. These assets were already interconnected to our low pressure and high pressure gas gathering systems at the time of acquisition and service Antero Resources’ production. Currently, we do not expect to make any significant capital investments related to the acquired assets. See Note 6—Property and Equipment to our consolidated financial statements for additional information.Divestiture

On December 5, 2025, we entered into a definitive agreement with two third-party buyers (collectively, the “Buyer Parties”) to sell substantially all of our Utica Shale midstream assets located in Ohio (the “Utica Shale Property and Equipment”), for aggregate cash consideration of $400 million, subject to the terms and conditions thereof. The Utica Shale Property and Equipment includes 118 miles of gathering pipelines, 0.7 Bcfe/d of compression capacity, 85 miles of water pipelines and 12 water impoundments with storage capacity of approximately 2 million barrels. The Utica Shale Divestiture is expected to close in February 2026, subject to the satisfaction of certain customary closing conditions. See Note 3—Transactions to our consolidated financial statements for additional information.

Our Assets

Our gathering and processing assets consist of high and low pressure gathering pipelines, compressor stations and processing and fractionation plants that collect and process natural gas and NGLs from Antero Resources’ wells in West Virginia and Ohio. Our water handling assets include two independent systems that deliver water from sources, including the Ohio River, local reservoirs and several regional waterways. Portions of these systems are also utilized to transport flowback and produced water. The water handling systems consist of permanent buried pipelines, surface pipelines and water storage facilities, as well as pumping stations, blending facilities and impoundments to transport water throughout the systems used to deliver water to Antero Resources’ well completions.

The following table provides information regarding our gathering and processing systems and water handling systems as of December 31, ~~2024~~2025:


	Gathering and Processing Systems			Water Handling Systems
	Low Pressure	High Pressure	Compression	Buried	Surface
	Pipeline	Pipeline	Capacity	Water Pipeline	Water Pipeline
	(miles)	(miles)	(Bcf/d)	(miles)	(miles)
Appalachian Basin	~~413~~426	~~295~~305	4.68	~~233~~236	~~163~~187

During the year ended December 31, ~~2024~~2025, we added 1213 miles of low pressure pipeline, 6510 miles of high pressure pipeline, ~~including~~three 48 miles of ~~acquired pipelines from our Summit acquisition, one mile of~~ buried water pipeline and 1724 miles of surface water pipeline in the Appalachian Basin. In addition, our compression capacity increased by 0.12 Bcf/d during the year ended December 31, ~~2024~~2025 as a result of our ~~Summit asset acquisition and~~ program to repurpose underutilized compressor units to expand existing or construct new compressor stations. In addition, we plan to redeploy 0.2 Bcf/d of compression capacity related to compressor units taken offline during the year ended December 31, 2024 on the construction of new or expansion of existing compression stations. As of December 31, ~~2024~~2025, we had ~~the~~33 ~~ability~~water toimpoundments ~~store~~with ~~5.3~~storage ~~million~~capacity ~~barrels~~ of ~~water~~approximately in5 34million ~~impoundments~~barrels. Additionally, we built water blending and storage infrastructure to support other fluid handling services that we provide to Antero Resources for well completion and production activities. We also own water treatment assets, including the Antero Clearwater Facility (the “Clearwater Facility”), which we idled in September 2019. Since ~~idling the Clearwater Facility, we have satisfied our obligation to handle Antero Resources’ flowback and produced water through our other fluid handling services.~~

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idling the Clearwater Facility, we have satisfied our obligation to handle Antero Resources’ flowback and produced water through our other fluid handling services.

Our Relationship with Antero Resources

Antero Resources is our most significant customer and is one of the largest producers of natural gas and NGLs in North America. As of December 31, ~~2024~~2025, substantially all of Antero Resources’ approximate ~~567~~566,000 gross acres (~~521~~537,000 net acres) are dedicated to us for gathering, compression and water services. During the year ended December 31, ~~2024~~2025, Antero Resources produced, on average, 3.4 Bcfe/d net (3736% liquids). As of December 31, ~~2024~~2025, Antero Resources’ estimated net proved reserves were 1719.91 Tcfe, which were comprised of 5961% natural gas, 4038% NGLs and 1% oil. Antero Resources’ has a vast drilling inventory of horizontal well locations in the Appalachian Basin (all of which are on acreage dedicated to us) for gathering and compression and water handling services, which provides us with significant opportunities for growth as Antero Resources’ active development program continues.

Antero Resources announced its ~~2025~~2026 drilling and completion budget is $~~650~~1.0 ~~million~~billion to $~~700~~1.2 ~~million~~billion, and includes plans to complete 6070 to 6580 net horizontal wells in the Appalachian Basin. ~~Additionally~~In addition, Antero Resources’ ~~2025~~2026 capital budget includes $75100 million ~~to $100 million~~ for leasehold expenditures, all of which will be dedicated to us. Antero Resources’ 2026 capital budget reflects the closing of the HG Upstream Acquisition on February 3, 2026 and assumes the closing of the divestiture of its Utica Shale oil and gas assets during February 2026. Antero Resources relies significantly on us to deliver the midstream infrastructure necessary to accommodate its development program. For additional information regarding our contracts with Antero Resources, see “—Operational and Managerial Arrangements with Antero Resources.”

We currently derive substantially all of our revenue from Antero Resources. Any development that materially and adversely affects Antero Resources’ operations, financial condition or market reputation could have a material adverse impact on us. Accordingly, we are indirectly subject to the business risks of Antero Resources. For additional information, see “Item 1A. Risk Factors—Customer Concentration.”

Operational and Managerial Arrangements with Antero Resources

Gathering and Compression

Our gathering and compression service agreements with Antero Resources include: (i) the second amended and restated gathering and compression agreement dated December 8, 2019 (the “2019 gathering and compression agreement”), (ii) a gathering and compression agreement acquired with the Crestwood Equity Partners LP (“Crestwood”) assets (the “Marcellus gathering and compression agreement”), (iii) a compression agreement acquired with the EnLink Midstream LLC (NYSE: ENLC) (“EnLink”) assets (the “Utica compression agreement”) and (iv) a gathering and compression agreement acquired with the Summit assets (the “Mountaineer gathering and compression agreement,” and together with the 2019 gathering and compression agreement, the Marcellus gathering and compression agreement and the Utica compression agreement, the “gathering and compression agreements”). See Note 63—~~Property~~Transactions and ~~Equipment~~Note 6—Revenue to our consolidated financial statements for additional information. Pursuant to these gathering and compression agreements, Antero Resources has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to us for gathering and compression services. The 2019 gathering and compression agreement, Marcellus gathering and compression agreement and Mountaineer gathering and compression agreement have initial terms through 2038, 2031 and 2026, respectively, and the Utica compression agreement has two acreage dedications, one of which expired in 2024 and one that expires in 2030. Upon expiration of the Marcellus gathering and compression agreement, the Utica compression agreement and the Mountaineer gathering and compression agreement, we will continue to provide gathering and compression services under the 2019 gathering and compression agreement. We also have an option to gather and compress natural gas produced by Antero Resources on any undedicated acreage it acquires in the future outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions as the 2019 gathering and compression agreement. The Utica compression agreement is included in the Utica Shale Divestiture.

Under the gathering and compression agreements, we receive a low pressure gathering fee per Mcf, a high pressure gathering fee per Mcf and a compression fee per Mcf, as applicable, subject to annual CPI-based adjustments. We intend to make certain modifications to our existing commercial arrangements with Antero Resources to provide for on-pad compression with respect to certain wells. If and to the extent Antero Resources requests that we construct new low pressure lines, high pressure lines and/or compressor stations, our 2019 gathering and compression agreement contains options at our election for either (i) minimum volume commitments that require Antero Resources to utilize or pay for 75% of the high pressure gathering capacity and 70% of the compression capacity of such new construction for 10 years or (ii) a cost of service fee that allows us to earn a 13% rate of return on such new construction over seven years, which election is made individually for each piece of equipment placed in service. The Marcellus gathering and compression agreement provides for a minimum volume commitment that requires Antero Resources to utilize or pay for 25% of the compression capacity for a period of 10 years from the in-service date. The Mountaineer gathering and compression agreement provides for monthly minimum compression and gathering fees for each compressor station or high pressure gathering line, respectively, for a period of 12 years commencing 90 days after such asset’s in-service date. As of December 31, 2024, the minimum volume commitments for the 2019 gathering and compression agreement end in 2034, and the minimum gathering and compression fees for the Mountaineer gathering and compression agreement end in 2026. As of January 1, 2025, there were no minimum volume commitments under the Marcellus gathering and compression agreement. Additional gathering lines and compressor stations installed on our own initiative are not subject to these minimum volume commitments or cost of service fee options. These minimum volume commitments and rate of

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utilize or pay for 25% of the compression capacity for a period of 10 years from the in-service date. The Mountaineer gathering and compression agreement provides for monthly minimum compression and gathering fees for each compressor station or high pressure gathering line, respectively, for a period of 12 years commencing 90 days after such asset’s in-service date. As of December 31, 2025, the minimum volume commitments for the 2019 gathering and compression agreement end in 2035, and the minimum gathering and compression fees for the Mountaineer gathering and compression agreement end in 2026. As of January 1, 2025, there were no minimum volume commitments under the Marcellus gathering and compression agreement. Additional gathering lines and compressor stations installed on our own initiative are not subject to these minimum volume commitments or cost of service fee options. These minimum volume commitments and rate of return options are intended to support the stability of our cash flows.

Water Handling Services

Pursuant to the water services agreement, we provide certain water handling services to Antero Resources within an area of dedication in defined service areas in Ohio and West Virginia. We also have certain rights of first offer with respect to water services for acreage located outside of the existing dedicated areas. Antero Resources agreed to pay us for all water handling services provided by us in accordance with the terms of the water services agreement, under which Antero Resources has no minimum volume commitments. Under the agreement, Antero Resources will pay, and therefore we will receive, a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. Antero Resources also agreed to pay us a fixed fee per barrel for water treatment at the Clearwater Facility, which was idled in the third quarter of 2019 and we expect will remain idled for the foreseeable future. In addition, we also provide other fluid handling services. These operations, along with our fresh water delivery systems, support well completion and production operations for Antero Resources. These services are provided by us directly or through third-parties with which we contract. For other fluid handling services provided by third parties, Antero Resources reimburses our third-party out-of-pocket costs plus 3%. For other fluid handling services provided by us, we charge Antero Resources a cost of service fee. The initial term of the water services agreement runs to 2035.

We intend to make certain modifications to our water services agreement to provide a transition period through 2026 before certain water services would be provided to Antero Resources for the assets acquired from HG Production.

Gas Processing and NGLs Fractionation

The Joint Venture was formed in February 2017 to develop processing and fractionation assets in Appalachia. In connection with our entry into the Joint Venture with MarkWest, we released to the Joint Venture our right to provide certain processing and fractionation services on 195,000 gross acres held by Antero Resources in the Appalachian Basin. We have a right-of-first-offer agreement with Antero Resources for the provision of processing and fractionation services pursuant to which Antero Resources, subject to certain exceptions, may not procure any gas processing or NGLs fractionation services with respect to its production (other than production subject to a pre-existing dedication) without first offering us the right to provide such services.

Secondment and Services Agreements

Pursuant to a secondment agreement and a services agreement, Antero Resources seconds employees to us to provide operational services with respect to our assets and certain corporate, general and administrative services in exchange for reimbursement of any direct expenses and an allocation of any indirect expenses attributable to its provision of such services. These agreements extend through 2039.

Acreage Dispositions

Antero Resources may sell, transfer, convey, assign, grant or otherwise dispose of dedicated properties free of the dedication under our gathering and compression, water services and right-of-first-offer agreements, provided that the number of net acres of dedicated properties so disposed of, when added to the number of net acres of dedicated properties previously disposed of free of the dedication since the respective effective dates of the agreements, does not exceed the aggregate number of net acres of dedicated properties acquired by Antero Resources since such effective dates. Accordingly, under certain circumstances, Antero Resources may dispose of a significant number of net acres of dedicated properties free from dedication without our consent, and we have no control over the timing or extent of such dispositions.

Title to Properties

Our real property is classified into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned these lands without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

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Title to Properties

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, cold winters, hot summers or severe weather events can significantly increase demand and price fluctuations, while seasonal anomalies, such as mild winters, mild summers or severe weather events, can sometimes lessen the impact of these fluctuations. In addition, certain natural gas end users, utilities and marketers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall, thereby smoothing demand for natural gas. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for our services during the summer and winter months and decrease demand for our services during the spring and fall months.

Competition

As a result of our relationship with Antero Resources, we do not compete for the portion of Antero Resources’ existing operations for which we currently provide midstream services and will not compete for future portions of Antero Resources’ operations that are dedicated to us pursuant to: (i) our gathering and compression agreements; (ii) our water handling services agreement; and (iii) our right-of-first-offer agreement with Antero Resources for the provision of processing and fractionation services. For a description of these contracts, see “—Our Relationship with Antero Resources—Operational and Managerial Arrangements with Antero Resources.” However, we face competition in attracting third-party volumes to our gathering and compression and water handling systems. In addition, these third parties may develop their own gathering and compression and water handling systems in lieu of employing our assets.

Regulation of Operations

Regulation of pipeline gathering services may affect certain aspects of our business and the market for our services.

Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act of 1938 (“NGA”), exempts natural gas gathering facilities from regulation by the FERC, under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of some our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility is not a gathering pipeline and the pipeline provides interstate transmission service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978 (“NGPA”). Such FERC-regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

Unlike natural gas gathering under the NGA, there is no exemption for the gathering of crude oil or NGLs under the Interstate Commerce Act (“ICA”). Whether a crude oil or NGLs shipment is in interstate commerce under the ICA depends on the fixed and persistent intent of the shipper as to the crude oil’s or NGLs’ final destination, absent a break in the interstate movement. Antero Midstream believes that the crude oil and NGLs pipelines in its gathering system meet the traditional tests the FERC has used to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on Antero Midstream’s crude oil and NGLs pipelines depends on the shipper’s intentions and the transportation of the crude oil or NGLs outside of Antero Midstream’s system, and may change over time. If the FERC were to consider the status of an individual facility and the character of a crude oil or NGLs shipment, and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by the FERC under the ICA. Such FERC regulation could decrease revenue, increase operating costs and, depending on the facility in question, could adversely affect Antero Midstream’s results of operations and cash flows. In addition, if any of Antero Midstream’s facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and civil remedies and criminal penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.

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to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on Antero Midstream’s crude oil and NGLs pipelines depends on the shipper’s intentions and the transportation of the crude oil or NGLs outside of Antero Midstream’s system, and may change over time. If the FERC were to consider the status of an individual facility and the character of a crude oil or NGLs shipment, and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by the FERC under the ICA. Such FERC regulation could decrease revenue, increase operating costs and, depending on the facility in question, could adversely affect Antero Midstream’s results of operations and cash flows. In addition, if any of Antero Midstream’s facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and civil remedies and criminal penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. States in which we operate may adopt ratable take and common purchaser statutes, which would require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. The regulations under these statutes may have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate may also adopt a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such regulation will be adopted and whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to state regulations.

Our gathering operations could be adversely affected should they be subject in the future to more stringent application of state regulation of rates and services. Our gathering operations also may be, or become, subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

The Energy Policy Act of 2005 (“EPAct 2005”), amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets. The FERC subsequently issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. The FERC’s anti-manipulation rules apply to intrastate sales and gathering activities only to the extent that there is a “nexus” to FERC-jurisdictional transactions. EPAct 2005 also provided the FERC with the authority to impose civil penalties of up to approximately $1 million (adjusted annually for inflation) per day per violation.

In January 2025, FERC issued an order (Order No. 906) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of up to $1,584,648 per violation per day.

Pipeline Safety Regulation

Some of our gas pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), with respect to crude oil and NGLs. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020. The NGPSA and HLPSA regulate safety requirements in the design, construction, operation and maintenance of natural gas, crude oil and NGLs pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil, NGLs and natural gas transmission pipelines in certain high risk areas, such as high-consequence areas (“HCAs”) or moderate consequence areas (“MCAs”).

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The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs and MCAs. The regulations require operators, including us, to:

● perform ongoing assessments of pipeline integrity;

● identify and characterize applicable threats to pipeline segments that could impact certain high risk areas;

● improve data collection, integration and analysis;

● repair and remediate pipelines as necessary; and

● implement preventive and mitigating actions.

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The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the 2011 Pipeline Safety Act, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. In December 2024, those maximum civil penalties were increased to $272,926 and $2,729,245, respectively, to account for inflation. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations.

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 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, completed inspection of these plans in 2022. Additionally, 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~~. InAdditionally, 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. WeFurther, doin ~~not~~January ~~expect~~2025, ~~our~~PHMSA ~~operations~~finalized a rule that enhances the safety requirements for gas distribution pipelines and requires updates to bedistribution ~~affected~~integrity bymanagement ~~these~~programs, ~~new~~emergency ~~rules~~response orplans, operations and maintenance manuals and other safety practices. However, the Trump administration withdrew the final rule ~~changes~~shortly thereafter, and, accordingly, it has not been codified. These new and any ~~differently~~future ~~than~~regulations adopted by PHMSA have imposed and may impose more stringent requirements applicable to integrity management programs and other ~~similarly~~pipeline ~~situated~~safety ~~midstream~~aspects ~~companies~~of our operations, which could cause us to incur increased capital and operating costs and operational delays.

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 the 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.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations.

We regularly review all existing and proposed pipeline safety requirements and work to incorporate the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above, consistent with other similarly situated midstream companies. In addition to regulatory changes, costs may be incurred if there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs and corrective action is required.

Regulation of Environmental and Occupational Safety and Health Matters

General

Our natural gas gathering and compression and water handling activities are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment, natural resources and worker safety. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

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Regulation of Environmental and Occupational Safety and Health Matters

General

● requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way we operate resulting in additional costs to our operations;

● limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands, coastal regions or areas inhabited by endangered or threatened species;

● delaying system modification or upgrades during review of permit applications and revisions;

● requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and

● enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or regulatory requirements imposed by such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or solid waste into the environment.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our capital costs to construct, maintain and operate equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position, results of operations or cash flows, nor do we believe that they will affect our competitive position since the operations of our competitors are generally similarly affected. In addition, we believe that the various activities in which we are presently engaged that are subject to environmental laws and regulations are not expected to materially interrupt or diminish our operational ability to gather natural gas and provide water handling services. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense 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. Our primary customer, Antero Resources, uses the water we deliver to it for hydraulic fracturing as part of its completion operations as does most of the U.S. onshore oil and natural gas industry. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies; however, in recent years the EPA has asserted limited authority over hydraulic fracturing pursuant to the federal Safe Drinking Water Act (“SDWA”) and has issued or sought to propose rules related to the control of air emissions, disclosure of chemicals used in the process and the disposal of flowback and produced water resulting from the process. Some states, including those in which we operate, have adopted and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. For example, both West Virginia and Ohio have adopted requirements governing well pad construction, as well as requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drilling 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 sought to ban hydraulic fracturing altogether. 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. We cannot predict whether any such federal, state or local legal restrictions relating to the hydraulic fracturing process will ever be enacted in areas where our customers operate and if so, what the effects of such restrictions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal state or local level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of water and natural gas that move through our systems, which in turn could materially adversely affect our revenues and results of operations.

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time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. 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. We cannot predict whether any such federal, state or local legal restrictions relating to the hydraulic fracturing process will ever be enacted in areas where our customers operate and if so, what the effects of such restrictions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal state or local level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of water and natural gas that move through our systems, which in turn could materially adversely affect our revenues and results of operations.

Hazardous Waste

Antero Midstream and Antero Resources’ operations generate solid wastes, including small quantities of hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many oil and natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development or production of crude oil and natural gas, including residual constituents derived from those exempt wastes. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations and it is possible that certain oil and natural gas exploration and production wastes now classified as exploration and production-exempt non-hazardous waste could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services, increase our waste disposal costs and adversely affect our business.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Although petroleum as well as natural gas is excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations, our operations generate wastes that may be designated as hazardous substances. CERCLA authorizes the EPA, states, and, in some cases, third parties to take actions in response to releases or threatened releases of hazardous substances into the environment and to seek to recover from the classes of responsible persons the costs they incur to address the release. Under CERCLA, we could be subject to strict joint and several liabilities for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.

We currently own or lease, and may have in the past owned or leased, properties that have been used for the gathering and compression of natural gas and the gathering and transportation of oil. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. Such petroleum hydrocarbons or wastes may have migrated to property adjacent to our owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial operations to prevent future contamination. We are not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at or implicating our facilities or operations.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States (“WOTUS”). The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. The scope of regulated waters has been subject to substantial controversy and uncertainty, with the Corps and EPA pursuing several rulemakings since 2015 to attempt to define the scope of WOTUS. Most recently, EPA issued a WOTUS rule in September 2023 that is currently only implemented in 24 states due to ongoing litigation. Thus, the operative definition of WOTUS varies by state. To the extent the implementation of this rule, results of the litigation, or any action further expands the scope of the CWA’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Separately, in April 2020, the federal district court for the District of Montana determined that the Corps CWA Section 404 Nationwide Permit (“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

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~~projects~~and damages. ~~While~~The ~~the~~scope ~~district~~of ~~court’s~~regulated ~~order~~waters has ~~subsequently~~ been ~~limited~~subject to substantial controversy and uncertainty, with the ~~particular~~Corps ~~pipeline~~and inEPA ~~that~~pursuing ~~case~~several ~~pending~~rulemakings ~~appeal,~~since we2015 ~~cannot~~to ~~predict~~attempt ~~the~~to ~~ultimate~~define ~~outcome~~the scope of ~~this~~WOTUS. In ~~case~~September ~~and~~2023, ~~its~~the ~~impacts~~EPA toissued ~~the~~a ~~NWP~~WOTUS ~~program~~rule that is currently only implemented in 24 states due to ongoing litigation. ~~Relatedly~~However, in ~~response~~November to2025, the ~~vacatur,~~EPA and the Corps ~~reissued~~proposed ~~NWP~~a 12rule ~~for~~to ~~oil~~further update and ~~natural~~narrow ~~gas~~the ~~pipeline~~September ~~activities~~2023 definition of WOTUS, ~~including~~guided ~~certain~~by ~~revisions~~the toSackett v. EPA decision. To the ~~conditions~~extent ~~for~~any judicial ruling, administrative rulemaking, or other action further changes the ~~use~~scope of ~~NWP~~the ~~12;~~CWA’s ~~however~~jurisdiction in areas where we operate, anwe ~~October~~could ~~2021~~face ~~decision~~increased bycosts ~~the~~and ~~District~~delays ~~Court~~with ~~for~~respect ~~the~~to ~~Northern~~obtaining ~~District~~permits offor ~~California~~dredge ~~resulted~~and infill aactivities ~~vacatur~~in ofwetland aareas. Separately, ~~2020~~we ~~rule~~rely ~~revising~~on the Corps’ CWA Section ~~401~~404 ~~certification~~Nationwide ~~process~~Permit (“NWP”) 12. ~~This~~The ~~vacatur~~NWP ~~was~~process ~~subsequently~~relies ~~stayed~~upon by the ~~U.S.~~CWA ~~Supreme~~Section ~~Court~~401 incertification ~~April~~process. In ~~2022~~September 2023, ~~and~~ the EPA published a ~~final~~ rule tofinalizing ~~update~~its ~~and~~CWA ~~replace~~Section ~~the~~401 ~~relevant~~Water ~~regulations~~Quality inCertification ~~September~~Improvement Rule, effective November 2023~~. Litigation~~, ~~regarding~~but ~~the~~shortly ~~use~~thereafter, ofseveral ~~NWP~~states 12challenged the rule. Litigation is ongoing. ~~Additionally,~~In inJanuary ~~March 2022~~2026, the ~~Corps~~EPA ~~announced~~published ~~it would seek stakeholder input on~~ a ~~formal~~proposed ~~review~~rule ofrevising ~~NWP~~its ~~12,~~regulations ~~which~~governing isWater ~~also~~Quality ~~ongoing~~Certifications. While the full extent and impact of these actions 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. However, we cannot predict what, when, or how the Trump administration may take action with respect to any of these regulations. As a result, there is significant uncertainty with respect to wetlands regulations under the CWA at this time.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and regulations provide for administrative, civil and criminal penalties for any discharges not authorized by the permit and may impose substantial potential liability for the costs of removal, remediation and damages. ~~We believe that compliance with such permits will not have a material adverse effect on our business operations.~~

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. ~~We do not believe that any noncompliance with worker health and safety requirements has occurred or will have a material adverse effect on our business or operations.~~

Endangered Species

The federal Endangered Species Act (“ESA”), provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations and have pipeline construction and maintenance projects in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (the “USFWS”), may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Moreover, as a result of a settlement, the USFWS was required to make a determination as to whether more than 250 species classified as endangered or threatened should be listed under the ESA by the completion of the agency’s 2017 fiscal year. For example, in April 2015, the USFWS listed the northern long-eared bat, whose habitat includes the areas in which we operate, as a threatened species under the ESA; however, following a 2020 court order to reconsider this decision the USFWS redesignated this species as endangered in November 2022, which became effective March 1, 2023. The designation of previously unprotected species as threatened or endangered, or redesignation of a threatened species as endangered, in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or could result in limitations on our pipeline construction activities or the exploration and production activities of Antero Resources, any of which could have an adverse impact on our results of operations.

Air Emissions

The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various emission limits, operational limits and monitoring, reporting and recordkeeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations and potentially criminal enforcement actions. These laws are frequently subject to change. ~~Most~~In ~~recently, in~~ 2020, the Trump administration maintained the National Ambient Air Quality Standard (“NAAQS”) for ozone at 70 parts per billion for both the eight-hour primary and secondary standards. ~~The~~We ~~EPA’s reconsideration of this standard remains ongoing. These decisions are subject to legal challenge; however, we~~ cannot predict what further actions, if any, and on what timeline, the Trump administration may take with respect to these regulations. Several EPA new source performance standards (“NSPS”), and national emission standards for hazardous air pollutants (“NESHAP”), also apply to our facilities and operations. These NSPS and NESHAP standards impose emission limits and operational limits as well as detailed

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~~facilities and operations. These NSPS and NESHAP standards impose emission limits and operational limits as well as detailed~~ testing, recordkeeping and reporting requirements on the “affected facilities” covered by these regulations. Several of our facilities are “major” facilities requiring Title V operating permits which impose semi-annual reporting requirements. However, the EPA has recently announced plans to reconsider many of these rules under the Trump administration’s deregulatory agenda and has, in the meantime, extended various compliance deadlines.

Regulation of “Greenhouse Gas” Emissions

InThe ~~response~~EPA tounder ~~findings~~previous ~~that~~presidential ~~emissions~~administrations ~~of GHGs present an endangerment to public health and the environment, the EPA~~ has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”), pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources that are already potential major sources of criteria pollutant emissions regulated under the statute. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for their GHG emissions established by the states or, in some cases, by the EPA, for those emissions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. ~~However~~Although the EPA has proposed to delay GHG reporting for the oil and gas sector until 2034, ~~existing~~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 has already become a focus of the ~~new~~ Trump ~~Administration~~administration. ~~On his first day in office,~~ President Trump has 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~~actions ~~Orders~~ 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 new regulations, known as Subpart OOOOa, that set emissions standards for methane and volatile organic compounds (“VOC”) 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. ~~Under~~However, ~~the~~in ~~final~~March ~~rules~~2025, ~~states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under~~ the final rule are generally the same for both new and existing sources. The requirements include enhanced leak detection survey requirements using optical gas imaging and other 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. This rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA ofannounced ~~large~~plans ~~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~~reconsider ~~challenges,~~OOOOb and ~~we cannot predict the final outcome. However~~OOOOc, ~~the OOOOb rules are currently~~ in ~~effect. Moreover,~~line ~~compliance~~ with the ~~new~~Trump ~~rules may affect the amount we owe under the Inflation Reduction Act~~administration’s ~~(“IRA~~deregulatory ~~2022”)~~agenda. Additionally, ~~methane~~in ~~fee~~November ~~described below~~2025, ~~because~~the ~~compliance with~~ EPA’s ~~methane~~finalized ~~rules~~an ~~would~~interim ~~exempt~~rule anextending ~~otherwise~~the ~~covered~~compliance ~~facility~~deadlines ~~from~~for ~~the~~certain ~~requirement~~provisions toprovided ~~pay~~in ~~the~~OOOOb ~~methane~~and ~~fee~~OOOOc. ~~The~~Litigation ~~requirements~~challenging of the EPA’s final ~~methane~~interim ~~rules~~rule ~~have~~extending ~~the~~such ~~potential~~compliance todeadlines ~~increase~~for ~~our~~new ~~operating costs~~ and ~~thus~~existing may adversely affect our financial results and cash flows. Moreover, 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~~source ~~remain~~remains ~~a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities~~pending. ~~To the extent not timely repealed or modified by the Trump administration, these rules could impose new compliance costs and permitting burdens on natural gas operations.~~

In ~~the United States, no comprehensive climate legislation has been implemented at the federal level. In~~ August 2022, the IRA 2022 was signed into law, ~~appropriating~~which appropriated significant federal funding for renewable energy initiatives~~. 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~~imposed ~~administrative actions is uncertain at this time. For the first time ever, the IRA 2022 imposes~~ a federal fee on excess methane emissions from certain oil and gas facilities. On November 12, 2024, the EPA finalized a rule requiring oil and gas facilities that emit more than 25,000 metric tons of CO2 per year to pay a set fee per metric ton of methane emissions that exceed statutory thresholds. ~~Unless~~However, in February 2025, Congress repealed orthe ~~modified~~rule under the Congressional Review Act. Additionally, under the One Big Beautiful Bill Act (the “OBBB”), Congress delayed the implementation of the methane emissions fee ~~and~~until ~~renewable~~2034. Compliance with the methane emissions fee and ~~low-carbon~~other ~~energy~~air ~~funding~~pollution ~~provisions~~control ofand ~~the~~permitting ~~law~~requirements could increase our operating costs and accelerate the transition away from oil and natural gas, which could in turn adversely affect our business and results of operations, as well as those of our customers. ~~Congress~~Moreover, ~~may~~failure ~~seek~~ to ~~revise~~comply ~~the~~with ~~IRA~~these ~~2022~~CAA torequirements ~~remove~~can ~~this~~result ~~rule,~~in ~~but~~the weimposition ~~cannot~~of ~~predict~~substantial ~~whether,~~fines ~~when,~~and orpenalties ~~how~~as ~~Congress~~well ~~might~~as ~~seek~~costly toinjunctive ~~do so~~relief. ~~The~~Given ~~Trump~~that ~~administration~~the ~~may~~long-term ~~also~~trend ~~seek~~toward toincreasing ~~challenge~~regulation, ~~repeal,~~future orfederal ~~revise~~GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane ~~fee~~emissions ~~rule~~from oroil and gas production activities. To the ~~IRA~~extent ~~2022;~~not ~~however~~timely repealed or modified by the Trump administration, wethese rules could impose new compliance costs and permitting burdens on natural gas operations. We cannot predict when or whether the ~~new~~ administration may take ~~these~~further actions, ~~if at all,~~ or the resulting impact on our business operations.

Since 2017, we have published an annual ESG report, which highlights our most significant environmental program improvements and initiatives. As highlighted in this report, our methane leak loss rate in 2024 was 0.033%, which was calculated in accordance with OneFuture, a voluntary industry partnership focused on reducing methane emissions from the natural gas sector, well below the OneFuture voluntary industry target of 1%.

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~~Internationally,~~During the Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years beginning in 2020. President Biden recommitted the United States to the Paris Agreement in February 2021, and in April 2021, established a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. However, on January 20, 2025, ~~President~~our ~~Trump~~GHG/methane ~~signed~~emission anreduction ~~Executive~~efforts ~~Order~~included ~~once again withdrawing~~ the ~~United~~following States from the Paris Agreement. The United States’ participation in future United Nations climate-related conferences and the impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, any Conference of the Parties, or other international conventions cannot be predicted at this time.activities:

Since 2017, we have published an annual ESG Report, which highlights our most significant environmental program improvements and initiatives. As highlighted in our ESG Report, our methane leak loss rate in 2023 was 0.035%, which was calculated in accordance with OneFuture, a voluntary industry partnership focused on reducing methane emissions from the natural gas sector, well below the OneFuture voluntary industry target of 1%.

During 2024, our GHG/methane emission reduction efforts included the following activities:

●

Conducted quarterly facility LDAR inspections on all of our compressor stations.

● Installed pigging blowdown capture systems at ~~five~~one ~~locations including two~~ compressor ~~stations~~station and ~~three~~one pipeline ~~interchanges~~interchange.

●

Continued implementation of a double-pig capture process that reduces the frequency of pig receiver blowdowns, which has the effect of reducing emissions and improving labor efficiency.

●

Continued deployment of a technology that was successfully field pilot tested with a major engine manufacturer to reduce total carbon emissions while increasing the efficiency of the engine by adding additional horsepower.

●

Continued to shepherd patent pending technology that passed proof of concept examination for hydraulic emission displacement designed to eliminate GHG emissions from pipeline maintenance activities.

●

Utilized our ESG Advisory Council together with our GHG/Methane Reduction Team to manage the identification, evaluation, monitoring, mitigation and adaptation, as applicable, of risks and opportunities related to the environment.

● Maintained our marginal abatement cost curve (“MACC”) to effectively and systematically model emission reduction projects across our operations. Our MACC process is instrumental in evaluating the capital improvements required to achieve our ~~net zero scope 1 and scope 2~~ emissions ~~targets by 2050~~goals.

We continue to assess various opportunities for emission reductions. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe or across all operational assets, or their ultimate effectiveness. We did not have any material capital or other non-recurring expenditures in complying with environmental laws or environmental remediation matters in ~~2024~~2025. However, we cannot guarantee that we will not incur material costs related to compliance with or liability under environmental laws and regulations in the future. For risks and uncertainties related to ~~ESG~~sustainability matters, see “Item 1A. Risk Factors—Business Operations—~~ESG~~Sustainability matters and conservation measures may adversely impact our business.”

Increasingly, oil and natural gas companies are exposed to litigation risks related to climate risks. While we are not currently party to any such litigation, we could be named in future actions making similar claims of liability and depending on the nature of the claims asserted and other factors, such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors. Additionally, demand for hydrocarbons, and therefore our products and services, may be reduced by actions taken at the federal, state or local levels to restrict, ban or limit products that rely on oil and natural gas.

Additionally, our access to capital may be impacted by climate risk policies. Financial institutions may adopt policies that have the effect of reducing the funding provided to the oil and natural gas industry, although this trend has generally 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 midstream services.

In addition, some states have adopted or are considering adopting laws requiring the disclosure of climate-related risks. Lawsuits have been filed challenging the implementation of these laws, but we cannot predict the outcome of these suits at this time. Compliance with these laws, to the extent implemented and applicable to us, may result in additional costs related to disclosure requirements as well as increased costs of and restrictions on access to capital. Separately, enhanced climate-related disclosure requirements could lead to reputational or other harm, and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions.

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~~In addition~~services, insuch ~~March~~as ~~of 2024, the SEC finalized a rule requiring registrants~~ to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and periodic reports. However, this rule is currently paused pending litigation and is expected to be repealed. The timeline for any repeal, if at all, is subject to a number of uncertainties and likely could face legal challenges that would further delay the ~~implementation~~extent ofwarmer ~~any~~winters ~~repeal,~~reduce ~~and we cannot predict~~ the ~~ultimate~~demand ~~outcome. Further,~~for inenergy ~~October~~for ~~2023,~~heating ~~the Governor of California signed the Climate Corporate Data Accountability Act (“CCDAA”) and Climate-Related Financial Risk Act (“CRFRA”) into law~~purposes. ~~The~~Such ~~CCDAA~~physical ~~requires~~risks ~~both~~may ~~public~~also ~~and~~impact private U.S. companies that are “doing business in California” and that have a total annual revenue of $1 billion to publicly disclose and verify, on an annual basis, Scope 1, 2 and 3 GHG emissions. The CRFRA requires the ~~disclosure~~infrastructure ~~of a climate-related financial risk report (in line with the Task Force~~ on ~~the~~which ~~Climate-Related~~we ~~Financial~~rely Disclosures (“TCFD”) recommendations or equivalent disclosure requirements under the International Sustainability Standards Board’s (“ISSB”) climate-related disclosure standards) every other year for public and private companies that are “doing business in California” and have total annual revenue of at least $500 million. Reporting under both laws would begin in 2026. These laws are currently subject to ~~legal~~provide challenges, but the outcome of such challenges are uncertain at this time. Additionally, New York and other jurisdictions are considering adopting similar climate disclosure laws. Currently, the ultimate impact of these laws on our ~~business is uncertain~~services. ~~The~~One ~~Governor~~or ofmore ~~California has directed further consideration~~ of the implementation deadlines for each of the laws, and there is potential for legal challenges to be filed with respect to the scope of the law, but, absent clarification or revisions to the law, alongside the SEC rule, implementation may result in additional costs to comply with these ~~disclosure~~developments ~~requirements as well as increased costs of and restrictions on access to capital. Separately, enhanced climate-related disclosure requirements~~ could ~~lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to~~ have ~~been~~a ~~made~~material byadverse useffect oron ~~others in~~ our ~~industry regarding climate risks~~business, orfinancial incondition ~~connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties~~ and ~~estimations with respect to calculating and reporting GHG emissions~~operations. Separately, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, and there is the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient.

Moreover, climate risks may also result in various physical risks such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our financial condition and operations, as well as those of our suppliers or customers. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our services, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure on which we rely to provide our services. One or more of these developments could have a material adverse effect on our business, financial condition and operations.

Legal Proceedings

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. See “Item 3. Legal Proceedings.”

We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

Human Capital

We believe that our employees and contractors are significant contributors to our past and future success, which depends on our ability to attract, retain and motivate qualified personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance.

All of our executive officers and other personnel who provide corporate, general and administrative services to our business are, when providing services to us, concurrently employed by Antero Resources and us pursuant to the terms of a services agreement. In addition, our operational personnel are seconded to us by Antero Resources pursuant to the terms of a secondment agreement and individuals are concurrently employed by Antero Resources and us during such secondment. As of December 31, ~~2024~~2025, ~~616~~632 people were concurrently employed by us and Antero Resources pursuant to these arrangements. We and Antero Resources consider our relations with these employees to be generally good.

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Total Rewards

We have demonstrated a history of investing in our workforce by offering competitive salaries, fair living wages and comprehensive benefits. To foster a stronger sense of ownership and align the interests of our personnel with shareholders, we provide long-term incentive programs that include restricted stock units, performance share units and cash awards. Additionally, we offer short-term cash incentive programs, which are discretionary and are based on individual and company performance factors, among others. Furthermore, we offer comprehensive benefits to our full-time employees working 30 hours or more per week. To be an employer of choice and maintain the strength of our workforce, we consistently assess the current business environment and labor market to refine our compensation and benefits programs and other resources available to our personnel. Among other benefits, these include:

● comprehensive health insurance, including vision and dental; we have not increased employee premiums in over 1718 years;

●

employee Health Savings Accounts, including contributions to these accounts by us;

●

401(k) retirement savings plan with discretionary contribution matching opportunities;

●

competitive paid time off and sick leave programs;

●

paid parental leave;

●

student loan repayment matching opportunities; and

●

wellness support benefits including an employee assistance program, short-term and long-term disability coverage and gym membership and/or fitness subscription reimbursement, among others.

Role Based Support

We support our employees’ professional development. To help our personnel succeed in their roles, we emphasize continuous formal and informal training, developmental, and educational opportunities. We also assist employees with the cost of such educational pursuits through our student loan repayment matching program. Additionally, we have a robust performance evaluation program, which includes tools to facilitate goals and career progression.

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Workforce Health and Safety

The safety of our employees is a core tenet of our values, and our safety goal is zero incidents and zero injuries. A strong safety culture reduces risk, enhances productivity and builds a strong reputation in the communities in which we operate. We have earned a reputation as a safe and an environmentally responsible operator through continuous improvement in our safety performance. This makes us more attractive to current and new employees.

We invest in safety training and coaching, promote risk assessments and encourage visible safety leadership. Employees are empowered and expected to stop or refuse to perform a job if it is not safe or cannot be performed safely. We sponsor emergency preparedness programs, conduct regular audits to assess our performance and celebrate our successes through the annual contractor safety conference where we acknowledge employees and contractors alike who have exhibited strong safety leadership during the course of the year. These many efforts combine to create a culture of safety throughout the company and provide a positive influence on our contractor community.

Equal Employment Opportunity and Workplace Culture

We are committed to building a culture where equal employment opportunity and a strong workplace culture are core philosophies across our operations. We prohibit all forms of unlawful discrimination and are committed to making opportunities for development and progress available to all employees so their talents can be fully developed to maximize our and their success. We believe that creating an environment that cultivates a sense of belonging requires encouraging employees to continue to educate themselves about each other’s experiences, and we strive to promote the respect and dignity of all persons. We also believe it is important that we foster education, communication and understanding about diverse backgrounds and perspectives as well as belonging. Finally, in line with these beliefs and our commitment to equal employment opportunity, we expect recruiters operating on our behalf to provide us with a diverse pool of candidates.

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Address, Internet Website and Availability of Public Filings

Our principal executive offices are at 1615 Wynkoop Street, Denver, Colorado 80202. Our telephone number is (303) 357-7310. Our website is located at www.anteromidstream.com.

We file or furnish our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.

We also make available free of charge our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. These documents are located www.anteromidstream.com under the “Investors” link.

Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.

Item 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks described in this Annual Report on Form 10-K could materially and adversely affect our business, financial condition, cash flows and results of operations. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Customer Concentration

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:~~

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Accordingly, we are indirectly subject to the business risks of Antero Resources, including, among others:

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a reduction in or slowing of Antero Resources’ development program, which would directly and adversely impact demand for our gathering and compression services and our water handling services;

● a reduction in or slowing of Antero Resources’ well completions, which would directly and adversely impact demand for our water handling services;

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the volatility of natural gas, NGLs and oil prices, which could have a negative effect on the value of Antero Resources’ properties, its development program and its ability to finance its operations;

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the availability of capital on an economic basis to fund Antero Resources’ exploration and development activities and to service and/or refinance its debt, as well as to fund its capital expenditure programs;

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Antero Resources’ ability to replace its oil and gas reserves;

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Antero Resources’ drilling and operating risks, including potential environmental liabilities;

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transportation and processing capacity constraints and interruptions; and

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adverse effects of governmental and environmental regulation.

Further, we are subject to the risk of non-payment or non-performance by Antero Resources, including with respect to our gathering and compression and water handling services agreements. We cannot predict the extent to which Antero Resources’ business would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on Antero Resources’ ability to execute its drilling and development program or perform under our gathering and compression and water handling services agreements. Low commodity price environments can negatively impact natural gas producers and cause the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer, including Antero Resources, is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by Antero Resources could adversely affect our business and operating results.

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have on Antero Resources’ ability to execute its drilling and development program or perform under our gathering and compression and water handling services agreements. Low commodity price environments can negatively impact natural gas producers and cause the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer, including Antero Resources, is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by Antero Resources could adversely affect our business and operating results.

Also, due to our relationship with Antero Resources, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to Antero Resources’ financial condition or adverse changes in its credit ratings.

Any material limitation of our ability to access capital could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Antero Resources could negatively impact our share price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

See Item 1A, “Risk Factors” in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, ~~2024~~2025 (which is not, and shall not be deemed to be, incorporated by reference herein) for a full disclosure of the risks associated with Antero Resources’ business.

The natural gas volumes that support our gathering business depend on the level of production from wells connected to our systems, which may be less than expected and will naturally decline over time. To the extent Antero Resources reduces its development activity or otherwise ceases to drill and complete new wells, revenues for our gathering and compression and water handling services will be directly and adversely affected. Our ability to maintain water handling services revenues is substantially dependent on continued completion activity by Antero Resources or third parties over time, as well as the volumes of water used in and produced from such activity. In addition, natural gas volumes from completed wells will naturally decline and our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas from Antero Resources or third parties. The primary factors affecting our ability to obtain additional sources of natural gas include (i) the success of Antero Resources’ drilling activity in our areas of operation, (ii) Antero Resources’ ability to replace declining production, (iii) Antero Resources’ acquisition of additional acreage, including acquisitions that offset any dispositions by Antero Resources and (iv) our ability to obtain dedications of acreage from third parties. Demand for our fresh water delivery services, which make up a substantial portion of our water handling services revenues, is dependent on water used in Antero Resources’ completion activities. To the extent that Antero Resources or other fresh water delivery customers reduce the number of completion stages per well or use less water in their completions, the demand for our fresh water delivery services would be reduced.

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sources of natural gas include (i) the success of Antero Resources’ drilling activity in our areas of operation, (ii) Antero Resources’ ability to replace declining production, (iii) Antero Resources’ acquisition of additional acreage, including acquisitions that offset any dispositions by Antero Resources and (iv) our ability to obtain dedications of acreage from third parties. Demand for our fresh water delivery services, which make up a substantial portion of our water handling services revenues, is dependent on water used in Antero Resources’ completion activities. To the extent that Antero Resources or other fresh water delivery customers reduce the number of completion stages per well or use less water in their completions, the demand for our fresh water delivery services would be reduced.

We have no control over Antero Resources’ or other producers’ levels of development and completion activity in our areas of operation, the amount of oil and gas reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, our water handling business is dependent upon active development in our areas of operation. To maintain or increase throughput levels on our water handling systems, we must service new wells. We have no control over Antero Resources or other producers or their development plan decisions, which are affected by, among other things:

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the availability and cost of capital;

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prevailing and projected natural gas, NGLs and oil prices;

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demand for natural gas, NGLs and oil;

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quantities of reserves;

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geologic considerations;

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environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

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the costs of producing the gas and the availability and costs of drilling rigs and other equipment.

The first of month prices for NYMEX Henry Hub natural gas ranged from a high of $3.43 per MMBtu to a low of $1.58 per MMBtu in 2024, and the calendar month average prices for NYMEX West Texas Intermediate crude oil ranged from a high of $84.39 per barrel to a low of $69.37 per barrel during the same period. Natural gas prices were substantially lower in 2024 than they were in 2023, while oil prices were relatively consistent in 2024 and 2023. 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 (59% of equivalent proved reserves), changes in natural gas prices have 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.

The first of month prices for NYMEX Henry Hub natural gas ranged from a high of $4.42 per MMBtu to a low of $2.84 per MMBtu in 2025, and the calendar month average prices for NYMEX West Texas Intermediate crude oil ranged from a high of $75.10 per barrel to a low of $57.87 per barrel during the same period. Natural gas prices were substantially higher in 2025 than they were in 2024, while oil prices decreased substantially in 2025 as 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 (61% and 38% of equivalent proved reserves, 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.

The industry shift towards maintenance capital development programs compelled most natural gas and oil producers, including Antero Resources, to reduce the level of exploration, drilling and production activity and capital budgets compared to prior years. This shift had a significant effect on our capital resources, liquidity and expected operating results. Natural gas and oil prices directly affect Antero Resources’ production. If prices decrease from current levels, our revenues, cash flows and results of operations could continue to be adversely affected. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services and cash flows.

Due to these and other factors, even if reserves are known to exist in areas served by our assets, producers have chosen and may choose in the future, not to develop those reserves. Reductions in development activity, including Antero Resources’ reduction in lateral lengths or use of water in its completions, could result in our inability to maintain the current levels of throughput on our systems or reduce the demand for our water handling services on a per well basis, which could in turn reduce our revenue and cash flows and adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of our common stock.

Finally, the 2019 gathering and compression agreement, Marcellus gathering and compression agreement, water services agreement and right-of-first-offer agreement between us and Antero Resources permits Antero Resources to sell, transfer, convey, assign, grant or otherwise dispose of dedicated properties free of the dedication under such agreements, provided that the number of net acres of dedicated properties so disposed of, when added to the number of net acres of dedicated properties previously disposed of free of the dedication since the respective effective dates of the agreements, does not exceed the aggregate number of net acres of dedicated properties acquired by Antero Resources since such effective dates. Accordingly, under certain circumstances, Antero Resources may dispose of a significant number of net acres of dedicated properties free from dedication without our consent, and we have no control over the timing or extent of such dispositions. Any such dispositions could adversely affect our business and operating results. Even if the disposed property remains dedicated to us, the goals and intention of the acquiror with respect to such property may differ significantly from those of Antero Resources. For example, a subsequent owner of a property could choose to invest less capital in the development of such property or to otherwise drill fewer wells than Antero Resources. There can be no assurance that a subsequent owner of dedicated properties would choose to, or be able to, grow or maintain current rates of production from the properties, which could adversely impact us.

~~Business Operations~~16

A material shut-in of production by Antero Resources or any of our other customers could adversely affect our business.

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~~production~~net ~~due~~acres toof ~~storage~~dedicated ~~capacity~~properties ~~constraints~~so disposed of, itwhen ~~may~~added doto sothe innumber of net acres of dedicated properties previously disposed of free of the ~~future. Production~~dedication ~~curtailments~~since orthe ~~shut-ins~~respective byeffective ~~our~~dates ~~producer~~of ~~customers~~the ~~will~~agreements, ~~reduce~~does ~~volumes~~not ~~flowing~~exceed ~~through~~the ~~our~~aggregate ~~gathering~~number ~~and~~of ~~processing~~net ~~system~~acres of dedicated properties acquired by Antero Resources since such effective dates. InAccordingly, ~~addition~~under certain circumstances, ifAntero ~~our~~Resources ~~customers~~may ~~delay~~dispose orof ~~discontinue~~a ~~drilling~~significant ornumber ~~completion~~of ~~activities,~~net itacres ~~will~~of ~~reduce~~dedicated ~~the~~properties ~~volumes~~free offrom ~~water~~dedication ~~that~~without our consent, and we ~~handle. A~~have ~~material~~no ~~reduction~~control inover ~~volumes~~the ontiming ~~our~~or ~~systems~~extent of such dispositions. Any such dispositions could adversely affect our business and operating results. Even if the disposed property remains dedicated to us, ~~revenue~~the goals and ~~cash~~intention ~~flows~~of ~~and~~the ~~could~~acquiror ~~adversely~~with ~~affect~~respect ~~our~~to ~~ability~~such property may differ significantly from those of Antero Resources. For example, a subsequent owner of a property could choose to ~~return~~invest less capital toin ~~our~~the ~~stockholders~~development ~~through~~of ~~dividends~~such ~~and/~~property or ~~repurchases~~to otherwise drill fewer wells than Antero Resources. There can be no assurance that a subsequent owner of ~~shares~~dedicated properties would choose to, or be able to, grow or maintain current rates of AMproduction ~~common~~from ~~stock~~the properties, which could adversely impact us.

Business Operations

A material shut-in of production by Antero Resources or any of our other customers could adversely affect our business.

The marketing of the natural gas, NGLs and oil of our producer customers is substantially dependent upon the existence of adequate markets for their products. Imbalances between the supply of and demand for these products could cause extreme market volatility and a substantial adverse effect on commodity prices. For example, in response to the coronavirus pandemic, governments tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which caused a significant decrease in the demand for oil, natural gas and NGLs. Also, a supply and demand imbalance for oil, natural gas and NGLs in the future could result in storage capacity constraints. During times of supply and demand imbalance, if Antero Resources or any of our other customers are unable to sell their production or enter into additional storage arrangements on commercially reasonable terms or at all, they may be forced to temporarily shut-in a portion of their production or delay or discontinue drilling and completion plans and commercial production. Although Antero Resources has not been required to temporarily shut-in a portion of its production due to storage capacity constraints, it may do so in the future. Production curtailments or shut-ins by our producer customers will reduce volumes flowing through our gathering and processing system. In addition, if our customers delay or discontinue drilling or completion activities, it will reduce the volumes of water that we handle. A material reduction in volumes on our systems could adversely affect our business, revenue and cash flows and could adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of AM common stock.

Our gathering and compression agreements include minimum volume commitments only under certain circumstances.

Our gathering and compression agreements include minimum volume commitments only on new high pressure pipelines and/or compressor stations, as applicable, constructed at Antero Resources’ request. There are no minimum volume commitments on the low pressure pipelines or fresh water delivery pipelines. Any decrease in the current levels of throughput on our gathering, compression and fresh water delivery systems could reduce our revenue and cash flows.

The construction of additions or modifications to our existing systems and the construction or purchase of new assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all, or they may not operate as designed or at the expected levels. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. In addition, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering and compression, water handling or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our financial condition and results of operations. Furthermore, adding to our existing assets may require us to obtain new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new natural gas supplies to our existing gathering pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

The construction of gathering pipelines, compressor stations, processing and fractionation facilities and water handling assets is subject to construction cost overruns due to costs and availability of equipment and materials such as steel. If third party providers of steel products essential to our capital improvements and additions are unable to obtain raw materials, including steel, at historical prices, they may raise the price we pay for such products. On March 8, 2018, the President of the United States issued two proclamations directing the imposition of ad valorem tariffs of 25% on certain imported steel products and 10% on certain imported aluminum products from most countries, with limited exceptions. On May 31, 2018, the U.S. announced that it would also impose steel and aluminum tariffs on Canada, Mexico and the 28 member countries of the European Union. Argentina, Australia, Brazil and South Korea implemented measures to address the impairment to U.S. national security attributable to steel and/or aluminum imports that were deemed satisfactory to the United States. On May 19, 2019, the U.S. announced that Canada and Mexico had also implemented satisfactory measures to address the threatened impairment to U.S. national security caused by steel and aluminum imports from those countries. As a result, imports of steel from Argentina, Australia, Brazil, Canada, Mexico and South Korea and aluminum from Argentina, Australia, Canada and Mexico have been exempted from the imposition of tariff-based remedies, but the United States has implemented quantitative restrictions in the form of absolute quotas for steel article imports from Argentina, Brazil and South Korea and aluminum products from Argentina, meaning that imports in excess of the allotted quota will be disallowed. In addition, effective August 13, 2018, the United States announced that it would impose a 50% ad valorem tariff on steel articles imported from Turkey, which remained in effect until May 21, 2019, at which time a 25% ad valorem tariff on steel articles imported from Turkey was reimposed, consistent with the tariff on imports from most countries. On January 24, 2020, the United States announced that an additional 25% ad valorem tariff would be imposed on certain derivative steel article imports from all countries except Argentina, Australia, Brazil, Canada, Mexico and South Korea, and that an additional 10% ad valorem tariff would be imposed on certain derivative aluminum article imports from all countries except Argentina, Australia, Canada and Mexico. On August 6, 2020, the U.S. re-imposed the 10% ad valorem tariff on imports of non-alloyed unwrought aluminum from Canada due to a surge in imports of those articles, but on October 27, 2020, retroactively reinstated Canada on the list of countries excluded from tariffs for

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~~those~~Recent ~~articles. On~~action ~~August~~and ~~28, 2020,~~ the ~~U.S.~~possibility ~~announced that it would lower one~~ of ~~the~~future ~~quantitative~~action ~~limitations~~ on ~~imports~~trade ofby ~~certain steel articles from Brazil for the remainder of 2020. The~~ U.S. provided relief from these limitations in specific circumstances, namely for production activities with contracts for steel imports from Brazil during the fourth quarter of 2020 entered into before August 28, 2020 that met other specified criteria. In 2020, the U.S. and ~~Mexico~~foreign ~~also~~governments ~~engaged~~has inincreased ~~discussions regarding steel imports pursuant to their Joint Statement of May 17, 2019. On August 31, 2020,~~ the ~~Office~~costs of the U.S. Trade Representative announced that Mexico would establish a strict monitoring regime of exports of standard pipe, mechanical tubing and semi-finished steel products to the U.S. through June 1, 2021. The U.S. agreed to continue to exempt Mexico from duty on these imports. On November 5, 2020, the Office of the U.S. Trade Representative announced that Mexico agreed to establish a strict monitoring regime for exports of certain ~~grain-oriented~~equipment ~~electrical steel (“GOES”)-containing products into the U.S.,~~ and the U.S. agreed that Mexico would not be subject to any adjustments of imports of electrical transformers or related parts. In addition, the U.S.-Mexico-Canada Free Trade Agreement (“USMCA”) became effective on July 1, 2020. The USMCA includes agreements related to steel and aluminum imports, including changes to rules-of-origin requirements for steel and aluminum materials originating in North America, rules for determining whether goods containing materials from non-USMCA countries are considered “North American” under the Harmonized Tariff Schedule, and tariff exemptions for certain automotive imports. Following these proclamations, domestic prices for steel rose. Price increases for materials used in the construction of our assets ~~may~~and ~~result~~has increated ~~increased~~uncertainty ~~costs~~in ~~associated~~global ~~with the continued build-out of our assets~~markets, aswhich ~~well~~may asadversely ~~projects~~affect ~~under development. Because we generate substantially all of~~ our ~~revenue under agreements with Antero Resources that provide for fixed fee structures, we will generally be unable to pass these cost increases along to our customers, and our~~ income from operations and cash flows ~~may be adversely affected~~.

Price increases for materials used in the construction of our assets, including as a result of tariffs, supply chain disruptions, or inflation of prices for commodities, materials, products and shipping, may result in increased costs associated with the continued build-out of our assets, as well as projects under development. Because we generate substantially all of our revenue under agreements with Antero Resources that provide for fixed fee structures, we will generally be unable to pass these cost increases along to our customers, and our income from operations and cash flows may be adversely affected.

Our gathering and compression assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, compressor stations and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. If any such increase in costs occurs or if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, our operating margin and cash flows could be adversely affected.

Our exposure to commodity price risk may change over time.

We currently generate all of our revenues pursuant to fee-based contracts under which we are paid based on the volumes of natural gas that we gather, process and compress and water that we handle and treat, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to negotiate such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of natural gas, NGLs and oil prices, especially in light of the recent declines, could have a material adverse effect on our business, financial condition and results of operations.

As the rate of inflation has increased in the U.S., the cost of the goods and services and labor we use in our operations has also increased, increasing our operating costs. Our costs may increase at a rate greater than the fees we charge to our customers. Furthermore, Antero Resources and our other customers may not renew their contracts with us, or may from time to time seek to renegotiate with us the amount and/or the structure of fees we charge. Additionally, some of our customers’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are curtailed or cut-off due to events beyond our control, and in some cases, certain of those agreements may be terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of fees is insufficient to cover increased costs, our customers do not renew or extend their contracts with us, or our customers suspend or terminate their contracts with us, our financial results would suffer.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water.

Our business includes fresh water delivery for use in our customers’ natural gas, NGLs and oil exploration and production activities. Water is an essential component of natural gas, NGLs and oil production during the drilling, and in particular, the hydraulic fracturing process. We derive a significant portion of our revenues from providing fresh water to Antero Resources. Antero Resources implemented efficiency improvements and water initiatives during 2020, which reduced the amount of fresh water needed to complete their operations. Furthermore, the availability of water supply for our operations may be limited due to, among other things, prolonged drought or state and local governmental authorities restricting the use of water for hydraulic fracturing. The availability of water may also change over time in ways that we cannot control, including as a result of climate related effects such as

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Resources implemented efficiency improvements and water initiatives during 2020, which reduced the amount of fresh water needed to complete their operations. Furthermore, the availability of water supply for our operations may be limited due to, among other things, prolonged drought or state and local governmental authorities restricting the use of water for hydraulic fracturing. The availability of water may also change over time in ways that we cannot control, including as a result of climate related effects such as shifting meteorological and hydrological patterns. Any decrease in the demand for water handling services, or the water supply we need to provide such services, would adversely affect our business and results of operations.

~~ESG~~Sustainability 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 ~~ESG~~sustainability 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~~While ~~while~~ 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 ~~ESG~~sustainability 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~~sustainability-related disclosure is also ~~emerging~~evolving 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 ~~ESG~~sustainability matters. ~~Additionally~~In addition, while we may ~~also~~ announce various voluntary ~~ESG~~sustainability targets, including ~~our~~certain ~~goals~~GHG ~~to achieve a 100% reduction in pipeline~~ 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 ~~ESG~~sustainability impact instead of actual changes in our ~~ESG~~sustainability 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 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, ~~are~~have ~~instituting~~instituted 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 ~~ESG~~sustainability profile or transparency of our operations, we cannot guarantee that such participation or certification will have the intended results on our ~~ESG~~sustainability profile. Also, despite these aspirational goals, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ~~ESG~~sustainability-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~~sustainability 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 ~~ESG~~sustainability matters are becoming increasingly subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ~~ESG~~sustainability benefits. AsAdditionally, acertain ~~result,~~employment wepractices ~~may~~and ~~face~~social ~~increased~~initiatives ~~litigation~~are ~~risks~~the ~~from~~subject ~~private~~of ~~parties~~scrutiny ~~and~~by ~~governmental~~both ~~authorities~~those ~~related~~calling toof ~~our~~the ~~ESG~~continued ~~efforts. Moreover~~advancement of such policies, ~~any~~as ~~alleged~~well ~~claims~~as ofthose ~~greenwashing~~who ~~against~~believe usthey orshould ~~others~~be incurbed, ~~our~~including ~~industry~~government ~~may~~actors, ~~lead~~and tothe ~~negative~~complex ~~sentiment~~regulatory ~~towards~~and ~~our~~legal ~~company~~frameworks orapplicable ~~industry~~to such initiatives continue to evolve. ToWe ~~the~~cannot ~~extent~~be ~~that~~certain of the ~~Company~~impact isof ~~unable~~such toregulatory, ~~respond~~legal ~~timely~~ and ~~appropriately~~other todevelopments ~~any~~on ~~negative~~our ~~publicity,~~business. More ~~our~~recent ~~reputation~~political developments could bemean ~~harmed~~that we face increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. ~~Damage~~Such tosentiment may focus on our ~~overall~~environmental ~~reputation~~commitments ~~could~~or ~~have~~our apursuit ~~negative~~of ~~impact~~certain onemployment ~~our~~practices ~~financial~~or ~~results~~social ~~and~~initiatives ~~require~~that ~~additional~~are ~~resources~~alleged ~~for~~to ~~the~~be ~~Company~~political or polarizing in nature or are alleged to ~~rebuild~~violate ~~its~~laws ~~reputation.~~based, in part, on changing

2019

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Inpriorities ~~addition~~of, ~~organizations~~or ~~that~~interpretations ~~provide~~by, ~~information~~federal toagencies ~~investors~~or onstate ~~corporate~~governments. Consideration ~~governance~~of sustainability and social-related ~~matters~~factors ~~have~~in ~~developed~~our ~~ratings~~decision ~~processes~~making ~~for~~could ~~evaluating companies on their approach to ESG matters. Such ratings may~~ be ~~used~~subject ~~by some investors~~ to ~~inform~~increasing ~~their~~scrutiny ~~investment~~ and ~~voting~~objection ~~decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away~~ from ~~companies~~such ~~with energy~~anti-~~related~~ESG ~~assets~~parties. As ~~could~~a ~~lead~~result, towe ~~increased~~may ~~negative~~face ~~investor~~increased ~~sentiment~~litigation ~~toward~~risks ~~us,~~from ~~Antero~~private ~~Resources~~parties and ~~our~~governmental ~~industry~~authorities ~~and~~related to ~~the~~our ~~diversion~~sustainability ~~of investment to other industries~~efforts. Moreover, ~~which~~any ~~could~~alleged ~~have~~claims aof ~~negative~~greenwashing ~~impact~~against onus ~~our~~or ~~stock~~others ~~price~~in ~~and~~ our ~~access~~industry ~~to and costs of capital. Also, certain institutional lenders~~ may ~~decide~~lead ~~not~~ to ~~provide~~negative ~~funding~~sentiment ~~for~~towards ~~oil~~our ~~and~~company ~~natural gas companies~~ or industry. To the ~~corresponding~~extent ~~infrastructure~~that ~~projects~~the ~~based~~Company onis ~~climate~~unable ~~related~~to ~~concerns,~~respond ~~which~~timely ~~could~~and ~~affect~~appropriately ~~our access~~ to ~~capital~~any ~~for~~negative ~~potential growth projects. Moreover~~publicity, ~~to the extent ESG matters negatively impact~~ our reputation, wecould ~~may not~~ be ~~able~~harmed. Damage to ~~compete~~our asoverall ~~effectively~~reputation orcould ~~recruit~~have ora ~~retain~~negative ~~employees,~~impact ~~which~~on ~~may adversely affect~~ our ~~operations. Such~~financial ~~ESG~~results ~~matters may also impact Antero Resources~~ and ~~our~~require ~~customers,~~additional ~~which~~resources ~~may~~for ~~adversely~~the ~~impact~~Company ~~our~~to ~~business,~~rebuild ~~financial~~its ~~condition or results of operations~~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 sustainability matters. Such ratings, proxy advisory services, and reports may be used by some investors to inform their investment and voting decisions. While such 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 sustainability 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 sustainability matters may also impact Antero Resources and our customers, which may adversely impact our business, financial condition or results of operations.

Our operations are subject to all of the hazards associated with the processing, gathering and compression of natural gas, NGLs and oil and water handling services, including:

●

unintended breach of impoundment and downstream flooding, release of invasive species or aquatic pathogens, hazardous spills near intake points, trucking collision, vandalism, excessive road damage or bridge collapse and unauthorized access or use of automation controls;

●

damage to pipelines, compressor stations, pumping stations, blending facilities, impoundments, related equipment and surrounding properties caused by natural disasters, acts of terrorism and acts of third parties;

●

damage from construction, farm and utility equipment as well as other subsurface activity (for example, mine subsidence);

●

leaks of natural gas, NGLs or oil or losses of natural gas, NGLs or oil as a result of the malfunction of equipment or facilities;

●

fires, ruptures and explosions;

●

other hazards that could also result in personal injury and loss of life, pollution of the environment, including natural resources and suspension of operations; and

●

hazards experienced by other operators that may affect our operations by instigating increased regulations and oversight.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

●

injury or loss of life;

●

damage to and destruction of property, natural resources and equipment;

●

pollution and other environmental damage;

●

regulatory investigations and penalties;

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●

suspension of our operations; and

●

repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable under policies we are covered under, and we have obtained pollution insurance. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

21An impairment of our assets, including property and equipment and/or intangible assets could reduce our earnings.

GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets, including property and equipment and/or intangible assets. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings. During the year ended December 31, 2025, we reduced the carrying value of the Utica Shale Property and Equipment to the estimated selling price less costs to sell and recorded a loss on long-lived assets of $87 million in our consolidated statements of operations and comprehensive income.

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We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

Because we do not own all of the land on which our pipelines and facilities have been constructed, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations.

World health events may materially adversely affect our business.

World health events may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. While it is not possible to predict their extent or durations, these disruptions may have a material adverse effect on our business, financial condition and results of operations and could adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of AM common stock.

Further, adverse impacts on Antero Resources’ business resulting from world health events may also adversely affect our business and results of operations. The effects of a pandemic, epidemic or outbreak of an infectious disease and concerns regarding its global spread could negatively impact global demand for crude oil and natural gas, which may contribute to price volatility that could impact the price Antero Resources’ receives for its natural gas, NGLs and oil and materially and adversely affect the demand for and marketability of Antero Resources’ production, as well as lead to temporary curtailment or shut-ins of production due to lack of downstream demand or storage capacity. For further discussion of the business risks of Antero Resources that may impact us, see “—Customer Concentration—Because substantially all of our revenue is currently derived from Antero Resources, any development that materially and adversely affects Antero Resources’ operations, financial condition or market reputation could have a material and adverse impact on us.”

Terrorist attacks, cyberattacks and threats could have a material adverse effect on our business, financial condition and results of operations.

Terrorist attacks or cyberattacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Cyber incidents, including deliberate attacks, have increased in frequency globally. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the United States. We depend on digital technology in many areas of our business and operations, including, but not limited to, performing many of our gathering and compression and water handling services, processing and recording financial and operating data, oversight and analysis of our operations and communications with the employees supporting our operations and our customers or service providers. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. The growing regulatory landscape around data protection adds additional complexity to safeguarding this information. The secure processing, maintenance and transmission of information is critical to our operations, and we monitor our key information technology systems in an effort to detect and prevent cyberattacks, security breaches or unauthorized access. Despite our security measures, our information technology systems may undergo cyberattacks or security breaches including as a result of employee error, malfeasance or other threat vectors, which could lead to the corruption, loss, or disclosure of proprietary and sensitive data, misdirected wire transfers, and an inability to: perform services for our customers; complete or settle transactions; maintain our books and records; prevent environmental damage; and maintain communications or operations. Significant liability to the Company or third parties may result. We are not able to anticipate, detect or prevent all cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until an attack is already underway or significantly thereafter, and because attackers are increasingly using technologies specifically designed to circumvent cybersecurity measures and avoid detection. Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (e.g., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.

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customers, orsuppliers, ~~other~~investors ~~business~~and ~~partners~~other ~~could~~stakeholders. The ~~propagate~~growing ~~across~~regulatory ~~the~~landscape ~~supply~~around ~~chain,~~data ~~potentially~~protection ~~causing~~adds ~~widespread~~additional ~~operational~~complexity orto ~~financial~~safeguarding ~~disruptions~~this information. ~~Although~~The wesecure ~~have~~processing, ~~written~~maintenance ~~policies~~ and ~~procedures~~transmission ~~for~~of ~~monitoring~~information ~~cybersecurity~~is ~~risk~~critical ~~and~~to ~~identifying~~our ~~and reporting incidents~~operations, ~~there~~and ~~can~~we bemonitor noour ~~guarantee~~key ~~they~~information ~~will~~technology besystems ~~effective~~in atan ~~preventing~~effort ~~cyberattacks~~to ordetect ~~ensuring~~and ~~incidents~~prevent ~~are timely identified or reported. Some cyber incidents~~cyberattacks, ~~such~~security asbreaches ~~surveillance, ransomware,~~ or ~~deepfake-based~~unauthorized ~~social engineering attacks, may remain undetected for some period of time~~access. ~~Advances~~Despite inour ~~computer~~security ~~capabilities~~measures, ~~discoveries~~our ininformation ~~the~~technology ~~field~~systems ofmay ~~artificial~~undergo ~~intelligence,~~cyberattacks ~~cryptography,~~ or ~~other~~security ~~developments~~breaches ~~may~~including ~~result~~as in a ~~compromise~~result ~~or breach~~ of ~~the~~employee ~~technology we use to safeguard confidential~~error, ~~personal~~malfeasance or other ~~information. As~~threat ~~cyberattacks continue to evolve~~vectors, wewhich ~~may~~could belead ~~required~~ to ~~expend~~the ~~significant~~corruption, ~~additional~~loss, ~~resources to continue to modify~~ or ~~enhance~~disclosure ~~our~~of ~~protective~~proprietary ~~measures or to investigate~~ and ~~remediate~~sensitive ~~any~~data, ~~vulnerabilities~~misdirected towire ~~cyberattacks. In particular~~transfers, ~~our implementation of various procedures~~ and ~~controls~~an inability to: ~~monitor~~perform ~~and~~services ~~mitigate~~for ~~security~~our ~~threats~~customers; ~~and~~complete toor ~~increase~~settle ~~security~~transactions; ~~for~~maintain our ~~personnel,~~books ~~information, facilities~~ and ~~infrastructure~~records; ~~may~~prevent ~~result~~environmental indamage; ~~increased~~and ~~capital~~maintain ~~and~~communications ~~operating~~or ~~costs~~operations. ~~While~~Significant weliability ~~maintain cyber insurance coverage~~ to ~~help~~the ~~mitigate~~Company ~~financial~~or ~~risks~~third ~~associated~~parties ~~with~~may ~~cyber~~result. We ~~incidents,~~are ~~such policies have limitations and do~~ not ~~cover~~able ~~all~~to ~~potential losses~~anticipate, ~~such~~detect ~~as reputational harm~~ or ~~regulatory~~prevent ~~fines. Accordingly, our cyber insurance may not provide coverage for~~ all ~~potential risks arising from cyber incidents. As~~ cyberattacks ~~increase globally in frequency and severity~~, ~~coverage~~particularly ~~availability~~because ~~and~~the ~~affordability~~methodologies ~~may~~used ~~further~~by ~~decline. A~~attackers ~~successful~~change ~~cyberattack~~frequently or ~~security~~may ~~breach~~not ~~could~~be ~~result~~recognized inuntil ~~liability~~an ~~resulting~~attack ~~from~~is ~~data~~already ~~privacy~~underway or ~~cybersecurity~~significantly ~~claims~~thereafter, ~~liability~~and ~~under~~because ~~data~~attackers ~~privacy~~are ~~laws,~~increasingly ~~regulatory~~using ~~penalties,~~technologies ~~damage~~specifically designed to ~~our~~circumvent ~~reputation,~~cybersecurity ~~long-lasting~~measures ~~loss~~and ofavoid ~~confidence~~detection. Cybersecurity inattacks ~~us,~~are oralso ~~additional~~becoming ~~costs~~more ~~for~~sophisticated ~~remediation~~ and ~~modification~~include, orbut ~~enhancement~~are ofnot ~~our~~limited ~~information systems~~ to, ~~prevent future occurrences~~ransomware, ~~all~~credential ~~of which could have a material and adverse effect on our business~~stuffing, ~~financial~~spear ~~condition or results of operations. To date~~phishing, wesocial ~~have not experienced any material losses relating to cyberattacks; however~~engineering, ~~there~~use ~~can~~of bedeepfakes ~~no assurance that we will not suffer such losses in the future~~(e. ~~No security measure is infallible~~g. ~~Consequently~~, ithighly isrealistic ~~possible~~synthetic ~~that~~media ~~any~~generated ofby ~~these~~artificial ~~occurrences,~~intelligence) orand aother ~~combination~~attempts ofto ~~them,~~gain ~~could~~unauthorized ~~have~~access ato ~~material~~data ~~adverse~~for ~~effect~~purposes onof ~~our~~extortion ~~business,~~or ~~financial~~other ~~condition and results of operations~~malfeasance.

Our information and operational technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may become the target of cyberattacks or information security breaches that result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or adversely disrupt our business operations. The interconnected nature of our industry heightens the risk that a cybersecurity incident affecting one of our vendors, suppliers, customers or other business partners could propagate across the supply chain, potentially causing widespread operational or financial disruptions. Although we have written policies and procedures for monitoring cybersecurity risk and identifying and reporting incidents, there can be no guarantee they will be effective at preventing cyberattacks or ensuring incidents are timely identified or reported. Some cyber incidents, such as surveillance, ransomware, or deepfake-based social engineering attacks, may remain undetected for some period of time. Advances in computer capabilities, discoveries in the field of artificial intelligence, cryptography, or other developments may result in a compromise or breach of the technology we use to safeguard confidential, personal or other information. As cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. While we maintain cyber insurance coverage to help mitigate financial risks associated with cyber incidents, such policies have limitations and do not cover all potential losses, such as reputational harm or regulatory fines. Accordingly, our cyber insurance may not provide coverage for all potential risks arising from cyber incidents. As cyberattacks increase globally in frequency and severity, coverage availability and affordability may further decline. A successful cyberattack or security breach could result in liability resulting from data privacy or cybersecurity claims, liability under data privacy laws, regulatory penalties, damage to our reputation, long-lasting loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations. To date, we have not experienced any material losses relating to cyberattacks; however, there can be no assurance that we will not suffer such losses in the future. No security measure is infallible. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Capital Structure and Access to Capital

Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including the Credit 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 Credit Facility and our 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 senior notes. Our ability to restructure or refinance our indebtedness will depend on the condition of the credit and capital markets, including the markets for credit facilities and senior unsecured notes, and our financial condition at such time. Any refinancing of our indebtedness, including using borrowings under the Credit Facility to redeem our senior notes, 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 and 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 and result in more onerous restrictions in our debt securities and facilities. 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. The Credit Facility and the indentures governing our senior notes place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. 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.

To increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we may be unable to expand our business operations, which could adversely affect our business and operating results. To fund our expansion capital expenditures and investment capital expenditures, we expect to use cash from our operations or incur borrowings. Alternatively, we may sell additional shares of common stock or other securities to fund our capital expenditures. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our or Antero Resources’ financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. In

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us from adopting some of these alternatives. In addition, ~~incurring~~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 ~~debt~~indebtedness ~~may~~and ~~significantly~~result ~~increase~~in more onerous restrictions in our ~~interest~~debt ~~expense~~securities and ~~financial~~facilities. In ~~leverage~~the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and ~~issuing~~might ~~shares~~be required to dispose of ~~common~~material ~~stock~~assets ~~may~~or ~~result~~operations into ~~significant~~meet ~~stockholder~~our ~~dilution~~debt service and other obligations. ~~Neither~~The ~~Antero~~Credit ~~Resources~~Facility orand ~~any~~the indentures governing our senior notes place certain restrictions on our ability to dispose of ~~its~~assets ~~affiliates~~and isour ~~committed~~use of the proceeds from such dispositions. We may not be able to ~~providing~~consummate those dispositions, and the proceeds of any ~~direct~~such ordisposition ~~indirect~~may ~~support~~not be adequate to ~~fund~~meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our ~~growth~~scheduled debt service obligations.

We may be unable to access the equity or debt capital markets to meet our obligations.

Declines in commodity prices or the financial condition or prospects of Antero Resources may cause the financial markets to exert downward pressure on our stock price and credit capacity. For example, for portions of 2020, the market for senior unsecured notes was unfavorable for high-yield issuers such as us. Our plans for growth may require access to the capital and credit markets. Although the market for high-yield debt securities has improved since 2020, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms or at all, we may be unable to carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Restrictions in our existing and future debt agreements could adversely affect our business, financial condition and results of operations.

The Credit Facility limits our ability to, among other things:

●

permit liens on our properties;

●

make certain investments;

●

merge, consolidate, liquidate or dissolve;

●

dispose of assets;

●

enter into certain types of transactions with affiliates;

●

prepay or amend certain indebtedness; and

●

enter into certain swap and hedging transactions.

The indentures governing our senior notes contains similar restrictive covenants. In addition, the Credit Facility contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratio or test. Additionally, we may not be able to borrow the full amount of commitments under the Credit Facility if doing so would cause us to breach a financial covenant.

The provisions of the Credit Facility and the indentures governing our senior notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the Credit Facility or the indentures governing our senior notes could result in a default or an event of default that would restrict our ability to access loans under our Credit Facility and could enable our lenders or noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If our obligations to repay our debt are accelerated, our assets may be insufficient to repay such debt in full, and you could experience a partial or total loss of your investment. See Note 8—Long-Term Debt to our consolidated financial statements for additional information.

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conditions. In addition, a failure to comply with the provisions of the Credit Facility or the indentures governing our senior notes could result in a default or an event of default that would restrict our ability to access loans under our Credit Facility and could enable our lenders or noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If our obligations to repay our debt are accelerated, our assets may be insufficient to repay such debt in full, and you could experience a partial or total loss of your investment. See Note 9—Long-Term Debt to our consolidated financial statements for additional information.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:

●

our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to our gathering and compression agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

●

our funds available for operations and future business opportunities will be reduced by that portion of our cash flows required to make interest payments on our debt;

●

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

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●

our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing or not paying dividends, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue growth opportunities, reduce cash flow used for our services and place us at a competitive disadvantage. For example, during ~~2024~~2025, we had average outstanding borrowings under the Credit Facility of $~~420~~463 million, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of $45 million and a corresponding decrease in our cash flows and net income before the effects of income taxes. Disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to carry out our business plan.

Geographic Concentration

Our gathering and compression and water handling systems are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.

We rely primarily on revenues generated from our gathering and compression and water handling systems, which are all located in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by, and associated with, governmental regulation, state and local political activities, market limitations, availability of equipment and personnel or interruption of the compression, processing or transportation of natural gas, NGLs or oil.

A shortage of equipment and skilled labor in the Appalachian Basin could reduce equipment availability and labor productivity and increase labor costs, which could have a material adverse effect on our business and results of operations.

Gathering and compression and water handling services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If Antero Resources experiences shortages of skilled labor or there is a lack of necessary equipment in the Appalachian Basin in the future, our allocation of labor costs and overall productivity could be materially and adversely affected. If our allocation of labor prices increase or if Antero Resources experiences materially increased health and benefit costs for employees, our business and results of operations could be materially and adversely affected.

~~Acquisitions and Takeovers~~24

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Acquisitions and Divestitures

We may not achieve the intended benefits of the HG Acquisition, and the HG Acquisition may disrupt our existing plans or operations.

There can be no guarantee that we will be able to successfully integrate the assets and operations to be acquired in, or otherwise realize the expected benefits of, the HG Acquisition. Difficulties in integrating the assets acquired in the HG Acquisition may result in operational and other challenges, including the diversion of management’s attention from ongoing business concerns; the diversion of resources to integration processes; the retention of existing business and operational relationships, including customers, suppliers and other counterparties; the attraction of new business and operational relationships; the possibility of faulty assumptions underlying expectations regarding integration processes and associated expenses; the elimination of duplicative corporate or operational processes; as well as unanticipated issues in integrating certain systems, including internal controls over financial reporting and disclosure controls and procedures. An inability to realize the full extent of the intended benefits of the HG Acquisition, and any delays encountered in the integration process, could have an adverse effect on our revenues and level of expenses and results of operations. In addition, the integration may result in additional or unforeseen expenses. Although we expect the strategic benefits to offset incremental transaction-related costs over time, if we are not able to adequately and effectively address integration challenges, we may be unable to successfully integrate operations or realize anticipated benefits of the integration.

We may not complete the Utica Shale Divestiture within the anticipated timeframe or at all.

The completion of the Utica Shale Divestiture is subject to a number of conditions. The failure to satisfy all of the required conditions could delay the completion of the Utica Shale Divestiture for a significant period of time or prevent it from occurring at all. A delay in completing the Utica Shale Divestiture could cause us to realize some or all of the benefits later than we otherwise expect to realize them if the Utica Shale Divestiture was successfully completed within the anticipated timeframe, which could result in additional transaction costs or in other negative effects associated with uncertainty around completion of the divestiture.

Notwithstanding the due diligence investigation that we performed in connection with our entry into the definitive agreement to purchase HG Midstream, HG Midstream may have liabilities, losses or other exposures for which we do not have adequate insurance coverage or other protection.

While we performed due diligence on HG Midstream prior to our entry into the definitive agreement to purchase HG Midstream, we are dependent on the accuracy and completeness of statements and disclosures made or actions taken by HG Midstream and its representatives when conducting due diligence and evaluating the results of such due diligence. We do not control and may be unaware of activities of HG Midstream prior to the completion of the HG Acquisition, including intellectual property and other litigation, claims or disputes, information security vulnerabilities, violations of laws, policies, rules and regulations, commercial disputes, tax liabilities and other known and unknown liabilities.

With the consummation of the HG Acquisition, the liabilities of HG Midstream, including contingent liabilities, will be consolidated with our liabilities for purposes of financial reporting. HG Midstream may have unknown liabilities which we will be responsible for following the consummation of the HG Acquisition. If HG Midstream’s liabilities are greater than expected, or if there are obligations of HG Midstream of which we are not aware, our business could be materially and adversely affected. We do not have indemnification rights from the current owners of HG Midstream for defects and liabilities associated with the acquired assets and instead will rely on a limited representation and warranty insurance policy, which we have obtained. Such insurance is subject to exclusions, policy limits and certain other customary terms and conditions. If we are responsible for liabilities not covered by representation and warranty insurance, we could suffer consequences that could have a material adverse effect on our financial condition and results of operations.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future, we may acquire businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

In connection with acquisitions, we perform a review of the subject assets that we believe to be generally consistent with industry practices. However, our review will not reveal all existing or potential problems. For example, certain environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we are able to obtain ~~contractual indemnification rights, there is no assurance that the seller will be capable of performing under any indemnification obligation.~~

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~~purchase~~contractual ~~prices~~indemnification ~~significantly~~rights, ~~higher~~there ~~than~~is ~~those~~no ~~paid for earlier acquisitions. No~~ assurance ~~can be given~~ that wethe seller will be ~~able~~capable toof ~~identify~~performing ~~suitable~~under acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to successfully integrate the acquired businesses and assets into our existing operations or to minimize any ~~unforeseen~~indemnification ~~operational difficulties could have a material adverse effect on our business, financial condition and results of operations~~obligation.

The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to successfully integrate the acquired businesses and assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, financial condition and results of operations.

In addition, our agreements governing our debt impose certain limitations on our ability to enter into mergers or combination transactions. The Credit Facility and the indentures governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Certain provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our certificate of incorporation and bylaws:

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provide advance notice procedures with regard to stockholder nominations of candidates for election as directors or other stockholder proposals to be brought before meetings of our stockholders, which may preclude our stockholders from bringing certain matters before our stockholders at an annual or special meeting;

●

provide our Board of Directors (the “Board”) the ability to authorize issuance of preferred stock in one or more classes or series, which makes it possible for our Board to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us and which may have the effect of deterring hostile takeovers or delaying changes in control or management of us;

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provide that the authorized number of directors may be changed only by resolution of our Board;

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provide that, subject to the rights of holders of any series of preferred stock to elect directors or fill vacancies in respect of such directors as specified in the related preferred stock designation and the terms of that certain Stockholders’ Agreement, dated October 9, 2018, by and among Antero Midstream Corporation and certain of its stockholders named thereto (the “Stockholders’ Agreement”), all vacancies, including newly created directorships be filled by the affirmative vote of holders of a majority of directors then in office, even if less than a quorum, or by the sole remaining director, and will not be filled by our stockholders;

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provide that, subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, if any, and the terms of the Stockholders’ Agreement, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of our stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders;

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provide for our Board to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms;

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provide that, subject to the rights of the holders of shares of any series of preferred stock, if any, to remove directors elected by such series of preferred stock pursuant to our certificate of incorporation (including any preferred stock designation thereunder) and the terms of the Stockholders’ Agreement, directors may be removed from office at any time, only for cause and by the holders of a majority of the voting power of all outstanding voting shares entitled to vote generally in the election of directors;

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provide that special meetings of our stockholders may only be called by the Chief Executive Officer, the Chairman of our Board or our Board pursuant to a resolution adopted by a majority of the total number of directors that we would have if there were no vacancies;

● provide that (i) Yorktown Partners LLC (“Yorktown”) and their affiliates are permitted to participate (directly or indirectly) in venture capital and other direct investments in corporations, joint ventures, limited liability companies and other entities conducting business of any kind, nature or description, (ii) Yorktown and their affiliates are permitted to have interests in, participate with, aid and maintain seats on the boards of directors or similar governing bodies of any such investments, in each case that may, are or will be competitive with our business and the business of our subsidiaries or in the same or similar lines of business as us and our subsidiaries, or that could be suitable for us or our subsidiaries

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provide that the provisions of our certificate of incorporation can only be amended or repealed by the affirmative vote of the holders of at least 66 2/3% in voting power of the outstanding shares of our common stock entitled to vote thereon, voting together as a single class; provided, however, that so long as the Stockholders' Agreement remains in effect, no provision of our certificate of incorporation may be amended, altered or repealed in any manner that would be contrary to or inconsistent with the terms of the Stockholders’ Agreement, and no amendment to the Stockholders’ Agreement (regardless of whether such amendment modifies any provision of the Stockholders’ Agreement to which our certificate of incorporation is subject) will be deemed an amendment of our certificate of incorporation; and

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provide that our bylaws can be altered or repealed by (a) our Board or (b) our stockholders upon the affirmative vote of holders of at least 66 2/3% of the voting power of our common stock outstanding and entitled to vote thereon, voting together as a single class. However, so long as the Stockholders’ Agreement remains in effect, our Board may not approve any amendment, alteration or repeal of any provision of our bylaws or the adoption of any new bylaw, that (a) would be contrary to or inconsistent with the terms of the Stockholders’ Agreement or (b) would amend, alter or repeal certain portions of our certificate of incorporation; provided, however, that so long as the Stockholders’ Agreement remains in effect, the parties to the Stockholders' Agreement may amend any provision of the Stockholders’ Agreement, and no amendment to the Stockholders’ Agreement (regardless of whether such amendment modifies any provision of the Stockholders’ Agreement to which the bylaws are subject) will be deemed an amendment of the bylaws for purposes of the amendment provisions of our bylaws.

We have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”), regulating corporate takeovers.

In general, the provisions of Section 203 of the DGCL prohibit a Delaware corporation, including those whose securities are listed for trading on the New York Stock Exchange, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

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prior to such time, the business combination or the transaction which resulted in the stockholder becoming an interested stockholder is approved by our Board;

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upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding certain specified shares); or

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on or after such time the business combination is approved by our Board and authorized at a meeting of stockholders by the holders of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Section 203 of the DGCL permits a Delaware corporation to elect not to be governed by the provisions of Section 203. Pursuant to our certificate of incorporation, we expressly elected not to be governed by Section 203. Accordingly, we are not subject to any anti-takeover effects or protections of Section 203 of the DGCL, although no assurance can be given that we will not elect to be governed by Section 203 of the DGCL pursuant to an amendment to our certificate of incorporation in the future.

Joint Ventures

On February 6, 2017, we entered into the Joint Venture with MarkWest. While we and MarkWest each own a 50% interest in the Joint Venture, MarkWest is the primary operator of the Joint Venture, and we depend on MarkWest for the day-to-day operations of the Joint Venture. Our lack of control over the Joint Venture’s day-to-day operations and the associated costs of operations could result in receiving lower cash distributions from the Joint Venture than currently anticipated. In addition, differences in views among the owners of the Joint Venture could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of the Joint Venture and, in turn, the amount of cash from the Joint Venture operations distributed to us.

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operations could result in receiving lower cash distributions from the Joint Venture than currently anticipated. In addition, differences in views among the owners of the Joint Venture could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of the Joint Venture and, in turn, the amount of cash from the Joint Venture operations distributed to us.

If the Joint Venture is not successful or if the Joint Venture does not perform as expected, our future financial performance may be negatively impacted.

We may be exposed to certain risks in connection with our ownership interest in the Joint Venture, including regulatory, environmental and litigation risks. If such risks or other anticipated or unanticipated liabilities were to materialize, any desired benefits of our entry into the Joint Venture may not be fully realized, if at all, and its future financial performance may be negatively impacted.

In addition, the Joint Venture may result in other difficulties including, among other things:

●

diversion of our management’s attention from other business concerns;

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managing regulatory compliance and corporate governance matters;

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an increase in our indebtedness; and

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potential environmental or other regulatory compliance matters or liabilities and/or title issues, including certain liabilities arising from the operation of the Joint Venture assets prior to the closing of the Joint Venture.

Interruptions in operations at any of the Joint Venture’s facilities may adversely affect its operations and our gathering and processing and water handling operations.

The Joint Venture assets consist of processing plants in West Virginia and a one-third interest in two fractionators in Ohio (the “MarkWest fractionators”). Any significant interruption at these facilities would adversely affect the Joint Venture’s operations. Because a significant portion of Antero Resources’ production is processed by the Joint Venture, any significant interruption at these facilities would also adversely affect our other midstream operations.

We do not operate the MarkWest fractionators, and the operations of the MarkWest’s and Joint Venture’s processing facilities and the MarkWest fractionators could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within its control, such as:

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unscheduled turnarounds or catastrophic events, including damages to facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters;

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restrictions imposed by governmental authorities or court proceedings;

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labor difficulties that result in a work stoppage or slowdown;

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a disruption in the supply of gas to MarkWest’s or the Joint Venture’s processing and fractionation plants and associated facilities;

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disruption in the supply of power, water and other resources necessary to operate MarkWest’s or the Joint Venture’s facilities;

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damage to MarkWest’s or the Joint Venture’s facilities resulting from gas that does not comply with applicable specifications; and

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inadequate fractionation capacity or market access to support production volumes, including lack of availability of rail cars, barges, pipeline capacity or market constraints, including reduced demand or limited markets for certain NGLs.

In addition, MarkWest’s fractionation operations in the Appalachian Basin are integrated, and as a result, it is possible that an interruption of these operations in other regions may impact operations in the regions in which the Joint Venture’s facilities are located.

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Compliance with Regulations

Our operations are subject to complex and stringent federal, state and local laws and regulations. In order 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 in order to maintain compliance with these existing laws and regulations and the permits and other approvals issued thereunder. In addition, our costs of compliance may increase or operational delays may occur if existing laws and regulations are revised or reinterpreted, or if new laws and regulations apply to our operations. 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 and results of operations. Also, we might not be able to obtain or maintain all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.

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, inthere ~~January~~have ~~2023,~~been ~~the~~several ~~White~~recent ~~House’s~~developments ~~Council~~regarding ~~on Environmental Quality (“CEQ”) released guidance to assist federal agencies in assessing~~ the ~~GHG~~NEPA ~~emissions~~regulatory ~~and climate change effects of their proposed actions under NEPA~~regime. InMost ~~May 2024~~recently, ~~the~~following ~~CEQ published~~ a ~~final~~Trump ~~rule~~administration ~~which~~Executive Order, in ~~the~~February ~~second and final “phase” of updates~~2025, ~~revised~~ the ~~implementing~~White ~~regulations~~House’s ofCouncil ~~procedural~~on ~~provisions~~Environmental ofQuality ~~NEPA~~(“CEQ”) ~~and~~released ~~implements~~an ~~NEPA~~interim ~~amendments included in the Financial Responsibility Act of 2023. The~~ final rule ~~was~~rescinding ~~challenged~~its byregulations ~~various~~implementing ~~states~~NEPA. InFederal ~~the~~agencies ~~U.S.~~have ~~District~~begun ~~Court for~~ the ~~District~~process of ~~North~~preparing ~~Dakota~~their inown ~~February~~new ~~2025,~~or ~~the~~updated ~~court~~NEPA-implementing ~~issued~~rules anor ~~order~~guidelines, ~~vacating~~with the ~~May~~first ~~2024~~batch ~~rule~~of ~~citing~~updates areleased ~~November~~in ~~2024~~July ~~opinion of the U~~2025.S. In ~~Court~~May of2025, ~~Appeals for~~ the ~~D.C.~~Supreme ~~Circuit,~~Court ~~which~~issued ~~held~~its ~~that~~opinion ~~the~~in ~~CEQ~~Seven ~~lacks~~County ~~authority~~Infrastructure toCoalition ~~issue NEPA regulations~~v. As aEagle ~~result~~County, ofemphasizing ~~these rulings and~~ the ~~recent~~“substantial ~~change~~judicial indeference” ~~presidential~~that ~~administration,~~courts ~~there~~must isgrant ~~significant~~agencies ~~uncertainty~~when ~~with~~considering ~~respect to current and future~~ NEPA ~~regulations~~challenges. ~~For example~~And, onin ~~January 20,~~September 2025, ~~President~~CEQ ~~Trump~~ issued annew ~~Executive~~guidance ~~Order~~to ~~directing~~federal ~~the~~agencies ~~CEQ~~implementing NEPA encouraging them to ~~issue~~limit ~~guidance~~their ~~and~~NEPA ~~propose~~reviews, ~~rescinding~~rely ~~existing~~more ~~NEPA~~heavily ~~regulations~~on tosponsor-prepared ~~“expedite~~documents, and ~~simplify~~streamline the ~~permitting~~NEPA process.” ~~While~~The ~~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. ~~Most~~In ~~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 ~~operative~~EPA and the Corps proposed a rule to further update and narrow this September 2023 definition of WOTUS, ~~varies~~guided by ~~state~~the Sackett v. EPA decision. To the extent any judicial ruling, administrative rulemaking, or other action further ~~expands~~changes 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.

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Our gathering and transportation operations are exempt from regulation by the FERC, under the NGA. Section 1(b) of the NGA, exempts natural gas gathering facilities from regulation by the FERC under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, could adversely affect our financial condition, cash flows and results of operations.

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale.

Moreover, FERC regulations indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and market center promotion, indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our financial condition, cash flows and results of operations. The FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1,584,648 per day for each violation and disgorgement of profits associated with any violation.

For more information regarding federal and state regulation of our operations, see “Business—Regulation of Operations.”

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 addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act 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, both West Virginia and Ohio have adopted requirements governing well pad construction, as well as requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drilling 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.

We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal, state or local level, that could lead to delays, increased operating costs and process prohibitions that could reduce the amount of natural gas that moves through our gathering and processing systems or reduce the number of wells drilled and completed that require fresh water for hydraulic fracturing activities, which in turn could materially and adversely affect our revenues and results of operations.

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hydraulic fracturing activities, which in turn could materially and adversely affect our revenues and results of operations.

We or any third-party customers may incur significant liability under, or costs and expenditures to comply with, environmental and occupational health and workplace safety regulations, which are complex and subject to frequent change.

As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state, provincial and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose various obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability. While the Trump administration may make changes to President Biden’s environmental and climate change initiatives, we cannot predict what, when or how the new 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.

Our operations also pose risks of environmental liability due to potential leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations is expected to continue, which may result in increased costs of doing business and consequently affecting profitability. See “Business—Regulation of Environmental and Occupational Safety and Health Matters” for more information.

The Inflation Reduction Act could adversely impact demand for oil and gas and could impose new costs on our operations and those of our customers.

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 ~~imposes~~imposed 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 ~~amends~~amended 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 ~~methane~~EPA ~~emissions~~finalized ~~charge~~a ~~would~~rule ~~start~~implementing inthis ~~calendar~~charge ~~year~~in November 2024; ~~at $900 per ton of methane~~however, ~~increase to $1,200~~ in February 2025, ~~and~~Congress berepealed ~~set~~the atrule ~~$1,500~~under ~~for~~the ~~2026~~Congressional ~~and~~Review ~~each year after~~Act. ~~Calculation~~Additionally, ofunder the ~~fee~~OBBB, isCongress ~~based~~delayed onthe ~~certain~~implementation ~~thresholds~~of ~~established~~the inmethane ~~the~~emissions ~~IRA~~charge ~~2022~~until 2034. ~~The~~Compliance with the methane emissions charge and ~~the~~other ~~incentives~~air ~~for~~pollution ~~renewable~~control ~~energy~~and ~~infrastructure~~permitting ~~development~~requirements could impose additional costs on our operations and reduce demand for oil and natural gas. ~~This~~Consequently, this could ~~decrease demand for oil and gas and consequently,~~ adversely affect our business and results of operations and those of our customers. ~~The~~We ~~Trump administration may seek to challenge, repeal, or revise this rule; however we~~ cannot predict what, when, or how the ~~new~~Trump administration ~~make~~or 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.

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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 the EPA has proposed to delay GHG reporting for the oil and gas sector until 2034, ~~existing~~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 ~~has~~have ~~already~~been ~~become~~ 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~~actions ~~Orders~~ 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. ~~Under~~However, ~~the~~in ~~final~~March ~~rules~~2025, ~~states~~the ~~have~~EPA ~~two~~announced ~~years to prepare and submit their~~ plans to ~~impose~~reconsider ~~methane~~OOOOb ~~emission~~and ~~controls~~OOOOc, onin ~~existing~~line ~~sources. The~~with ~~presumptive standards established under~~ the ~~final~~Trump ~~rule~~administration’s ~~are~~deregulatory ~~generally the same for both new and existing sources~~agenda. ~~The~~Additionally, ~~requirements~~in ~~include~~November ~~enhanced~~2025, ~~leak~~the ~~detection~~EPA ~~survey~~finalized ~~requirements~~an ~~using~~interim ~~optical~~rule ~~gas~~extending ~~imaging and other advanced monitoring to encourage~~ the ~~deployment~~compliance ofdeadlines ~~innovative~~for ~~technologies~~certain toprovisions ~~detect~~provided ~~and~~in ~~reduce~~OOOOb ~~methane emissions, reduction of emissions by 95% through capture~~ and ~~control systems and zero-emission requirements for certain devices~~OOOOc. ~~The~~Litigation ~~rule~~challenging ~~also~~the ~~establishes a “super emitter” response program that would allow third parties to make reports to~~ EPA’s offinal ~~large~~interim ~~methane~~rule ~~emission~~extending ~~events,~~such ~~triggering~~compliance ~~certain~~deadlines ~~investigation~~for ~~and~~new ~~repair requirements. Fines~~ and ~~penalties~~existing ~~for~~oil ~~violations of these rules can be substantial. These rules are currently subject to legal challenges,~~ and wegas ~~cannot~~sources ~~predict~~remains ~~the final outcome~~pending. ~~However,~~We ~~the OOOOb rules are currently in effect. The Trump administration may seek to revise or repeal these rules; however, we~~ cannot predict what additional actions the ~~new~~Trump administration may take, ~~if at all,~~ or ~~on what timelines, or~~ how they may affect our business operations. ~~Moreover~~However, 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, 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.

Internationally, the Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years beginning 2020. President Biden recommitted the United States to the Paris Agreement in February 2021 and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. However, on January 20, 2025, President Trump signed an Executive Order once again withdrawing the United States from the Paris Agreement. The United States’ participation in future United Nations climate-related conferences and the impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement or other international conventions cannot be predicted at this time.

Increasingly, oil and natural gas companies are also exposed to litigation risks related to climate risks. While we are not currently party to any such litigation, we could be named in future actions making similar claims of liability and, depending on the nature of the claims asserted and other factors, such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.

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, 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.

In addition, in October 2023, some states have adopted or are considering adopting laws requiring the disclosure of climate-related risks. Lawsuits have been filed challenging the implementation of one of these laws, but we cannot predict the outcome of these suits at this time. Compliance with these laws, to the extent implemented and applicable to us, may result in additional costs

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~~Additionally,~~related ~~companies in the oil and natural gas industry may be exposed~~ to ~~increasing~~disclosure ~~financial~~requirements ~~risks. Financial~~as ~~institutions,~~well ~~including~~as ~~investment~~increased ~~advisors~~costs ~~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~~restrictions ~~gas~~on ~~related~~access ~~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~~capital. ~~To the extent implemented or pursued~~Separately, ~~such~~enhanced ~~policies~~climate ~~and~~related ~~commitments~~disclosure requirements could lead to ~~some~~reputational ~~lenders restricting access to capital for~~ or ~~divesting~~other ~~from~~harm ~~certain industries or companies, including the oil~~ and ~~natural~~could ~~gas~~also ~~sector,~~increase orour ~~requiring~~litigation ~~that~~risks ~~borrowers~~relating ~~take additional steps~~ to ~~reduce~~statements ~~their~~alleged ~~GHG emissions. There is also a risk that financial institutions will be required~~ to ~~adopt policies that~~ have ~~the~~been ~~effect~~made ofby ~~reducing~~us ~~the~~or ~~funding~~others ~~provided~~in toour ~~the oil and natural gas~~ industry~~. While~~ weregarding ~~cannot~~climate ~~predict~~risks, ~~how~~ or toin ~~what~~connection ~~extent~~with ~~sustainable~~any ~~lending~~future ~~and~~disclosures ~~investment~~we ~~practices~~ may ~~impact~~make ~~our~~regarding ~~operations~~reported emissions, aparticularly ~~material~~given ~~reduction in~~ the ~~capital~~inherent ~~available~~uncertainties ~~to the oil~~ and ~~natural~~estimations ~~gas~~with ~~industry~~respect ~~could make it more difficult~~ to ~~secure~~calculating ~~funding for exploration, development, production, transportation~~ and ~~processing~~reporting ~~activities,~~GHG ~~which could result in decreased demand for our midstream services~~emissions.

In addition, in March 2024, the SEC finalized a rule requiring registrants to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and periodic reports. However, this rule is currently paused pending litigation and is expected to be repealed. The timeline for any repeal, if at all, is subject to a number of uncertainties and likely could face legal challenges that would further delay the implementation of any repeal, and we cannot predict the ultimate outcome. Similarly, in October 2023, the Governor of California signed the CCDAA and CRFRA into law. The CCDAA requires both public and private U.S. companies that are “doing business in California” and that have a total annual revenue of $1 billion to publicly disclose and verify, on an annual basis, Scope 1, 2 and 3 GHG emissions. The CRFRA requires the disclosure of a climate-related financial risk report (in line with the TCFD recommendations or equivalent disclosure requirements under the ISSB climate-related disclosure standards) every other year for public and private companies that are “doing business in California” and have total annual revenue of at least $500 million. Reporting under both laws would begin in 2026. These laws are currently subject to legal challenges, but the outcome of such challenges is uncertain at this time. Additionally, New York and other jurisdictions are considering adopting similar climate disclosure laws. Currently, the ultimate impact of these laws on our business is uncertain—the Governor of California has directed further consideration of the implementation deadlines for each of the laws, and there is potential for legal challenges to be filed with respect to the scope of the law—but, absent clarification or revisions to the law, alongside the SEC rule, if implemented, may result in additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions. Separately, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, and there is the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate risks or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for the services we provide. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in HCAs or MCAs. The regulations require operators to:

●

perform ongoing assessments of pipeline integrity;

●

identify and characterize applicable threats to pipeline segments that could impact certain high risk areas;

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

●

implement preventive and mitigating actions.

The 2011 Pipeline Safety Act among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the 2011 Pipeline Safety Act, the PHMSA, finalized rules that increased the maximum administrative civil penalties for violations of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. In December 2024, those maximum civil penalties were increased to $272,926 and $2,729,245, respectively, to account for inflation. Should our operations fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.

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. 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. 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. 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.

The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant, consistent with other similarly situated midstream companies. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and

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~~strength~~regulatory ofchanges ~~pipe~~could ~~operating~~have ~~above~~a ~~30%~~material ofeffect ~~specified~~on ~~minimum~~our ~~yield~~cash ~~strength in HCAs~~flow. ~~Consistent~~See ~~with the 2011~~ “Business—Pipeline Safety ~~Act,~~Regulation” ~~the PHMSA, finalized rules that increased the maximum administrative civil penalties~~ for ~~violations~~more ~~of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations~~information. In December 2024, those maximum civil penalties were increased to $272,926 and $2,729,245, respectively, to account for inflation. Should our operations fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.

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 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. 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. 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.

Regulations related to the protection of wildlife could adversely affect our ability to conduct oil and gas operations in some of the areas where we operate.

Oil and gas operations in our operating areas can be adversely affected by regulations designed to protect various wildlife. For example, following a 2020 court order to reconsider its decision to list the northern long-eared bat as threatened instead of endangered, the USFWS redesignated the bat as endangered under the ESA. The designation of previously unprotected species as threatened or endangered, or redesignation of a threatened species as endangered, in areas where we operate could cause us to incur increased costs arising from species protection measures, result in constraints on our customer’s exploration and production activities and on our pipeline construction and operation activities. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations or the operations of our customers and materially increase our operating and capital costs.

Human Capital

The loss of senior management or technical personnel could adversely affect 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 ~~Paul~~Michael MN. ~~Rady~~Kennedy, ~~Chairman, President and~~ Chief Executive Officer and President, could have a material adverse effect on our business, financial condition and results of operations.

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Our officers and employees provide services to both Antero Resources and us.

All of our executive officers and certain other personnel who provide corporate, general and administrative services to our business are, when providing services to us, concurrently employed by Antero Resources and us pursuant to the terms of a services agreement. In addition, our operational personnel are seconded to us by Antero Resources pursuant to the terms of a secondment agreement and are concurrently employed by Antero Resources and us during such secondment. As a result, there could be material competition for the time and effort of the officers and employees who provide services to Antero Resources and us. If such officers and employees do not devote sufficient attention to the management and operation of our business, our financial results may suffer.

Related Parties

All of our officers and certain of our directors are also officers or directors of Antero Resources. Also, as of December 31, ~~2024~~2025, Antero Resources beneficially owned 29% of our outstanding common stock. Conflicts of interest will arise between Antero Resources and us. Our directors and officers who are also directors and officers of Antero Resources have a fiduciary duty to manage Antero Resources in a manner that is beneficial to Antero Resources. In resolving these actual or apparent conflicts of interest, these directors and officers may choose strategies that favor Antero Resources over our interests and the interests of our stockholders. These actual and apparent conflicts may in certain cases include, for example, the decision to declare and pay dividends or the decision to repurchase shares of our common stock owned by Antero Resources. The resolution of any conflicts of interest between Antero Resources and its subsidiaries, on one hand, and us and our subsidiaries, on the other, to the extent we can resolve them, may be costly and reduce the amount of time and attention that our directors and officers may spend in operating our business, which, in each case, may adversely affect our business.

Furthermore, Antero Resources is under no obligation to adopt a business strategy that favors us. For example, Antero Resources has dedicated acreage to, and entered into long-term contracts for gathering and compression services on, our gathering and compression systems, as well as long-term contracts for receiving water services. However, while we have a right of first offer that expires in 2038 to provide processing and fractionation services to Antero Resources, subject to certain exceptions, Antero Resources is under no obligation to consider whether any future drilling plans would create beneficial opportunities for us. Additionally, although our processing and fractionation services provided by the Joint Venture are supported by minimum volume commitments, the gathering and compression agreements include minimum volumes commitments only on high pressure pipelines and/or compressor stations constructed at Antero Resources’ request. Any decision by Antero Resources to operate its assets in a manner that does not support our operations could have a material adverse effect on our business, financial condition and results of operations.

We are a holding company whose sole material asset is our equity interest in Antero Midstream Partners, and we are accordingly dependent upon distributions from Antero Midstream Partners to pay taxes, return capital to stockholders and cover our corporate and other overhead expenses.34

We are a holding company and have no material assets other than our equity interest in Antero Midstream Partners. We have no independent means of generating revenue. To the extent Antero Midstream Partners has available cash, we intend to cause Antero Midstream Partners to make distributions to us in an amount at least sufficient to allow us to pay our taxes, to fund our return of capital to our stockholders (including paying dividends and repurchasing shares of our common stock) and for our corporate and other overhead expenses. To the extent that we need funds and Antero Midstream Partners or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders.

Paul M. Rady and an individual affiliated with Yorktown serve as members of our Board and the Board of Directors of Antero Resources. Mr. Rady and Yorktown also own a significant portion of the shares of common stock of Antero Resources. As a result of their investments in Antero Resources, Mr. Rady and Yorktown may have conflicting interests with other stockholders. Conflicts of interest could arise in the future between us, on the one hand, and Mr. Rady and Yorktown, on the other hand, regarding, among other things, decisions related to our financing, capital expenditures and growth plans, the terms of our agreements with Antero Resources and its subsidiaries and the pursuit of potentially competitive business activities or business opportunities.

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Taxes

Our future tax liabilities may be greater than expected if we do not generate deductions or net operating loss (“NOL”) carryforwards sufficient to offset taxable income or if tax authorities challenge our tax positions.

We expect to generate deductions and NOL carryforwards that we can use to offset our taxable income. As a result, we do not expect to pay material U.S. federal and state income taxes through 2026. This expectation is based upon assumptions our management has made regarding, among other things, income, capital expenditures and net working capital. Further, the IRS or other tax authorities could challenge one or more tax positions we take, and any change in law may affect our tax positions. While we expect that our deductions and NOL carryforwards will be available to us as a future benefit, in the event that they are not generated as expected, are successfully challenged by the IRS or other tax authorities (in a tax audit or otherwise), or are subject to future limitations, our ability to realize these benefits may be limited.

Changes to applicable tax laws and regulations or exposure to additional income tax liabilities could adversely affect our operating results and cash flows.

We are subject to various complex and evolving U.S. federal, state and local tax laws. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect. Any significant variance in our interpretation of current tax laws or a successful challenge of one or more of our tax positions by the IRS or other tax authorities could increase our future tax liabilities and adversely affect our operating results and cash flows.

Taxable gain or loss on the sale of our common stock could be more or less than expected.

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 ~~the~~a ~~majority~~portion 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.

The IRS Forms 1099-DIV that our stockholders receive from their brokers may over-report dividend income with respect to our common stock for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a stockholder’s U.S. federal income tax return. For non-U.S. holders of our common stock, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund to claim a refund of the overwithheld taxes.

Distributions we pay with respect to our common stock will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a stockholder’s tax basis in their common stock and then as capital gain realized on the sale or exchange of such stock. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax with respect to distribution amounts that should have been classified as a tax-free return of capital. In such a case, a stockholder generally would have to timely file an amended U.S. tax return or an appropriate claim for refund to obtain a refund of the overpaid tax.

For a U.S. holder of our common stock, the IRS Forms 1099-DIV received from brokers may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a stockholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended U.S. federal, state or local income tax return). We will attempt to timely notify our stockholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our stockholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a stockholder’s tax return.35

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For a non-U.S. holder of our common stock, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with the conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that constitute a “dividend” for U.S. federal income tax purposes, or a stockholder’s broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a stockholder’s broker or other withholding agent may overwithhold taxes from distributions paid. In such a case, a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.

General Risks

We expect to use a significant portion of our cash flows to pay dividends to our stockholders and/or repurchase shares of our common stock, which could limit our ability to grow and make acquisitions.

We have previously announced that we plan to return capital to our stockholders through dividends to our stockholders and repurchasing shares of our common stock, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional shares of common stock in connection with any acquisitions or expansion capital expenditures, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the cash that we have available to return capital to our stockholders through dividends and/or repurchases of shares of our common stock.

We may reduce or cease paying dividends on our common stock.

We are not obligated to pay dividends on shares of our common stock. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of our common stock are only entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our Board out of funds legally available for dividend payments. Our Board makes a determination each quarter as to the actual amount, if any, of dividends to pay on our common stock, based on various factors, some of which are beyond our control, including our operating cash flows, our working capital needs, our ability to access capital markets for debt and equity financing on reasonable terms, the restrictions contained in our debt instruments, our debt service requirements, credit metrics and the cost of acquisitions, if any. We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. Accordingly, we cannot guarantee that we will declare any future dividends at levels consistent with our historic practice or at all.

The price of our common stock may be volatile, and you could lose a significant portion of your investment.

The market price of our common stock could be volatile, and holders of common stock may not be able to resell their common stock at or above the price at which they acquired such securities due to fluctuations in the market price of our common stock.

Specific factors that may have a significant effect on the market price for our common stock include:

●

our operating and financial performance and prospects and the trading price of our common stock;

●

the level of our dividends;

●

quarterly variations in the rate of growth of our financial indicators, such as dividends per share of our common stock, net income and revenues;

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levels of indebtedness;

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changes in revenue or earnings estimates or publication of research reports by analysts;

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speculation by the press or investment community;

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sales of our common stock by other stockholders;

●

announcements by us or our competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments;

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general market conditions;

●

changes in accounting standards, policies, guidance, interpretations or principles;

●

adverse changes in tax laws or regulations;

●

domestic and international economic, legal and regulatory factors related to our performance; and

●

Antero Resources’ operating and financial performance and prospects, and the trading price of its common stock.

There may be future dilution of our common stock, which could adversely affect the market price of shares of our common stock.

We are not restricted from issuing additional shares of our common stock out of our authorized capital. In the future, we may issue shares of our common stock to raise cash for future activities, acquisitions or other purposes. We may also acquire interests in other companies by using a combination of cash and shares of our common stock or only shares. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, shares of our common stock. Any of these events may dilute the ownership interests of our stockholders, reduce our net income per share or have an adverse effect on the price of shares of our common stock.

Sales of a substantial amount of shares of our common stock in the public market could adversely affect the market price of our shares.

Sales of a substantial amount of shares of our common stock in the public market or grants to our directors and officers under the Amended and Restated Antero Midstream Corporation Long Term Incentive Plan (“AM LTIP”), or the perception that these sales or grants may occur, could reduce the market price of shares of our common stock. All of the shares of our common stock are freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. In addition, we are party to a registration rights agreement with Antero Resources, certain members of management and certain funds affiliated with Yorktown, pursuant to which we agreed to register the resale of shares of our common stock issued or paid to them in the transactions that occurred pursuant to the Simplification Agreement, dated as of October 9, 2018. We cannot predict the size of future issuances of our common stock or securities convertible into our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock.

Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders' ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (the “Court of Chancery”) will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, stockholders, employees or agents to us or our stockholders, (iii) any action or proceeding asserting a claim arising pursuant to any provision of the DGCL, our certificate of incorporation or our bylaws as to which the DGCL confers jurisdiction on the Court of Chancery or (iv) any action or proceeding asserting a claim against us governed by the internal affairs doctrine, in each such case subject to the Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. The foregoing provision does not apply to claims under the Securities Act, the Exchange Act or any claim for which the U.S. federal courts have exclusive jurisdiction. Furthermore, if the Court of Chancery lacks subject matter jurisdiction for any such matter, any state or federal court located within Delaware will be the sole and exclusive forum for that matter. Any person or entity purchasing or otherwise acquiring or holding any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of certificate of incorporation described in the preceding sentence. This choice of forum provision may limit our stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with it or its directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations.

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preceding sentence. This choice of forum provision may limit our stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with it or its directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations.

We may issue preferred stock, which may have terms that could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes our Board to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of a class or series of our preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our common stock.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 1C. CYBERSECURITY

Processes for Assessing, Identifying and Managing Cybersecurity Risks

We are continuously assessing and adopting new processes, systems and resources in an effort to make our business safer from cybersecurity threats. We depend on digital technology in many areas of our business and operations, including, but not limited to, our gathering and compression and water handling services, processing and recording financial and operating data, oversight and analysis of our operations and communications with the employees supporting our operations and our customers and service providers. We also collect and store sensitive data in the ordinary course of our business, including certain personally identifiable information and proprietary information for our business and that of our customers, suppliers, investors and other stakeholders.

Attacks on our assets or security breaches in our systems or infrastructure could lead to the corruption, loss or unauthorized use of such data, delays in production or delivery of our production to customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions or other operational disruptions. We seek to address these risks by safeguarding assets, data and operations through the cybersecurity risk management processes described below:

Risk Assessments

We assess our systems, networks and data infrastructure to identify potential cybersecurity threats and vulnerabilities via continuous automated processes that are complemented by manual processes that are executed on both a routine and ad hoc basis. These processes are designed to prevent, detect and investigate activities and events that could pose a cybersecurity risk or threat to us, and include, but are not limited to, monitoring and evaluating cybersecurity intelligence information published or provided by certain United States federal government agencies as well as private cybersecurity groups. Our risk assessment processes are conducted, monitored and reviewed by our security and compliance team as well as third-party consultants. In addition, we perform cybersecurity tabletop exercises with our information technology (“IT”) department throughout the year. We also engage a third-party consultant to conduct an annual penetration test of our systems, networks and data infrastructure to complement our risk assessment processes and activities. These risk assessments help evaluate the likelihood and potential impact of cybersecurity incidents.

Our Vice President – IT oversees these risk assessments and meets regularly with the security and compliance team to review cybersecurity risks and threats, and also participates in our enterprise risk management process. In addition, the Company engages several third-party consultants in connection with the risk assessments, and we have established separate processes and procedures to oversee and identify cybersecurity risks associated with third parties. All third parties involved in our cybersecurity risk assessments are required to provide reports designed to allow us to monitor and assess such third parties’ security controls.

We monitor and manage our cybersecurity risk and threat exposure through prioritized remediation efforts. Any cybersecurity risk or threat that requires corrective action is managed by our security and compliance team together with certain business partners and IT specialists, as deemed necessary. Potential solutions are assessed in alignment with risk, business and cybersecurity priorities and our controls and security architecture. Plans to remediate cybersecurity risks are approved and monitored regularly for completion.38

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Incident Identification and Response

We have implemented a monitoring and detection system, with oversight from our Vice President – IT to help promptly identify cybersecurity incidents. In the event of any breach or cybersecurity incident, we have a formal incident response plan designed to provide for immediate action to contain the incident, mitigate the impact and restore normal operations efficiently.

Cybersecurity Training and Awareness

We train our users throughout the year using a wide variety of methods on cybersecurity-related topics, including how to identify and report potential social engineering including phishing through emails, text messages and phone calls. Formal training on cybersecurity practices begins when an employee is hired and is re-administered annually. We also require third-party contractors with access to our systems be trained on these topics. In addition, special training is held both formally and informally for groups that entail higher threat risks.

Policies

Our IT polices are designed to address and manage all aspects of our IT environment, including cybersecurity, and we review and update our policies regularly as part of our risk management processes. We deploy both an internal Protection of Personal Identifiable Information Policy and a publicly available Privacy Notice to help us understand and respect the privacy of the individuals whose data we have custody over. We monitor our data collection practices, policies and notices in an effort to comply with the evolving nature of applicable data privacy and security laws.

Our cybersecurity risk management processes are integrated into our enterprise risk management program. Cybersecurity threats are understood to be dynamic and intersect with various other enterprise risks. As such, cybersecurity is considered to be an important component of our enterprise risk management approach. Our cybersecurity strategies are based on standard cybersecurity frameworks, including the National Institute of Standards and Technology and the International Organization for Standardization.

Board of Directors’ Oversight of Cybersecurity Risks and Management’s Role in Assessing and Responding to Cybersecurity Risks

Cybersecurity risks are overseen at the board level through the Audit Committee. Our Vice President – IT, together with the security and compliance team, is responsible for the monitoring, assessment and management of cybersecurity risk, and seeks to maintain the security and continuity of our operations. Our Vice President – IT oversees the Company’s cybersecurity strategy, cybersecurity and data privacy policies, measures and controls, and Board of Directors and Audit Committee communications on cybersecurity matters. Our Vice President – IT regularly briefs senior management, the Board of Directors and the Audit Committee on cybersecurity issues as part of our overall enterprise risk management program, including quarterly updates to the Audit Committee, which may include information regarding our exposure to privacy and cybersecurity risks, plans and activities to monitor and mitigate privacy and cybersecurity risks, IT governance policies and programs, including our cybersecurity incident response plan, and legislative and regulatory developments that could impact our privacy and cybersecurity risks. Additionally, our Vice President – Risk Management oversees our enterprise risk management process and apprises the Audit Committee and our Board of Directors of all significant risks facing the Company, including cybersecurity risks.

Our Vice President – IT, Biren Kumar, has more than 1617 years of experience serving as a Chief Information Officer (“CIO”) or similar role, which included responsibility for managing cybersecurity risk. Mr. Kumar was named Vice President – IT in 2024. Prior to joining Antero, he served as the CIO for several companies, including Dynegy Inc. from 2005 to 2011, Rockwater Energy Solutions Inc. from 2011 to 2014, KLX Inc. from 2014 to 2018 and KLX Energy Services Holdings, Inc. from 2018 to 2021. Mr. Kumar holds a Bachelor of Business Administration in Management Information Systems and a Master of Business Administration from the University of Houston.

Impact of Risks from Cybersecurity Threats

The energy industry’s growing reliance on information technology and operational technology to support critical operations, such as energy distribution and management activities, has made it more susceptible to cybersecurity incidents. As a result, the global rise of cybersecurity incidents, whether from intentional attacks or accidental events, poses a significant challenge to our industry. As cybersecurity threats continue to evolve in complexity and scale, it remains an ongoing and increasingly difficult task for the industry to prevent, detect, mitigate, and remediate these incidents.

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rise of cybersecurity incidents, whether from intentional attacks or accidental events, poses a significant challenge to our industry. As cybersecurity threats continue to evolve in complexity and scale, it remains an ongoing and increasingly difficult task for the industry to prevent, detect, mitigate, and remediate these incidents.

As of the date of this Annual Report on Form 10-K, we are not aware of any cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected or are reasonably likely to materially affect us. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future discovery of cybersecurity incidents remains. Please see “Item 1A. Risk Factors” for additional information about cybersecurity risks. Despite the implementation of our cybersecurity programs, our security measures cannot guarantee that a cyberattack with significant impact will not occur. A successful attack on our IT systems could have significant consequences to the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our information technology systems.

Item 3. Legal Proceedings

See Note 1516—Contingencies to our consolidated financial statements for additional information.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock

We have one class of common equity outstanding, our common stock, par value $0.01 per share. Our common stock is listed on the New York Stock Exchange and traded under the symbol “AM.” On February 76, ~~2025~~2026, shares of our common stock were held by 4253 holders of record. The number of holders does not include the holders for whom shares of our common stock are held in a “nominee” or “street” name. In addition, as of February 76, ~~2025~~2026, Antero Resources and its subsidiaries owned 139,172,515 shares of our common stock, which represented a 29% interest in us.

Issuer Purchases of Equity Securities

The following table sets forth our common stock share purchase activity for each period presented:


					Approximate
					Dollar Value of
				Total Number of	Shares that May
	Total Number	Average Price		Shares Purchased	Yet be Purchased
	of Shares	Paid per		as Part of Publicly	Under the Plan
Period	Purchased (1)	Share		Announced Plans	($ in thousands)
October 1, 2024 – October 31, 2024 (1)	11,073	$	15.31	—	$	500,000
October 1, 2025 – October 31, 2025	736,197	$	18.04	736,197	$	371,362
November 1, 2024 – November 30, 2024	—		—	—		500,000
November 1, 2025 – November 30, 2025	1,074,617		17.68	1,046,012		352,870
December 1, 2024 – December 31, 2024	1,902,088		15.08	1,902,088		471,310
December 1, 2025 – December 31, 2025	922,173		17.94	922,173		336,329
Total	12,~~913~~732,~~161~~987	$	1517.0886	12,~~902~~704,~~088~~382

(1) The total number of shares purchased includes shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of equity-based awards held by our employees.

~~Dividends~~40

On January 14, 2025, the Board declared an aggregate cash dividend on the shares of our common stock of $0.2250 per share for the quarter ended December 31, 2024. The dividend was paid on February 12, 2025 to stockholders of record as of January 29, 2025.

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The Board also declared a cash dividend of $137,500 on shares of our Series A Non-Voting Perpetual Preferred Stock, par value $0.01 (the “Series A Preferred Stock”), that will be paid on February 14, 2025 in accordance with the terms of the Series A Preferred Stock, which are discussed in Note 12—Equity and Net Income Per Common Share to our consolidated financial statements. As of December 31, 2024, there were dividends in the amount of $68,750 accumulated in arrears on our Series A Preferred Stock.Dividends

On January 14, 2026, the Board declared an aggregate cash dividend on the shares of our common stock of $0.2250 per share for the quarter ended December 31, 2025. The dividend was paid on February 11, 2026 to stockholders of record as of January 28, 2026.

The Board also declared a cash dividend of $137,500 on shares of our Series A Non-Voting Perpetual Preferred Stock, par value $0.01 (the “Series A Preferred Stock”), that will be paid on February 17, 2026 in accordance with the terms of the Series A Preferred Stock, which are discussed in Note 13—Equity and Net Income Per Common Share to our consolidated financial statements. As of December 31, 2025, there were dividends in the amount of $68,750 accumulated in arrears on our Series A Preferred Stock.

The amount and timing of future payment of cash dividends on our common stock, if any, is within the discretion of the Board and will depend on our earnings, capital requirements, financial condition and other relevant factors.

Share Repurchase Program

On February 13, 2024, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $500 million of shares of our outstanding common stock. During 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 $29135 million. As of December 31, ~~2024~~2025, there was $~~471~~336 million 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 IRA 2022 applies to our share repurchase program.

Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, ~~2019~~2020 in (i) our common stock (assuming reinvestment of dividends), (ii) the Standard & Poor’s 500 (“S&P 500”) Index and (iii) the Alerian Midstream Energy (“AMNA”) Index. We believe the AMNA Index is meaningful because it is an independent, objective view of the performance of similarly-sized midstream energy companies.

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The information in this Form 10-K appearing under the heading “Stock Performance Graph” is being “furnished” pursuant to Item 2.01(e) of Regulation S-K under the Securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of the Exchange Act except to the extent that we specifically request that it be treated as such.

ITEM 6. Reserved

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. The information provided below supplements, but does not form part of, our consolidated financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, see “Item 1A. Risk Factors.” and the section entitled “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

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.

~~Asset~~ Acquisition and Divestiture

OnHG May 1, 2024, we acquired certain Marcellus gas gathering and compression assets from Summit for $70 million in cash, before closing adjustments, with an effective date of April 1, 2024. This acquisition was funded with our operating cash flow. The acquired assets include 48 miles of high pressure gathering pipelines and two compressor stations with 100 MMcf/d of compression capacity. These assets were already interconnected to our low pressure and high pressure gas gathering systems at the time of acquisition and service Antero Resources’ production. Currently, we do not expect to make any significant capital investments related to the acquired assets. See Note 6—Property and Equipment to our consolidated financial statements for additional information.Acquisition

~~Financing~~On ~~Highlights~~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 includes gathering pipelines and integrated water handling assets in the core of the Marcellus Shale in West Virginia. Pursuant to the same agreement, Antero Resources agreed 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 Upstream Acquisition includes approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. These acquisitions closed on February 3, 2026. The HG Acquisition was funded with net proceeds of the 2034 Notes (as defined below), borrowing under the Credit Facility and restricted cash. See Note 3—Transactions to our consolidated financial statements for additional information. We intend to make certain modifications to our existing commercial arrangements with Antero Resources to provide for on-pad compression with respect to certain wells and to provide a transition period through 2026 before certain water services would be provided under the existing agreements with Antero Resources.

~~Credit~~Utica ~~Facility~~Shale Divestiture

On ~~July 30~~December 5, ~~2024~~2025, we entered into anthe ~~amendment~~Utica ~~and~~Shale ~~restatement~~PSA with the Buyer Parties to sell substantially all of our ~~senior~~Utica ~~secured~~Shale ~~revolving~~Property ~~credit~~and ~~facility~~Equipment ~~with~~in ~~lender~~Ohio, ~~commitments~~for aggregate cash consideration of $1400 million, subject to the terms and conditions thereof.25 The ~~billion~~Utica Shale Property and Equipment includes 118 miles of gathering pipelines, ~~which~~0.7 ~~matures~~Bcfe/d onof ~~July~~compression 30capacity, ~~2029~~85 (miles of water pipelines and 12 water impoundments with storage capacity of approximately 2 million barrels. The Utica Shale Divestiture is expected to close in February 2026, subject to the satisfaction of certain ~~terms~~customary ~~and~~closing conditions. The ~~related~~net toproceeds from the ~~outstanding~~Utica ~~balances~~Shale Divestiture are expected to ~~our~~be ~~2027,~~used ~~2028~~for ~~and~~the ~~2029~~repayment ~~notes)~~of long-term debt. See Note 83—~~Long-Term~~Transactions ~~Debt~~ to our consolidated financial statements for additional information.

~~Issuance of Senior Notes~~42

On January 16, 2024, we issued $600 million of 6.625% senior notes due February 1, 2032 (the “2032 Notes”) at par. The 2032 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2032 Notes rank pari passu to our other outstanding senior notes and are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of our future restricted subsidiaries. The net proceeds from this offering were used to repay outstanding borrowings on the Credit Facility. See Note 8—Long-Term Debt to our consolidated financial statements for additional information.

Repurchase of Senior Notes

During the year ended December 31, 2024, we repurchased or otherwise fully redeemed $550 million aggregate principal amount of our 7.875% senior notes due May 15, 2026 (the “2026 Notes”) at a weighted average premium of 101.975% of the principal amount thereof, plus accrued and unpaid interest. The 2026 Notes were retired as of May 16, 2024. See Note 8—Long-Term Debt to our consolidated financial statements for additional information.

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Financing Highlights

Senior Notes

Issuance of 2033 Notes

On September 22, 2025, we issued $650 million in aggregate principal amount of 5.75% senior notes due October 15, 2033 (the “2033 Notes”) at par. The 2033 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2033 Notes rank pari passu to our other outstanding senior notes and are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of our future restricted subsidiaries. The net proceeds from this offering were used to redeem the 2027 Notes. See Note 9—Long-Term Debt to our consolidated financial statements for additional information.

Issuance of 2034 Notes

On December 23, 2025, we issued $600 million in aggregate principal amount of 5.75% senior notes due July 1, 2034 (the “2034 Notes”). The 2034 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2034 Notes rank pari passu to our other outstanding senior notes and are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of our future restricted subsidiaries. The net proceeds from this offering were used to partially fund the HG Acquisition. See Note 3—Transactions and Note 9—Long-Term Debt to our consolidated financial statements for additional information.

Redemption of 2027 Notes

During the year ended December 31, 2025, we redeemed $650 million aggregate principal amount of our 5.75% senior notes due March 1, 2027 (the “2027 Notes”) at par, plus accrued and unpaid interest. The 2027 Notes were retired as of September 23, 2025. See Note 9—Long-Term Debt to our consolidated financial statements for additional information.

Share Repurchase Program

OnThrough ~~February 13, 2024,~~ our ~~Board authorized a~~ share repurchase program, ~~that~~during ~~allows us to repurchase up to $500 million of shares of our outstanding common stock. During~~ the year ended December 31, ~~2024~~2025, we repurchased and retired approximately 2 8 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 approximately $~~471~~ 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.~~

Market Conditions and Business Trends

Commodity Markets

Benchmark prices for natural gas ~~decreased~~and ethane increased significantly, while benchmark prices for ~~oil~~C3+ ~~remained~~NGL’s ~~relatively consistent~~ and ~~NGLs~~oil ~~increased~~decreased during the year ended December 31, ~~2024~~2025 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’ ~~improved~~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.

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Economic Indicators

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 1.075% ~~between~~in ~~September~~2024 and ~~December 2024~~2025. While inflationary pressures in the United States’ economy have begun to subside, weit ~~continue~~is touncertain bewhat ~~impacted~~impact byrecent ~~the~~tariff ~~increased~~activity ~~federal~~by ~~funds~~the ~~interest~~United ~~rate. See~~States ~~“—Results~~and offoreign ~~Operations”~~governments ~~for~~will ~~additional~~have ~~information~~on 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 sanctions, ontariffs, ~~Russia and~~ other global trade 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, there can be no assurance that we will not experience interruptions in the future.

Inflationary pressures and supply chain disruptions could result in further increases to our operating and capital costs that are not fixed. However, our gathering and compression and water agreements provide for annual CPI-based adjustments that mitigate a portion of such inflationary pressures.

These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

Sources of Our Revenues

The following items are the primary components of our revenues:

●

Gathering and Processing. Our low pressure gathering, compression and high pressure gathering services support production operations for Antero Resources. Our gathering and processing revenues are driven by the volumes of natural gas we gather and compress. We receive a low pressure gathering fee per Mcf, a compression fee per Mcf and a high pressure gathering fee per Mcf, as applicable, substantially all of which are subject to annual CPI-based adjustments. Additionally, our gathering and compression agreements provide for certain minimum volume commitments for gathering and compression services that run to 2035. Pursuant to our long-term contracts with Antero Resources, we have secured long-term dedications covering substantially all of Antero Resources’ current and future acreage for gathering and compression services. Our gathering and compression operations are substantially dependent upon natural gas production from Antero Resources’ upstream activity in its areas of operation. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. Although we expect that Antero Resources will continue to devote substantial resources to the development of oil and gas reserves, we have no control over this activity and Antero Resources has the ability to reduce or curtail such development at its discretion. See Note 6—Revenue to our consolidated financial statements for additional information on our gathering and compression agreements.

●

Water Handling. Our fresh water delivery systems and other fluid handling services support well completion and production operations for Antero Resources. These services are provided by us directly or through third-parties with which we contract. Our water handling revenues are driven by quantities of fresh water delivered to our customers to support their well completion operations and produced water transported, blended and/or disposed. We receive a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. Our other fluid handling services include wastewater handling, blending and high-rate transfer services. For other fluid handling services provided by us, we charge Antero Resources a cost of service fee. For other fluid handling services provided by third parties, we charge Antero Resources a fee based on our third-party out-of-pocket costs plus 3%. We have a long-term water services agreement covering Antero Resources’ approximately 566,000 gross acres in West Virginia and Ohio, with a right of first offer on all future areas of operation. The initial term of the water services agreement runs to 2035. Our water handling operations are substantially dependent upon the number of wells drilled and completed by Antero Resources, as well as Antero Resources’ production. As of December 31, 2025, Antero Resources had disclosed estimated net proved reserves of 19.1 Tcfe, of which 61% was natural gas, 38% were NGLs and 1% was oil. Antero Resources’ has a vast drilling inventory of horizontal well locations in the Appalachian Basin, all of which are on acreage dedicated to us, providing us with significant opportunity for future capital investments as Antero Resources’ drilling program continues. See Note 6—Revenue to our consolidated financial statements for additional information on our water services agreement.

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Sources of Our Revenues

The following items are the primary components of our revenues:

● Gathering and Processing. Our low pressure gathering, compression and high pressure gathering services support production operations for Antero Resources. Our gathering and processing revenues are driven by the volumes of natural gas we gather and compress. We receive a low pressure gathering fee per Mcf, a compression fee per Mcf and a high pressure gathering fee per Mcf, as applicable, substantially all of which are subject to annual CPI-based adjustments. Additionally, our gathering and compression agreements provide for certain minimum volume commitments for gathering and compression services that run to 2034. Pursuant to our long-term contracts with Antero Resources, we have secured long-term dedications covering substantially all of Antero Resources’ current and future acreage for gathering and compression services. Our gathering and compression operations are substantially dependent upon natural gas production from Antero Resources’ upstream activity in its areas of operation. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. Although we expect that Antero Resources will continue to devote substantial resources to the development of oil and gas reserves, we have no control over this activity and Antero Resources has the ability to reduce or curtail such development at its discretion. See Note 5—Revenue to our consolidated financial statements for additional information on our gathering and compression agreements.

● Water Handling. Our fresh water delivery systems and other fluid handling services support well completion and production operations for Antero Resources. These services are provided by us directly or through third-parties with which we contract. Our water handling revenues are driven by quantities of fresh water delivered to our customers to support their well completion operations and produced water transported, blended and/or disposed. We receive a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. Our other fluid handling services include wastewater handling, blending and high-rate transfer services. For other fluid handling services provided by us, we charge Antero Resources a cost of service fee. For other fluid handling services provided by third parties, we charge Antero Resources a fee based on our third-party out-of-pocket costs plus 3%. We have a long-term water services agreement covering Antero Resources’ approximately 567,000 gross acres in West Virginia and Ohio, with a right of first offer on all future areas of operation. The initial term of the water services agreement runs to 2035. Our water handling operations are substantially dependent upon the number of wells drilled and completed by Antero Resources, as well as Antero Resources’ production. As of December 31, 2024, Antero Resources had disclosed estimated net proved reserves of 17.9 Tcfe, of which 59% was natural gas, 40% were NGLs and 1% was oil. Antero Resources’ has a vast drilling inventory of horizontal well locations in the Appalachian Basin, all of which are on acreage dedicated to us, providing us with significant opportunity for future capital investments as Antero Resources’ drilling program continues. See Note 5—Revenue to our consolidated financial statements for additional information on our water services agreement.

Principal Components of Our Cost Structure

The following items are the primary components of our operating expenses:

● Direct Operating. We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. We schedule and conduct preventative maintenance over time to avoid significant variability in our direct operating expense and minimize the impact on our cash flow. Gathering and compression operating costs consist primarily of labor, water disposal, pigging, fuel, monitoring, repair and maintenance, utilities and contract services. Gathering and compression operating costs vary with the miles of pipeline and number of compressor stations in our gathering and compression system. Fresh water operating expenses consist primarily of labor, pigging, monitoring, repair and maintenance and contract services. Fresh water operating costs vary with the miles of pipeline, number of pumping stations and ~~the~~ number of well completions in the Appalachian Basin for which we deliver fresh water and number of impoundments in our water system. Other fluid handling costs relate to contract services performed by us and third parties. Our other fluid handling costs consist of labor, monitoring and repair and maintenance costs. The other primary drivers of our direct operating expense include maintenance and contract services, regulatory and compliance expense and ad valorem taxes.

●

General and Administrative. Our general and administrative expenses include direct charges incurred by us and costs charged by Antero Resources. These costs relate to: (i) various business services, including payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation, including certain equity-based compensation. These expenses are charged to the Company based on the nature of the expenses and are apportioned based on a combination of the Company’s proportionate share of gross property and equipment, capital expenditures and labor costs, as applicable. Management believes these allocation methodologies are reasonable. Equity-based compensation includes costs related to the AM LTIP.

●

Depreciation. Depreciation consists of our estimate of the decrease in value of the assets capitalized in property and equipment as a result of using the assets throughout the applicable year. Depreciation is computed over the asset’s estimated useful life using the straight-line basis. See Note 7—Property and Equipment to our consolidated financial statements for additional information on our asset classes and estimated lives of our assets.

●

Impairment. We evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to their estimated fair value.

●

Interest. We have typically financed a portion of our cash requirements with borrowings under our Credit Facility and with senior unsecured notes. Our interest expense also includes amortization of deferred financing costs incurred in connection with our Credit Facility and senior notes and amortization of senior notes premiums. See Note 9—Long-Term Debt to our consolidated financial statements for additional information on our debt agreements.

●

Income tax expense. We are subject to state and U.S. federal income taxes but are currently not in a material cash tax paying position with respect to state and U.S. federal income taxes. The difference between our financial statement income tax expense and our current U.S. federal income tax liability is primarily due to the differences in the tax and financial statement treatment of our investment in Antero Midstream Partners. We have recorded deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. Our deferred income tax assets result primarily from net operating loss carryforwards. As of December 31, 2025, we had U.S. federal NOL carryforwards of $557 million and state NOL carryforwards of $406 million. The Company currently considers all of its deferred income tax assets, except for those related to charitable contributions, realizable. The amount of deferred income tax assets considered realizable, however, could change as we generate taxable income or as estimates of future taxable income are reduced. See Note 8—Income Taxes to our consolidated financial statements for additional information on our deferred income tax position and income tax expense.

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● General and Administrative. Our general and administrative expenses include direct charges incurred by us and costs charged by Antero Resources. These costs relate to: (i) various business services, including payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation, including certain equity-based compensation. These expenses are charged to the Company based on the nature of the expenses and are apportioned based on a combination of the Company’s proportionate share of gross property and equipment, capital expenditures and labor costs, as applicable. Management believes these allocation methodologies are reasonable. Equity-based compensation includes costs related to the AM LTIP.

● Depreciation. Depreciation consists of our estimate of the decrease in value of the assets capitalized in property and equipment as a result of using the assets throughout the applicable year. Depreciation is computed over the asset’s estimated useful life using the straight-line basis. See Note 6—Property and Equipment to our consolidated financial statements for additional information on our asset classes and estimated lives of our assets.

● Impairment. We evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to their estimated fair value.

● Interest. We have typically financed a portion of our cash requirements with borrowings under our Credit Facility and with senior unsecured notes. Our interest expense also includes amortization of deferred financing costs incurred in connection with our Credit Facility and senior notes and amortization of senior notes premiums. See Note 8—Long-Term Debt to our consolidated financial statements for additional information on our debt agreements.

● Income tax expense. We are subject to state and federal income taxes but are currently not in a cash tax paying position with respect to state and federal income taxes. The difference between our financial statement income tax expense and our current U.S. federal income tax liability is primarily due to the differences in the tax and financial statement treatment of our investment in Antero Midstream Partners. We have recorded deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. Our deferred income tax assets result primarily from net operating loss carryforwards. As of December 31, 2024, we had U.S. federal NOL carryforwards of $438 million and state NOL carryforwards of $505 million. The Company currently considers all of its deferred income tax assets, except for those related to charitable contributions, realizable. The amount of deferred income tax assets considered realizable, however, could change as we generate taxable income or as estimates of future taxable income are reduced. See Note 7—Income Taxes to our consolidated financial statements for additional information on our deferred income tax position and income tax expense.

Results of Operations

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 compressor stations 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) two independent systems that deliver 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 1617—Reportable Segments to our consolidated financial statements for additional information.

Year Ended December 31, 2024 Compared to Year Ended December 31, 2025

The operating results of our reportable segments are as follows:


	Year Ended December 31, 2024
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated ⁽¹⁾		Total
Revenues:
Revenue–Antero Resources	$	926,063		248,858		—		1,174,921
Revenue–third-party		—		1,944		—		1,944
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		888,977		217,216		—		1,106,193
Operating expenses:
Direct operating		103,053		114,923		—		217,976
General and administrative (excluding equity-based compensation)		28,814		8,279		4,661		41,754
Equity-based compensation		35,535		7,800		997		44,332
Facility idling		—		1,721		—		1,721
Depreciation		84,398		55,602		—		140,000
Impairment of property and equipment		332		—		—		332
Other operating expense		—		912		—		912
Total operating expenses		252,132		189,237		5,658		447,027
Operating income		636,845		27,979		(5,658)		659,166
Other income (expense):
Interest expense, net		—		—		(207,027)		(207,027)
Equity in earnings of unconsolidated affiliates		110,573		—		—		110,573
Loss on early extinguishment of debt		—		—		(14,091)		(14,091)
Total other income (expense)		110,573		—		(221,118)		(110,545)
Income before income taxes		747,418		27,979		(226,776)		548,621
Income tax expense		—		—		(147,729)		(147,729)
Net income and comprehensive income	$	747,418		27,979		(374,505)		400,892

(1)	Corporate expenses that are not directly attributable to either the gathering and processing or water handling segments.

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Year Ended December 31, 2023 Compared to Year Ended December 31, 2024


	Year Ended December 31, 2025
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated ⁽¹⁾		Total
Revenues:
Revenue–Antero Resources	$	987,284		269,399		—		1,256,683
Revenue–third-party		—		2,415		—		2,415
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		950,198		238,228		—		1,188,426
Operating expenses:
Direct operating		107,846		124,064		—		231,910
General and administrative (excluding equity-based compensation)		21,394		14,879		5,703		41,976
Equity-based compensation		30,025		14,789		1,144		45,958
Facility idling		—		1,801		—		1,801
Depreciation		76,559		57,751		—		134,310
Impairment of property and equipment		—		984		—		984
Loss on long-lived assets		82,960		3,666		—		86,626
Other operating expense, net		—		192		—		192
Total operating expenses		318,784		218,126		6,847		543,757
Operating income		631,414		20,102		(6,847)		644,669
Other income (expense):
Interest expense, net		—		—		(190,404)		(190,404)
Equity in earnings of unconsolidated affiliates		116,439		—		—		116,439
Loss on early extinguishment of debt		—		—		(1,313)		(1,313)
Transaction expense		—		—		(5,195)		(5,195)
Total other income (expense)		116,439		—		(196,912)		(80,473)
Income before income taxes		747,853		20,102		(203,759)		564,196
Income tax expense		—		—		(151,033)		(151,033)
Net income and comprehensive income	$	747,853		20,102		(354,792)		413,163

The operating results of our reportable segments were as follows:


	Year Ended December 31, 2023
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated (1)		Total
Revenues:
Revenue–Antero Resources	$	893,862		268,667		—		1,162,529
Revenue–third-party		—		1,414		—		1,414
Gathering—low pressure fee rebate		(51,500)		—		—		(51,500)
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		805,276		236,495		—		1,041,771
Operating expenses:
Direct operating		95,507		117,658		—		213,165
General and administrative (excluding equity-based compensation)		22,532		12,497		4,433		39,462
Equity-based compensation		23,313		7,362		931		31,606
Facility idling		—		2,459		—		2,459
Depreciation		83,409		52,650		—		136,059
Impairment of property and equipment		133		13		—		146
Accretion of asset retirement obligations		—		177		—		177
Loss on settlement of asset retirement obligations		—		805		—		805
Loss (gain) on asset sale		6,039		(9)		—		6,030
Total operating expenses		230,933		193,612		5,364		429,909
Operating income		574,343		42,883		(5,364)		611,862
Other income (expense):
Interest expense, net		—		—		(217,245)		(217,245)
Equity in earnings of unconsolidated affiliates		105,456		—		—		105,456
Total other income (expense)		105,456		—		(217,245)		(111,789)
Income before income taxes		679,799		42,883		(222,609)		500,073
Income tax expense		—		—		(128,287)		(128,287)
Net income and comprehensive income	$	679,799		42,883		(350,896)		371,786

(1)	Corporate expenses that are not directly attributable to either the gathering and processing or water handling segments.

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	Year Ended December 31, 2024
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated (1)		Total
Revenues:
Revenue–Antero Resources	$	926,063		248,858		—		1,174,921
Revenue–third-party		—		1,944		—		1,944
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		888,977		217,216		—		1,106,193
Operating expenses:
Direct operating		103,053		114,923		—		217,976
General and administrative (excluding equity-based compensation)		28,814		8,279		4,661		41,754
Equity-based compensation		35,535		7,800		997		44,332
Facility idling		—		1,721		—		1,721
Depreciation		84,398		55,602		—		140,000
Impairment of property and equipment		332		—		—		332
Accretion of asset retirement obligations		—		189		—		189
Loss on asset sale		—		723		—		723
Total operating expenses		252,132		189,237		5,658		447,027
Operating income		636,845		27,979		(5,658)		659,166
Other income (expense):
Interest expense, net		—		—		(207,027)		(207,027)
Equity in earnings of unconsolidated affiliates		110,573		—		—		110,573
Loss on early extinguishment of debt		—		—		(14,091)		(14,091)
Total other income (expense)		110,573		—		(221,118)		(110,545)
Income before income taxes		747,418		27,979		(226,776)		548,621
Income tax expense		—		—		(147,729)		(147,729)
Net income and comprehensive income	$	747,418		27,979		(374,505)		400,892

(1) Corporate expenses that are not directly attributable to either the gathering and processing or water handling segments.

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The operating data for Antero Midstream is as follows:


					Amount of
	Year Ended December 31,				Increase		Percentage
	~~2023~~2024		~~2024~~2025		or Decrease		Change
Operating Data:
Gathering—low pressure (MMcf)		1,~~202~~199,~~510~~804		1,~~199~~247,~~804~~889		(248,~~706)~~085		*4	%
Compression (MMcf)		1,~~186~~193,~~641~~306		1,~~193~~243,~~306~~205		649,~~665~~899		14	%
Gathering—high pressure (MMcf)		1,~~068~~102,~~292~~673		1,~~102~~158,~~673~~138		3455,~~381~~465		35	%
Fresh water delivery (MBbl)		3934,~~072~~626		3435,~~626~~342		~~(4,446)~~716		~~(11)~~2	%
Other fluid handling (MBbl)		2019,~~084~~615		1920,~~615~~837		~~(469)~~1,222		~~(2)~~6	%
Wells serviced by fresh water delivery		7661		6175		~~(15)~~14		~~(20)~~23	%
Gathering—low pressure (MMcf/d)		3,~~295~~278		3,~~278~~419		~~(17)~~141		~~(1)~~4	%
Compression (MMcf/d)		3,~~251~~260		3,~~260~~406		9146		*4	%
Gathering—high pressure (MMcf/d)		23,~~927~~013		3,~~013~~173		86160		35	%
Fresh water delivery (MBbl/d)		~~107~~95		9597		~~(12)~~2		~~(11)~~2	%
Other fluid handling (MBbl/d)		5554		5457		~~(1)~~3		~~(2)~~6	%
Average Realized Fees(1):
Average gathering—low pressure fee ($/Mcf)	$	0.3536		0.36		~~0.01~~—		3*	%
Average compression fee ($/Mcf)	$	0.21		0.2122		—0.01		*5	%
Average gathering—high pressure fee ($/Mcf)	$	0.2122		0.2223		0.01		5	%
Average fresh water delivery fee ($/Bbl)	$	4.2131		4.3137		0.1006		21	%
Joint Venture Operating Data:
Processing—Joint Venture (MMcf)		~~581~~588,~~785~~583		~~588~~615,~~583~~688		627,~~798~~105		15	%
Fractionation—Joint Venture (MBbl)		14,~~135~~640		14,~~640~~600		~~505~~(40)		4*	%
Processing—Joint Venture (MMcf/d)		1,~~594~~608		1,~~608~~687		1479		15	%
Fractionation—Joint Venture (MBbl/d)		3940		40		1—		3*	%

*Not meaningful or applicable.

(1)The average realized fees for the year ended December 31, ~~2024~~2025 include annual CPI-based adjustments of approximately 1.6%.

Revenues. Total revenues increased by 67%, from $1.01 billion for the year ended December 31, ~~2023~~2024, to $1.12 billion for the year ended December 31, ~~2024~~2025. Total revenues included amortization of customer relationships of $71 million ~~during~~for each of the years ended December 31, ~~2023~~2024 and ~~2024~~2025. Gathering and processing revenues increased by 107%, from $~~805~~889 million for the year ended December 31, ~~2023~~2024 to $~~889~~950 million for the year ended December 31, ~~2024~~2025. Water handling revenues ~~decreased~~increased by 810%, from $~~237~~217 million for the year ended December 31, ~~2023~~2024 to $~~217~~238 million for the year ended December 31, ~~2024~~2025. These fluctuations primarily resulted from the following:

Gathering and Processing

● Low pressure gathering revenue increased $5924 million period over period primarily due to ~~lower~~increased ~~growth~~throughput ~~incentive~~volumes ~~rebates~~ of ~~$52~~48 ~~million~~Bcf, ~~due~~or to141 ~~the expiration of the program on December 31~~MMcf/d, ~~2023~~ and increased low pressure gathering rates as a result of annual CPI-based adjustments~~, partially offset by decreased throughput volumes of 3 Bcf, or 17 MMcf/d~~. Low pressure gathering volumes ~~decreased~~increased between periods primarily due to ~~natural~~78 ~~production~~additional ~~decline from~~ wells being connected to our system since December 31, 2024, partially offset by 51natural ~~additional~~production ~~wells~~decline ~~being~~of the wells connected to our system ~~since~~between ~~December 31, 2023~~periods.

● Compression revenue increased $616 million period over period primarily due to increased throughput volumes of 750 Bcf, or 9146 MMcf/d, and increased compression rates as a result of annual CPI-based adjustments. Compression volumes increased between periods primarily due to 5178 additional wells being connected to our system since December 31, ~~2023~~2024, ~~and~~partially ~~two~~offset ~~compressor~~by ~~stations~~natural ~~that~~production ~~were~~decline ~~acquired~~of ~~during~~ the ~~second~~wells ~~quarter~~connected ofto ~~2024~~our system between periods.

● High pressure gathering revenue increased $1921 million period over period primarily due to increased throughput volumes of 3455 Bcf, or 86160 MMcf/d, ~~our acquisition of 48 miles of high pressure gathering lines during the second quarter of 2024~~ and increased high pressure gathering rates as a result of an annual CPI-based ~~adjustment~~adjustments. ~~The~~High ~~high~~ pressure gathering volumes increased ~~period~~between ~~over~~periods ~~period~~ primarily due to 5178 additional wells being connected to our ~~high pressure~~ system since December 31, ~~2023~~2024, partially offset by natural production decline of the wells connected to our system between periods.

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Water Handling

● Fresh water delivery revenue ~~decreased~~increased $165 million period over period primarily due to ~~decreased~~increased fresh water delivery volumes of 41 MMBbl, or 122 MBbl/d, ~~partially~~and ~~offset by~~ an increase to the fresh water delivery rate ~~for our long-term contract with Antero Resources~~ as a result of ~~the~~an annual CPI-based adjustment. Fresh water delivery volumes ~~decreased~~increased between periods due to ~~fewer~~the increase in wells serviced by our fresh water delivery system as a result of the timing of well completions by Antero Resources.

● Other fluid handling services revenue ~~decreased~~increased $416 million period over period primarily due to ~~decreased~~increased ~~wastewater~~other fluid handling ~~services~~volumes ~~and~~of ~~lower~~1 ~~high~~MMBbl, ~~rate~~or ~~transfer~~3 ~~volumes~~MBbl/d, ~~during~~as ~~the~~a ~~year~~result ~~ended~~of ~~December~~higher ~~31,~~wastewater ~~2024~~trucking and blending volumes, ~~partially~~as ~~offset~~well byas higher costs that are billed at cost plus 3% and blending cost of service fees between periods.

Direct operating expenses. Direct operating expenses increased by 26%, from $~~213~~218 million for the year ended December 31, ~~2023~~2024 to $~~218~~232 million for the year ended December 31, ~~2024~~2025. Gathering and processing direct operating expenses increased by 85% from $96103 million for the year ended December 31, ~~2023~~2024 to $~~103~~108 million for the year ended December 31, ~~2024~~2025 primarily due to increased ~~high pressure~~ gathering and compression volumes, ~~between~~higher ~~periods~~costs ~~and~~for ~~our~~the ~~acquisition of~~ two compressor stations and 48 miles of high pressure gathering lines acquired during the second quarter of 2024 and increased heavy maintenance expense between periods. Water handling direct operating expenses ~~decreased~~increased by 28%, from $~~117~~115 million for the year ended December 31, ~~2023~~2024 to $~~115~~124 million for the year ended December 31, ~~2024~~2025 primarily due to ~~decreased~~increased ~~fresh water and~~ other fluid handling volumes ~~between periods~~, ~~partially~~higher ~~offset~~wastewater bytrucking ~~increased~~and ~~pipeline~~disposal ~~maintenance~~costs, ~~repair~~ and ~~monitoring~~increased ~~activities~~blending costs between periods.

General and administrative (excluding equity-based compensation) expenses. General and administrative expenses (excluding equity-based compensation expense) ~~increased~~remained byconsistent ~~6%,~~at ~~from~~ $~~39 million for the year ended December 31, 2023 to $~~42 million for the year ended December 31, 2024 ~~primarily~~and ~~due~~2025, ~~to higher costs allocated to us from Antero Resources~~respectively.

Equity-based compensation expenses. Equity-based compensation expenses ~~increased~~remained byrelatively ~~40%~~consistent ~~from~~at $3244 million ~~for~~and ~~the year ended December 31, 2023 to~~ $4446 million for the year ended December 31, 2024 ~~primarily~~and ~~due~~2025, ~~to annual equity-based awards granted during the first quarter of 2024~~respectively. ~~Our equity-based awards vest over three or four year service periods.~~ See Note 1011—Equity-Based Compensation to our consolidated financial statements for additional information.

Depreciation expense. Depreciation expense ~~increased~~decreased by 34%, from $~~136~~140 million for the year ended December 31, ~~2023~~2024 to $~~140~~134 million for the year ended December 31, ~~2024. This~~2025 ~~increase was~~ primarily due to lower depreciation expense of $5 11 million related to ~~assets~~our ~~placed~~program into ~~service~~repurpose ~~between~~underutilized ~~periods~~compressor ~~and~~units ~~$1 million~~to ~~for~~expand ~~our~~existing ~~assets~~or ~~acquired~~construct ~~during~~new ~~the~~compressor ~~second~~stations ~~quarter~~between ~~of 2024~~periods, partially offset by depreciation expense of $2 4 million ofrelated ~~lower~~to ~~expense~~assets placed in service between periods ~~related~~and tohigher ~~our~~depreciation ~~program~~expense toof ~~repurpose~~$1 ~~underutilized~~million ~~compressor~~for ~~units~~our toassets ~~expand~~acquired ~~existing~~during orthe ~~construct~~second ~~new~~quarter ~~compressor~~of ~~stations~~2024.

Loss on ~~asset~~long-lived ~~sale~~assets. ~~Loss~~During the year ended December 31, 2025, we recognized a loss on ~~asset~~long-lived ~~sale~~assets of $687 million ~~and~~related ~~$1 million~~to the write-down of our Utica Shale net assets held for sale to the ~~years~~cash consideration expected to be received in the Utica Shale Divestiture less costs to sell. There was no loss on long-lived assets during the year ended December 31, ~~2023 and~~ 2024,. See ~~respectively,~~Note ~~was~~3—Transactions ~~primarily~~to ~~due~~our toconsolidated ~~sales~~financial ofstatements ~~miscellaneous~~for ~~equipment~~additional information.

Interest expense. Interest expense decreased by 58%, from $~~217~~207 million for the year ended December 31, ~~2023~~2024 to $~~207~~190 million for the year ended December 31, ~~2024~~2025 primarily due to lower ~~Credit~~interest ~~Facility~~expense ~~borrowings~~on ~~between~~our ~~periods~~senior ~~and~~notes due to the repurchase and redemption of ~~$550~~the ~~million~~7.875% ~~principal~~senior ~~amount~~notes ofdue May 15, 2026 (the “2026 Notes”) during the year ended December 31, 2024, and the redemption of the 2027 Notes during the year ended December 31, 2025, as well as lower interest rates on our Credit Facility between periods, partially offset by the ~~issuance~~issuances of ~~$600~~the ~~million~~6.625% ~~principal~~senior ~~amount~~notes ofdue February 1, 2032 (the “2032 Notes”), ~~during~~2033 ~~the~~Notes ~~year~~and ~~ended~~2034 ~~December 31,~~Notes ~~2024~~and higher average 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~~111 million for the year ended December 31, ~~2023~~2024 to $~~111~~116 million for the year ended December 31, ~~2024~~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 ~~repurchased~~recognized ora ~~otherwise~~loss ~~fully~~on ~~redeemed~~early ~~the~~extinguishment of debt of $~~550~~14 million ~~aggregate~~related ~~principal~~to ~~amount~~the premium paid to repurchase or otherwise fully redeem all of our 2026 Notes at a weighted average premium of 101.975% of the principal amount thereof, plus accrued and unpaid interest, ~~and~~as ~~recognized~~well aas ~~loss~~the onwrite-off ~~early~~of ~~debt~~unamortized ~~extinguishment~~deferred offinancing ~~$14 million~~costs. ~~There~~During ~~was~~the noyear ended December 31, 2025, we recognized a loss on early extinguishment of debt ~~for~~of $1 million related to the ~~year~~write-off ~~ended~~of ~~December 31~~unamortized deferred financing costs and premium attributable to our 2027 Notes that were fully redeemed at par, ~~2023~~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% from $128 million for the year ended December 31, 2023 to $148 million for the year ended December 31, 2024, which reflects effective tax rates of 25.7% and 26.9%, respectively. This income tax expense increase was primarily due to higher pre-tax income between periods. The increase in our effective tax rate between periods was primarily due to changes in apportionment of state income taxes during the year ended December 31, 2024.49

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~~Year~~Transaction ~~Ended~~expense. During the year ended December 31, ~~2022~~2025, ~~Compared~~we incurred $5 million of transaction expense related to ~~Year~~the ~~Ended~~HG Acquisition. There were no transaction expenses during the year ended December 31, ~~2023~~2024. See Note 3—Transactions to our consolidated financial statements for additional information.

~~See~~Income ~~“Item 7~~tax expense. ~~Management’s~~ Income ~~Discussion~~tax ~~and~~expense ~~Analysis~~increased ofby ~~Financial~~2%, ~~Condition~~from ~~and~~$148 ~~Results~~million offor ~~Operations~~the ~~—Results~~year ofended ~~Operations”~~December 31, in2024 ~~our~~to ~~2023~~$151 million ~~Annual~~for ~~Report~~the onyear ~~Form~~ended ~~10-K~~December 31, ~~for~~2025, awhich ~~discussion~~reflects ofeffective ~~the~~tax ~~results~~rates of ~~operations~~26.9% ~~for~~and ~~the~~26.8%, ~~year~~respectively. This ~~ended~~income ~~December 31,~~tax ~~2022~~expense ~~compared~~increase was primarily due to ~~the~~higher ~~year~~income ~~ended~~before ~~December~~income ~~31,~~taxes ~~2023~~between periods. See Note 8—Income Taxes to our consolidated financial statement for additional information.

Year Ended December 31, 2023 Compared to Year Ended December 31, 2024

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” in our 2024 Annual Report on Form 10-K for a discussion of the results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2024.

Capital Resources and Liquidity

Sources and Uses of Cash

Capital resources and liquidity are provided by operating cash flows, available borrowings under our Credit Facility, 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.

During the year ended December 31, ~~2024~~2025, we paid dividends of $0.90 per share, or a total of $~~438~~439 million, to holders of our common stock, as applicable, and we paid $550,000 of dividends on our Series A Preferred Stock. On January 14, ~~2025~~2026, the Board declared a cash dividend on the shares of our common stock of $0.2250 per share for the quarter ended December 31, ~~2024~~2025. The dividend was paid on February 1211, ~~2025~~2026 to stockholders of record as of January 2928, ~~2025~~2026. Our Board also declared a cash dividend of $137,500 on our Series A Preferred Stock that will be paid on February 1417, ~~2025~~2026 in accordance with their terms. As of December 31, ~~2024~~2025, there were dividends in the amount of $68,750 accumulated in arrears on our Series A Preferred Stock. See Note 1112—Cash Dividends and Note 1213—Equity and Net Income Per Common Share to our consolidated financial statements for additional information.

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 operations, orthe net proceeds from the offering of the 2034 Notes, proceeds from our Utica Shale Divestiture and borrowings under the Credit Facility.

As of December 31, ~~2024~~2025, we did not have any off-balance sheet arrangements.

Cash Flows

The following table summarizes our cash flows for the years ended December 31, ~~2023~~2024 and ~~2024~~2025:


	Year Ended December 31,
(in thousands)	~~2023~~2024		~~2024~~2025
Net cash provided by operating activities	$	~~779~~843,~~063~~994		~~843~~932,~~994~~464
Net cash used in investing activities		(~~183~~242,~~206~~733)		(~~242~~169,~~733~~212)
Net cash used in financing activities		(~~595~~601,~~791~~327)		(~~601~~500,~~327~~317)
Net increase (decrease) in cash and cash equivalents	$	66		(66)
Net increase (decrease) in cash, cash equivalents and restricted cash	$	(66)		262,935

Year Ended December 31, ~~2023~~2024 Compared to Year Ended December 31, ~~2024~~2025

Operating ~~Activities~~activities. Net cash provided by operating activities was $~~779~~844 million and $~~844~~932 million for the years ended December 31, ~~2023~~2024 and ~~2024~~2025, respectively. ~~The~~This increase in cash flows provided by ~~operations~~operating activities between periods was primarily due to higher gathering and processing ~~revenues~~ and ~~increased~~water ~~distributions~~handling ~~from~~revenues ~~our~~and ~~equity~~changes ~~method~~in ~~investments~~working ~~during the year ended December 31~~capital, ~~2024,~~ partially offset by ~~lower~~increased ~~water~~direct ~~handling~~operating ~~revenues~~expenses between periods. ~~See~~ “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” for additional information on the period over period changes in our gathering and processing and water handling revenues.

Investing Activities. Net cash used in investing activities was $183 million and $243 million for the years ended December 31, 2023 and 2024, respectively. The increase in cash used in investing activities between periods was primarily due to our acquisition of gathering and compression assets during the second quarter of 2024 of $70 million, before closing adjustments, and increased capital spending for our gathering systems and facilities of $12 million, partially offset by decreased capital spending for our water handling systems of $23 million between periods. During the year ended December 31, 2023, we expanded our gathering systems and facilities by building 17 miles of pipeline and adding capacity to one existing compressor station and water handling systems by building buried and surface pipelines of 6 miles and 9 miles, respectively. During the year ended December 31, 2024, we expanded our gathering systems and facilities by building 29 miles of pipeline and one new compressor station and water handling systems by building buried and surface pipelines of 1 mile and 17 miles, respectively.50

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~~Financing~~Investing ~~Activities~~activities. Net cash flows used in ~~financing~~investing activities was $~~596~~ 243 million and $~~601~~169 million for the years ended December 31, ~~2023~~2024 and ~~2024~~2025, respectively. The ~~increase~~decrease in cash flows used in ~~financing~~investing activities between periods was primarily due to our ~~repurchases~~acquisition of gathering and ~~redemption~~compression ofassets during the ~~2026~~second ~~Notes~~quarter of 2024 of $~~561~~70 million, ~~repurchases~~before ofclosing ~~approximately~~adjustments, 2and lower capital spending related to our gathering systems and facilities of $50 million, ~~shares~~partially ofoffset by higher capital spending on our ~~common~~water ~~stock~~handling ~~for~~systems of $2940 million and ~~payments~~additional investment in Stonewall of $4 million between periods. The decreased capital spending for ~~the~~our ~~2032~~gathering ~~Notes~~systems and ~~New~~facilities ~~Credit~~is ~~Facility~~primarily ~~deferred~~due ~~financing~~to ~~costs~~decreased high pressure pipeline projects of ~~$13 million~~7 ~~during~~miles ~~the~~in ~~year~~West ~~ended~~Virginia. The ~~December 31,~~increased ~~2024,~~capital ~~partially~~spending ~~offset~~for byour ~~the~~water ~~issuance~~handling ofsystems ~~the~~is ~~2032~~primarily ~~Notes~~due ofto ~~$600~~increased ~~million~~surface ~~during~~pipeline ~~the~~projects ~~year~~of ~~ended~~8 ~~December 31,~~miles ~~2024~~in West Virginia.

~~Year~~Financing ~~Ended~~activities. Net cash used in financing activities was $601 million and $500 million for the years ended December 31, ~~2022~~2024 ~~Compared~~and 2025, respectively. The decrease in cash flows used in financing activities between periods was primarily due to ~~Year~~the ~~Ended~~issuance ~~December 31~~of our 2034 Notes of $600 million for the HG Acquisition, ~~2023~~partially offset by increased net repayments on our Credit Facility of $339 million, increased repurchases of common stock of $106 million, lower cash provided from the refinancing of our 2026 Notes with our 2032 Notes of $39 million and higher employee tax withholdings for the settlement of equity-based compensation awards of $13 million.

~~See~~Year ~~“Item 7. Management’s~~Ended ~~Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended~~ December 31, 2023 ~~for~~Compared ~~a discussion of the cash flows for the year ended December 31, 2022 compared~~ to ~~the~~Year ~~year~~Ended ~~ended~~ December 31, ~~2023.~~2024

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2024 for a discussion of the cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2024.

Capital Investments

Our capital expenditures were as follows:


	Year Ended December 31,
(in thousands)	~~2023~~2024		~~2024~~2025
Gathering systems and facilities	$	~~132~~131,~~112~~920		~~131~~91,~~920~~115
Water handling systems		5227,~~620~~011		2780,~~011~~937
Investments in unconsolidated affiliates		~~262~~2,393		26,~~393~~653
Total capital expenditures	$	~~184~~161,~~994~~324		~~161~~178,~~324~~705

On February 1211, ~~2025~~2026, we announced a ~~2025~~2026 capital budget with a range of $~~170~~ 190 million to $~~200~~ 220 million. ~~This~~Our capital budget ~~supports~~reflects ~~Antero~~the ~~Resources’~~closing ~~maintenance~~of ~~capital~~the ~~program~~HG ~~for~~Acquisition ~~2025. Our~~on ~~capital~~February ~~budgets may be adjusted as business conditions warrant. If natural gas~~3, ~~NGLs~~2026 and ~~oil~~assumes ~~prices~~the ~~decline~~closing ~~to levels below acceptable levels or costs increase to levels above acceptable levels, Antero Resources could choose to defer a significant portion~~ of ~~its~~the ~~budgeted~~Utica ~~capital~~Shale ~~expenditures~~Divestiture ~~until~~during ~~later~~February ~~periods~~2026. AsOur acapital ~~result,~~budgets we may ~~also~~be ~~defer~~adjusted aas ~~significant~~business ~~portion~~conditions 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 flowswarrant. 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.

Debt Agreements

We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases ~~and/or exchanges for equity securities~~, 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, ~~2023~~2024 and ~~2024~~2025. The amounts involved could be material. See Note 89—Long-Term Debt to our consolidated financial statements for additional information.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. Any new accounting policies or updates to existing accounting policies as a result of recently adopted accounting standards have been included in Note 2—Summary of Significant Accounting Policies to our consolidated financial statements. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent liabilities. Accounting estimates and assumptions are considered to be critical if there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the reported amounts in our consolidated financial statements that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements.

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be reasonable under the circumstances, the results of which form the basis for making judgments about the reported amounts in our consolidated financial statements that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements.

Property and Equipment

Property and equipment primarily consists of gathering pipelines, compressor stations and the water handling assets. We evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are calculated using the expected present value of future cash flows method. Significant assumptions used in the cash flow forecasts include future net operating margins, future volumes, discount rates and future capital requirements.

Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property and equipment. Uncertainties that may impact these estimates of useful lives include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions and supply and demand for the Company’s services in the areas in which it operate. Historically, we have not experienced material changes in our results of operations from revisions to the estimated useful lives or salvage values of our property and equipment. However, these estimates are reviewed periodically and can be subject to revision as circumstances warrant. We believe that the estimates and assumptions related to depreciation expense are critical because the assumptions used to estimate useful lives and salvage values of property and equipment are susceptible to change as circumstances warrant. These assumptions affect depreciation expense and, if changed, could have a material effect on the Company's results of operations and financial position.

Income Taxes

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.

We record a valuation allowance when we believe all or a portion of our deferred income tax assets will not be realized. In assessing the realizability of our deferred income tax assets, management considers whether some portion or all of the deferred income tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred income tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred income tax assets are deductible. Management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income and tax planning strategies in making this assessment, estimates of which may be imprecise due to unforeseen future events or conditions outside of our control, including changes in Antero Resources’ production or development plans or changes to tax laws and regulations. The amount of deferred income tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change.

The calculation of deferred income tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations. We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the IRS or state revenue authorities. We believe that the estimates and assumptions related to income taxes are critical because the assumptions and estimates required to assess the likelihood that our deferred income tax assets will be recovered from future taxable income, as well as the amount and timing of a valuation allowance on our deferred income tax assets is an exercise in judgement and susceptible to change as circumstances warrant. These assumptions affect deferred income tax liability and income tax expense and, if changed, could have a material effect on the Company's financial position and results of operations.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

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Commodity Price Risk

Our gathering and compression and water services agreements with Antero Resources provide for fixed-fee and cost of service fee structures, and we intend to continue to pursue additional fixed-fee or cost of service fee opportunities with Antero Resources and third parties in order to avoid direct commodity price exposure. However, to the extent that our future contractual arrangements with Antero Resources or third parties do not provide for fixed-fee or cost of service fee structures, we may become subject to commodity price risk. We are subject to commodity price risks to the extent that they impact Antero Resources’ development program and production and therefore our gathering, compression and water handling volumes. We cannot predict to what extent our business would be impacted by lower commodity prices and any resulting impact on Antero Resources’ operations.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under the Credit Facility, which has a floating interest rate. We do not currently, but may in the future, hedge the interest on portions of our borrowings under the Credit Facility from time-to-time in order to manage risks associated with floating interest rates. As of December 31, ~~2024~~2025, we had ~~$484 million~~no ofoutstanding borrowings ~~and~~or no letters of credit ~~outstanding~~ under the ~~New~~ Credit Facility. A 1.0% increase in the Credit Facility interest rate would have resulted in an estimated $45 million increase in interest expense for the year ended December 31, ~~2024~~2025.

Credit Risk

We are dependent on Antero Resources as our primary customer, and we expect to derive substantially all of our revenues from Antero Resources for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Antero Resources’ production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and operating results.

Item 8. Financial Statements and Supplementary Data

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page F-2 of this Annual Report on Form 10-K and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, ~~2024~~2025 at a reasonable assurance level.

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Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended December 31, ~~2024~~2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Our internal control over financial reporting includes those policies and procedures that:

(i)

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets;

(ii)

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

(iii)

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect all misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.

Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control—Integrated Framework in 2013, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, ~~2024~~2025.

The effectiveness of our internal control over financial reporting as of December 31, ~~2024~~2025 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 in this Annual Report on Form 10-K.

Item 9B. Other Information

~~None~~In connection with the HG Acquisition, we entered into a letter agreement with Antero Resources to, among other things, allocate between the parties certain obligations, liabilities, costs and benefits under the purchase agreement relating to the HG Acquisition and the buyer-side representations and warranties insurance policies. A copy of the Letter Arrangement is filed as Exhibit 10.28 hereto and is incorporated herein by reference.

On November 6, 2025, Michael N. Kennedy, our Chief Executive Officer and President and Director, adopted a “Rule 10b5-1 trading arrangement,” as defined in Item 408(a) of Regulation S-K, that is intended to satisfy the affirmative defense of Rule 10b5-1(c) for the sale of up to 100,000 shares of the Company’s common stock until December 31, 2026.

Item 9C. disclosure regarding foreign jurisdictions that prevent inspections

Not applicable.

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PART III

Item 10. Directors, Executive Officers, and Corporate Governance

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our ~~2025~~2026 Annual Meeting of Stockholders.

Code of Ethics

We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of our Corporate Code of Business Conduct and Ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and other persons performing similar functions by posting such information in the “Governance” subsection of our website at www.anteromidstream.com.

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Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related STOCKHOLDER Matters

Item 13. Certain Relationships and Related Transactions and Director Independence

Item 14. Principal Accountant Fees and Services

Our independent registered accounting firm is KPMG LLP, Denver, CO, Auditor Firm ID: 185.

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PART IV

Item 15. Exhibit and Financial Statement Schedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

The consolidated financial statements are listed on the Index to Financial Statements to this Annual Report on Form 10-K beginning on page F-1.

(a)(3) Exhibits.

ExhibitNumber	Description of Exhibit
2.1	Simplification Agreement, dated as of October 9, 2018, by and among AMGP GP LLC, Antero Midstream GP LP, Antero IDR Holdings LLC, Arkrose Midstream Preferred Co LLC, Arkrose Midstream NewCo Inc., Arkrose Midstream Merger Sub LLC, Antero Midstream Partners GP LLC and Antero Midstream Partners LP (incorporated by reference to Exhibit 2.1 to Antero Midstream GP LP’s Current Report on Form 8-K (Commission File No. 001-38075) filed on October 10, 2018).
3.1	Certificate of Conversion of Antero Midstream Corporation, dated March 12, 2019 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
3.2	Certificate of Incorporation of Antero Midstream Corporation, dated March 12, 2019 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
3.3	Certificate of Amendment to Certificate of Incorporation of Antero Midstream Corporation, dated June 8, 2023 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 8, 2023).
3.4	~~Amended~~Certificate ~~and~~of ~~Restated~~Designations ~~Bylaws~~ of Antero Midstream Corporation, dated ~~February~~March 1412, ~~2023~~2019 (incorporated by reference to Exhibit 3.31 to the Company’s ~~Annual~~Current Report on Form 108-K (Commission File No. 001-38075) filed on ~~February~~March 1512, ~~2023~~2019).
3.5	~~Certificate~~Second ofAmended ~~Designations~~and Restated Bylaws of Antero Midstream Corporation, dated ~~March~~August 1214, ~~2019~~2025 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on ~~March~~August 1214, ~~2019~~2025).
4.1	Indenture, dated as of June 28, 2019, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 28, 2019).
4.2	Form of 5.75% Senior Note due 2028 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 28, 2019).
4.3	Registration Rights Agreement, dated March 12, 2019, by and among the Company, Antero Resources Corporation, Arkrose Subsidiary Holdings LLC, Glen C. Warren, Jr., Canton Investment Holdings LLC, Paul M. Rady, Mockingbird Investments, LLC and the other holders named therein (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
4.4	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended (incorporated by reference to Exhibit 4.9 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 14, 2024).
4.5	Indenture, dated June 8, 2021, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 8, 2021).

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4.1	Indenture, dated as of February 25, 2019, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on February 25, 2019).
4.6	Form of 5.375% Senior Note due 2029 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 8, 2021).
4.2	Form of 5.75% Senior Note due 2027 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on February 25, 2019).
4.7	Indenture, dated as of January 16, 2024, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Computer Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on January 16, 2024).
4.3	First Supplemental Indenture, dated as of April 15, 2019, among Antero Midstream Partners LP, Antero Midstream Finance Corporation, Antero Midstream Corporation, each of the other parties identified therein and Wells Fargo Bank, National Association, a national banking association, to the indenture governing the 2027 Notes (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on April 16, 2019).
4.8	Form of 6.625% Senior Note due 2032 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on January 16, 2024).
4.4	Indenture, dated as of June 28, 2019, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 28, 2019).
4.9	Indenture, dated as of September 22, 2025, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on September 23, 2025).
4.5	Form of 5.75% Senior Note due 2028 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 28, 2019).
4.10	Form of 5.75% Senior Note due 2033 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on September 23, 2025).
4.6	Registration Rights Agreement, dated March 12, 2019, by and among the Company, Antero Resources Corporation, Arkrose Subsidiary Holdings LLC, Glen C. Warren, Jr., Canton Investment Holdings LLC, Paul M. Rady, Mockingbird Investments, LLC and the other holders named therein (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
4.11	Indenture, dated as of December 23, 2025, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on December 23, 2025).
4.7	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended (incorporated by reference to Exhibit 4.9 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 14, 2024).
4.12	Form of 5.75% Senior Note due 2034 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on December 23, 2025).
4.8	Indenture, dated June 8, 2021, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 8, 2021).
4.9	Form of 5.375% Senior Note due 2029 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 8, 2021).
4.10	Indenture, dated as of January 16, 2024, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Computer Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on January 16, 2024).
4.11	Form of 6.625% Senior Note due 2032 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on January 16, 2024).
10.1	Second Amended and Restated Gathering and Compression Agreement, dated as of December 8, 2019, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.2	Amended and Restated Secondment Agreement, effective as of March 13, 2019, by and between Antero Midstream Corporation, Antero Midstream Partners LP, Antero Midstream Partners GP LLC, Antero Midstream LLC, Antero Water LLC, Antero Treatment LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.3	Second Amended and Restated Services Agreement, effective as of March 13, 2019, by and among Antero Midstream Partners LP, Antero Midstream Corporation, Antero Midstream Partners GP LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.4**	Amended and Restated Water Services Agreement, dated as of February 12, 2019, by and between Antero Resources Corporation and Antero Water LLC (incorporated by reference to Exhibit 10.4 to Antero Midstream Partners LP’s Annual Report on Form 10-K (Commission File No. 001-36719) filed on February 13, 2019).
10.5	Amended and Restated Contribution Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.6	Second Amended and Restated Right of First Offer Agreement, dated as of February 13, 2018, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.2 to Antero Midstream Partners LP’s Quarterly Report on Form 10-Q (Commission File No. 001-36719) filed on April 25, 2018).
10.7	License Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.4 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.8	First Amendment and Joinder Agreement, dated as of October 31, 2018 (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 2, 2018).

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10.5	Amended and Restated Contribution Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.6	Second Amended and Restated Right of First Offer Agreement, dated as of February 13, 2018, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.2 to Antero Midstream Partners LP’s Quarterly Report on Form 10-Q (Commission File No. 001-36719) filed on April 25, 2018).
10.7	License Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.4 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.8	First Amendment and Joinder Agreement, dated as of October 31, 2018 (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 2, 2018).
10.9	Second Amendment, dated as of February 26, 2019, by and among the Lenders party thereto, Antero Midstream Partners LP, and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.10	Joinder Agreement, dated as of November 19, 2019, by and among the Lenders party thereto, Antero Midstream Partners LP, and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.11	Second Amended and Restated Credit Facility, dated as of October 26, 2021, by and among Antero Midstream Partners LP, as Borrower, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on October 27, 2021).
10.12†	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
10.13†	Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement under the Antero Midstream Corporation Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on July 31, 2019).
10.14†	Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement under the Antero Midstream Corporation Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on July 27, 2022).
10.15†	Form of Stock Award Grant Notice and Stock Award Agreement (Form for Non-Employee Directors) under the Antero Midstream Corporation Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on April 26, 2023).
10.16	Stockholders’ Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP, Arkrose Subsidiary Holdings LLC, Paul M. Rady, Mockingbird Investment, LLC, Glen C. Warren, Jr., Canton Investment Holdings LLC and the other holders named therein (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on October 10, 2018).
10.17†	Amended and Restated Antero Midstream Corporation Long Term Incentive Plan, dated June 5, 2024 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 6, 2024).
10.18	Third Amended and Restated Credit Agreement, dated July 30, 2024, among Antero Midstream Partners LP, as the Borrower, the Lenders party thereto and Wells Fargo Banks, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on July 31, 2024).
19.1*	Antero Midstream Corporation Insider Trading Policies.
10.19*	First Amendment to the Third Amended and Restated Credit Agreement, dated December 11, 2025, among Antero Midstream Partners LP, as the Borrower, the Lenders party thereto and Wells Fargo Banks, National Association, as Administrative Agent.
21.1*	Subsidiaries of Antero Midstream Corporation.
10.20†	Chairman Emeritus Agreement, by and between Antero Resources Corporation, Antero Midstream Corporation and Paul Rady, dated August 14, 2025 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on August 14, 2025).
10.21†	Antero Midstream Corporation Executive Severance Plan, effective September 17, 2025 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on September 23, 2025).
10.22†*	Form of Antero Resources Corporation Executive Severance Plan Participation Agreement.
10.23†*	Antero Resources Corporation Executive Severance Plan Participation Agreement, by and between Antero Resources Corporation and Paul Rady, dated October 2, 2025.
10.24	Antero Midstream Corporation Summary of Compensation for Non-Employee Directors, effective August 14, 2025 (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on October 29, 2025).

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10.25***	Membership Interest Purchase Agreement, by and among HG Energy II LLC, HG Energy II Production Holdings, LLC, HG Energy II Midstream Holdings, LLC, Antero Resources Corporation and Antero Midstream Partners LP, dated as of December 5, 2025 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on December 8, 2025).
10.26***	Amendment No. 1 to the Membership Interest Purchase Agreement, by and among HG Energy II LLC, HG Energy II Production Holdings, LLC, HG Energy II Midstream Holdings, LLC, Antero Resources Corporation and Antero Midstream Partners LP, dated as of December 22, 2025 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on February 3, 2026).
10.27***	Purchase and Sale Agreement, among Antero Midstream LLC, Antero Water LLC, Antero Treatment LLC, Infinity Natural Resources LLC and Northern Oil and Gas, Inc., dated December 5, 2025 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on December 8, 2025).
10.28***	Letter Agreement, by and between Antero Midstream Partners LP and Antero Resources Corporation, effective as of December 5, 2025.
19.1	Antero Midstream Corporation Insider Trading Policies (incorporated by reference to Exhibit 19.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2025).
21.1*	Subsidiaries of Antero Midstream Corporation.
23.1*	Consent of KPMG LLP.
31.1*	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
97.1	Antero Midstream Corporation Incentive Compensation Recovery Policy (incorporated by reference to Exhibit 97.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 14, 2024).
101*	The following financial information from this Form 10-K of Antero Midstream Corporation for the year ended December 31, ~~2024~~2025, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.
104*	Cover Page Interactive Data File (embedded within the Inline XBRL document).

The exhibits marked with the asterisk symbol (*) are filed or furnished with this Annual Report on Form 10-K.

**	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

†*** ~~Management~~Certain ~~contract~~of orthe ~~compensatory~~schedules ~~plan~~and exhibits to the Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or ~~arrangement~~exhibit will be furnished to the U.S. Securities and Exchange Commission upon request. Certain personally identifiable information has also been omitted from this Exhibit pursuant to Item 601(a)(6) of Regulation S-K.

†	Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


ANTERO MIDSTREAM CORPORATION

By:	/s/ ~~BRENDAN~~Justin EJ. ~~KRUEGER~~Agnew
	~~Brendan~~Justin EJ. ~~Krueger~~Agnew
	Chief Financial Officer, and Vice President – Finance and ~~Treasurer~~Investor Relations

Date:	February 1211, ~~2025~~2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.


Signature	Title	Date

	Chairman of the Board, Director,
/s/ PAUL M. RADY	President and Chief Executive Officer	February 12, 2025
Paul M. Rady	(principal executive officer)

	Chief Financial Officer,
/s/ BRENDAN E. KRUEGER	Vice President – Finance and Treasurer	February 12, 2025
Brendan E. Krueger	(principal financial officer)

	Senior Vice President – Accounting and
/s/ SHERI L. PEARCE	Chief Accounting Officer	February 12, 2025
Sheri L. Pearce	(principal accounting officer)

/s/ MICHAEL N. KENNEDY	Director and Senior Vice President – Finance	February 12, 2025
Michael N. Kennedy

/s/ NANCY E. CHISHOLM	Director	February 12, 2025
Nancy E. Chisholm

/s/ PETER A. DEA	Director	February 12, 2025
Peter A. Dea

/s/ W. HOWARD KEENAN, JR.	Director	February 12, 2025
W. Howard Keenan, Jr.

/s/ DAVID H. KEYTE	Director	February 12, 2025
David H. Keyte

/s/ BROOKS J. KLIMLEY	Director	February 12, 2025
Brooks J. Klimley

/s/ JANINE J. MCARDLE	Director	February 12, 2025
Janine J. McArdle

/s/ JOHN C. MOLLENKOPF	Director	February 12, 2025
John C. Mollenkopf

/s/ JEFFREY S. MUÑOZ	Director	February 12, 2025
Jeffrey S. Muñoz

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Signature	Title	Date


/s/ Michael N. Kennedy	Director, Chief Executive Officer and President	February 11, 2026
Michael N. Kennedy	(principal executive officer)

	Chief Financial Officer and
/s/ Justin J. Agnew	Vice President – Finance and Investor Relations	February 11, 2026
Justin J. Agnew	(principal financial officer)

	Senior Vice President – Accounting and
/s/ Sheri L. Pearce	Chief Accounting Officer	February 11, 2026
Sheri L. Pearce	(principal accounting officer)

/s/ David H. Keyte	Chairman of the Board, Director	February 11, 2026
David H. Keyte

/s/ Nancy E. Chisholm	Director	February 11, 2026
Nancy E. Chisholm

/s/ Peter A. Dea	Director	February 11, 2026
Peter A. Dea

/s/ W. Howard Keenan, Jr.	Director	February 11, 2026
W. Howard Keenan, Jr.

/s/ Brooks J. Klimley	Director	February 11, 2026
Brooks J. Klimley

/s/ Janine J. McArdle	Director	February 11, 2026
Janine J. McArdle

/s/ John C. Mollenkopf	Director	February 11, 2026
John C. Mollenkopf

/s/ Jeffrey S. Muñoz	Director	February 11, 2026
Jeffrey S. Muñoz

/s/ Yvette K. Schultz	Director	February 11, 2026
Yvette K. Schultz

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Audited Consolidated Financial Statements as of December 31, 2023 and 2024 and for the Years Ended December 31, 2022, 2023 and 2024
Audited Consolidated Financial Statements as of December 31, 2024 and 2025 and for the Years Ended December 31, 2023, 2024 and 2025
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-4
Consolidated Statements of Operations and Comprehensive Income	F-5
Consolidated Statements of Stockholders’ Equity	F-6
Consolidated Statements of Cash Flows	F-7
Notes to Consolidated Financial Statements	F-8

F-1

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors
Antero Midstream Corporation:

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Antero Midstream Corporation and subsidiaries (the Company) as of December 31, ~~2023~~2024 and ~~2024~~2025, the related consolidated statements of operations and comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, ~~2024~~2025, and the related notes (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, ~~2023~~2024 and ~~2024~~2025, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, ~~2024~~2025, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2024~~2025 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of impairment triggering events for long-lived assets

As discussed in Note 2 to the consolidated financial statements, the Company evaluates property and equipment (collectively, long-lived assets) for impairment whenever events or changes in circumstances indicate that the related carrying values may not be recoverable (triggering events). The carrying value of property and equipment as of December 31, ~~2024~~2025 was $43.5 billion.

We identified the evaluation of impairment triggering events for long-lived assets as a critical audit matter. A higher degree of subjective auditor judgment was required to assess whether events or changes in circumstances indicate carrying values may not be recoverable.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of an internal control related to the long-lived assets impairment process. This included a control related to the Company’s process to identify and assess impairment triggering events for long-lived assets and the underlying quantitative data used to perform the analysis. We evaluated the Company’s identification of impairment triggering events for long-lived assets and responses to the factors considered by:

●

evaluating overall macro-economic conditions

●

analyzing historical financial results for long-lived assets to identify significant degradations in the related cash flows

●

evaluating the minimum volume commitments with Antero Resources Corporation and their impact on the recoverability of the long-lived assets

●

examining external information on certain of the Company’s customers’ drilling plans to assess continued development.

/s/ KPMG LLP

We have served as the Company’s auditor since 2016.

Denver, Colorado

February 1211, ~~2025~~2026

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ANTERO MIDSTREAM CORPORATION

Consolidated Balance Sheets

(In thousands, except per share amounts)


	December 31,
	~~2023~~2024		~~2024~~2025
Assets
Current assets:
Cash and cash equivalents	$	66—		—180,435
Accounts receivable–Antero Resources		88,610		115,180
Restricted cash		—		82,500
Accounts receivable–third party		952		832
Accounts receivable–Antero Resources		115,180		106,771
Other current assets		1,500		2,052
Accounts receivable–third party		832		993
Total current assets		91,128		118,064
Income tax receivable		—		1,896
Current assets held for sale		—		4,600
Other current assets		2,052		2,669
Total current assets		118,064		379,864
Long-term assets:
Property and equipment, net		3,~~793~~881,~~523~~621		3,~~881~~454,~~621~~572
Investments in unconsolidated affiliates		~~626~~603,~~650~~956		~~603~~585,~~956~~778
Customer relationships		1,~~215~~144,~~431~~759		1,~~144~~074,~~759~~087
Other assets, net		10,886		13,348
Assets held for sale		—		379,036
Total assets	$	5,737,618		5,761,748
Other assets, net		13,348		10,779
Total assets	$	5,761,748		5,884,116

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable–Antero Resources	$	4,~~457~~114		45,~~114~~366
Accounts payable–third party		1012,~~499~~308		1210,~~308~~368
Accrued liabilities		8083,~~630~~555		8391,~~555~~527
Other current liabilities		831		635
Current liabilities held for sale		—		2,297
Total current liabilities		96,417		100,612
Other current liabilities		635		1,924
Total current liabilities		100,612		111,482
Long-term liabilities:
Long-term debt		3,~~213~~116,~~216~~958		3,~~116~~222,~~958~~530
Deferred income tax liability, net		~~265~~413,~~879~~608		~~413~~562,~~608~~996
Other		10,375		15,399
Liabilities held for sale		—		3,021
Total liabilities		3,585,887		3,646,577
Other		15,399		12,046
Total liabilities		3,646,577		3,912,075
Stockholders' equity:
Preferred stock, $0.01 par value: 100,000 authorized as of December 31, 2023 and December 31, 2024
Preferred stock, $0.01 par value: 100,000 authorized as of December 31, 2024 and December 31, 2025
Series A non-voting perpetual preferred stock; 12 designated and 10 issued and outstanding as of December 31, 2023 and December 31, 2024		—		—
Series A non-voting perpetual preferred stock; 12 designated and 10 issued and outstanding as of December 31, 2024 and December 31, 2025		—		—
Common stock, $0.01 par value; 2,000,000 authorized; 479,713 and 479,422 issued and outstanding as of December 31, 2023 and December 31, 2024, respectively		4,797		4,794
Common stock, $0.01 par value; 2,000,000 authorized; 479,422 and 474,060 issued and outstanding as of December 31, 2024 and December 31, 2025, respectively		4,794		4,741
Additional paid-in capital		2,~~046~~019,~~487~~830		21,~~019~~952,~~830~~524
Retained earnings		~~100~~90,~~447~~547		9014,~~547~~776
Total stockholders' equity		2,~~151~~115,~~731~~171		21,~~115~~972,~~171~~041
Total liabilities and stockholders' equity	$	5,~~737~~761,~~618~~748		5,~~761~~884,~~748~~116

See accompanying notes to consolidated financial statements.

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ANTERO MIDSTREAM CORPORATION

Consolidated Statements of Operations and Comprehensive Income

(In thousands, except per share amounts)


	Year Ended December 31,
	~~2022~~2023		~~2023~~2024		~~2024~~2025
Revenue:
Gathering and compression–Antero Resources	$	~~743~~842,~~265~~362		~~842~~926,~~362~~063		~~926~~987,~~063~~284
Water handling–Antero Resources		~~244~~268,~~770~~667		~~268~~248,~~667~~858		~~248~~269,~~858~~399
Water handling–third party		21,~~622~~414		1,~~414~~944		12,~~944~~415
Amortization of customer relationships		(70,672)		(70,672)		(70,672)
Total revenue		~~919~~1,~~985~~041,771		1,~~041~~106,~~771~~193		1,~~106~~188,~~193~~426
Operating expenses:
Direct operating		~~180~~213,~~254~~165		~~213~~217,~~165~~976		~~217~~231,~~976~~910
General and administrative (including $19,654, $31,606 and $44,332 of equity-based compensation in 2022, 2023 and 2024, respectively)		62,125		71,068		86,086
General and administrative (including $31,606, $44,332 and $45,958 of equity-based compensation in 2023, 2024 and 2025, respectively)		71,068		86,086		87,934
Facility idling		42,~~166~~459		21,~~459~~721		1,~~721~~801
Depreciation		~~131~~136,~~762~~059		~~136~~140,~~059~~000		~~140~~134,~~000~~310
Impairment of property and equipment		~~3,702~~146		~~146~~332		~~332~~984
Accretion of asset retirement obligations		222		177		189
Loss on long-lived assets		—		—		86,626
Loss on settlement of asset retirement obligations		539		805		—
Other operating expense, net		7,012		912		192
Loss (gain) on asset sale		(2,251)		6,030		723
Total operating expenses		429,909		447,027		543,757
Total operating expenses		380,519		429,909		447,027
Operating income		611,862		659,166		644,669
Operating income		539,466		611,862		659,166
Other income (expense):
Interest expense, net		(~~189~~217,~~948~~245)		(~~217~~207,~~245~~027)		(~~207~~190,~~027~~404)
Equity in earnings of unconsolidated affiliates		94105,~~218~~456		~~105~~110,~~456~~573		~~110~~116,~~573~~439
Loss on early extinguishment of debt		—		—(14,091)		(141,~~091~~313)
Total other expense		(95,730)		(111,789)		(110,545)
Transaction expense		—		—		(5,195)
Income before income taxes		443,736		500,073		548,621
Total other expense		(111,789)		(110,545)		(80,473)
Income tax expense		(117,494)		(128,287)		(147,729)
Income before income taxes		500,073		548,621		564,196
Net income and comprehensive income	$	326,242		371,786		400,892
Income tax expense		(128,287)		(147,729)		(151,033)
Net income and comprehensive income	$	371,786		400,892		413,163

Net income per common share–basic	$	0.6877		0.7783		0.8386
Net income per common share–diluted	$	0.6877		0.7783		0.8386

Weighted average common shares outstanding:
Basic		~~478~~479,~~232~~378		~~479~~480,~~378~~822		~~480~~477,~~822~~906
Diluted		~~480~~482,~~300~~372		~~482~~485,~~372~~247		~~485~~482,~~247~~177

See accompanying notes to consolidated financial statements.

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ANTERO MIDSTREAM CORPORATION

Consolidated Statements of Stockholders’ Equity

(In thousands)


							Additional		~~Retained Earnings~~
	Preferred		Common Stock				Paid-In		~~(Accumulated~~Retained		Total
	Stock		Shares		Amount		Capital		~~Deficit)~~Earnings		Equity
Balance at December 31, 2021	$	—		477,495	$	4,775		2,414,398		(132,475)		2,286,698
Balance at December 31, 2022	$	—		478,497	$	4,785		2,104,740		82,793		2,192,318
Dividends to stockholders		—		—		—		(322,401)		(110,974)		(433,375)
Equity-based compensation		—		—		—		19,654		—		19,654
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes		—		1,002		10		(6,911)		—		(6,901)
Net income and comprehensive income		—		—		—		—		326,242		326,242
Balance at December 31, 2022		—		478,497		4,785		2,104,740		82,793		2,192,318
Dividends to stockholders		—		—		—		(81,352)		(354,132)		(435,484)
Equity-based compensation		—		—		—		31,606		—		31,606
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes		—		1,216		12		(8,507)		—		(8,495)
Net income and comprehensive income		—		—		—		—		371,786		371,786
Balance at December 31, 2023		—		479,713		4,797		2,046,487		100,447		2,151,731
Dividends to stockholders		—		—		—		(47,945)		(390,151)		(438,096)
Equity-based compensation		—		—		—		44,332		—		44,332
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes		—		1,611		16		(15,014)		—		(14,998)
Repurchases and retirement of common stock		—		(1,902)		(19)		(8,030)		(20,641)		(28,690)
Net income and comprehensive income		—		—		—		—		400,892		400,892
Balance at December 31, 2024	$	—		479,422	$	4,794		2,019,830		90,547		2,115,171
Dividends to stockholders		—		—		—		(53,665)		(386,003)		(439,668)
Equity-based compensation		—		—		—		45,958		—		45,958
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes		—		2,373		24		(27,626)		—		(27,602)
Repurchases and retirement of common stock		—		(7,735)		(77)		(31,973)		(102,931)		(134,981)
Net income and comprehensive income		—		—		—		—		413,163		413,163
Balance at December 31, 2025	$	—		474,060	$	4,741		1,952,524		14,776		1,972,041

See accompanying notes to consolidated financial statements.

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ANTERO MIDSTREAM CORPORATION

Consolidated Statements of Cash Flows

(In thousands)


	Year Ended December 31,
	~~2022~~2023		~~2023~~2024		~~2024~~2025
Cash flows provided by (used in) operating activities:
Net income	$	~~326~~371,~~242~~786		~~371~~400,~~786~~892		~~400~~413,~~892~~163
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		~~131~~136,~~762~~059		~~136~~140,~~059~~000		~~140~~134,~~000~~310
Accretion of asset retirement obligations		222		177		189
Impairment of property and equipment		146		332		984
Impairment of property and equipment		3,702		146		332
Deferred income tax expense		134,664		147,729		149,387
Deferred income tax expense		117,494		134,664		147,729
Equity-based compensation		31,606		44,332		45,958
Equity-based compensation		19,654		31,606		44,332
Equity in earnings of unconsolidated affiliates		(105,456)		(110,573)		(116,439)
Equity in earnings of unconsolidated affiliates		(94,218)		(105,456)		(110,573)
Distributions from unconsolidated affiliates		131,835		135,660		141,270
Distributions from unconsolidated affiliates		120,460		131,835		135,660
Amortization of customer relationships		70,672		70,672		70,672
Amortization of deferred financing costs		5,~~716~~979		56,~~979~~004		65,~~004~~255
Settlement of asset retirement obligations		(51,~~454~~258)		(~~1,258~~795)		(~~795~~467)
Loss on settlement of asset retirement obligations		539		805		—
Loss on early extinguishment of debt		—		14,091		1,313
Loss (gain) on asset sale		(2,251)		6,030		723
Loss on long-lived assets		—		—		86,626
Loss on early extinguishment of debt		—		—		14,091
Other operating activities		7,012		912		192
Changes in assets and liabilities:
Accounts receivable–Antero Resources		(32,~~354~~458)		(226,~~458~~571)		~~(26~~3,~~571)~~809
Accounts receivable–third party		~~723~~359		~~359~~748		~~748~~325
Income tax receivable		—940		~~940~~—		—(1,896)
Other current assets		(~~313~~2,041)		(~~2,041~~781)		(~~781~~737)
Accounts payable–Antero Resources		~~782~~(1,267)		(~~1,267~~54)		~~(54)~~1,141
Accounts payable–third party		(7,~~973~~766)		(73,~~766)~~722		3(2,~~722~~077)
Accrued liabilities		(747)		8,251		17,674
Income taxes payable		—		—		942
Net cash provided by operating activities		699,604		779,063		843,994
Accrued liabilities		8,251		17,674		(1,267)
Net cash provided by operating activities		779,063		843,994		932,464
Cash flows provided by (used in) investing activities:
Additions to gathering systems, facilities and other		(~~227~~130,~~561~~305)		(~~130~~141,~~305~~832)		(~~141~~91,~~832~~533)
Additions to water handling systems		(7153,~~363~~428)		(5330,~~428~~515)		(3070,~~515~~722)
Additional investments in unconsolidated affiliate		—(262)		(~~262~~2,393)		(26,~~393~~653)
Return of investment in unconsolidated affiliate		17,000		—		—
Acquisition of gathering systems and facilities		(266)		(69,992)		—
Acquisition of gathering systems and facilities		(216,726)		(266)		(69,992)
Other investing activities		1,055		1,999		(304)
Cash received in asset sales		5,726		1,087		1,342
Net cash used in investing activities		(183,206)		(242,733)		(169,212)
Change in other assets		(98)		(32)		(2)
Change in other liabilities		(804)		—		659
Net cash used in investing activities		(493,826)		(183,206)		(242,733)
Cash flows provided by (used in) financing activities:
Dividends to common stockholders		(~~432~~434,~~825~~846)		(~~434~~437,~~846~~634)		(~~437~~439,~~634~~007)
Dividends to preferred stockholders		(550)		(550)		(550)
Repurchases of common stock		—		—(28,690)		(28134,~~690~~981)
Issuance of Senior Notes		—		—600,000		~~600~~1,250,000
Redemption of Senior Notes		—		—(560,862)		(~~560~~650,~~862~~000)
Payments of deferred financing costs		~~(302)~~—		—(12,793)		(1213,~~793~~877)
Borrowings on Credit Facility		1,~~269~~037,~~300~~700		1,~~037~~565,~~700~~000		1,~~565~~768,~~000~~700
Repayments on Credit Facility		(1,~~034~~189,~~500~~600)		(1,~~189~~710,~~600~~800)		(12,~~710~~253,~~800~~000)
Employee tax withholding for settlement of equity-based compensation awards		(68,~~901~~495)		(814,~~495~~998)		(1427,~~998~~602)
Net cash used in financing activities		(~~205~~595,~~778~~791)		(~~595~~601,~~791~~327)		(~~601~~500,~~327~~317)
Net increase (decrease) in cash and cash equivalents		—		66		(66)
Net increase (decrease) in cash, cash equivalents and restricted cash		66		(66)		262,935
Cash and cash equivalents, beginning of period		—		—66		66—
Cash and cash equivalents, end of period	$	—		66		—
Cash, cash equivalents and restricted cash, end of period	$	66		—		262,935

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	~~183~~213,~~079~~955		~~213~~189,~~955~~908		~~189~~187,~~908~~656
Cash received during the period for income taxes	$	—		9,626		104
Income taxes refunded (paid) during the period	$	9,626		104		(2,600)
Increase (decrease) in accrued capital expenditures and accounts payable for property and equipment	$	~~(17~~1,~~003)~~288		1(13,~~288~~416)		~~(13~~9,~~416)~~797

See accompanying notes to consolidated financial statements.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements

(1) Organization

Antero Midstream Corporation together with its consolidated subsidiaries (the “Company” or “Antero Midstream”), is a growth-oriented midstream company formed to own, operate and develop midstream energy infrastructure primarily to service Antero Resources and its production and completion activity in the Appalachian Basin. The Company’s assets consist of gathering pipelines, compressor stations, interests in processing and fractionation plants and water handling assets. Antero Midstream provides midstream services to Antero Resources under long-term contracts. The Company’s corporate headquarters is located in Denver, Colorado.

The Company’s gathering and processing assets consist of high and low pressure gathering pipelines, compressor stations and processing and fractionation plants that collect and process natural gas and NGLs from Antero Resources’ wells in the Appalachian Basin. The Company’s water handling assets include two independent systems that deliver water from sources including the Ohio River, local reservoirs and several regional waterways, which portions of these systems are also utilized to transport flowback and produced water. The Company’s water handling assets also include other flowback and produced water treatment facilities.

Antero Midstream also has a 50% equity interest in the Joint Venture and a 15% equity interest in a gathering system of Stonewall. See Note 1415—Investments in Unconsolidated Affiliates.

(2) Summary of Significant Accounting Policies

(a)	Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with GAAP. In the opinion of management, these consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, ~~2023~~2024 and ~~December 31~~2025, ~~2024,~~ and the results of the Company’s operations and its cash flows for the years ended December 31, ~~2022~~2023, ~~2023~~2024 and ~~2024~~2025. The Company has no items of other comprehensive income; therefore, net income is equal to comprehensive income.

Certain costs of doing business incurred and charged to the Company by Antero Resources have been reflected in the accompanying consolidated financial statements. These costs include general and administrative expenses provided to the Company by Antero Resources in exchange for:

● business services, such as payroll, accounts payable and facilities management;

● corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy; and

● employee compensation.

Transactions between the Company and Antero Resources have been identified in the consolidated financial statements (see Note 45—Transactions with Affiliates).

(b)	Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Antero Midstream Corporation and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements.

Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero Midstream’s ownership interest, representation on the Board of Directors and participation in the policy-making decisions of equity method investees. Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s consolidated statements of operations and comprehensive income and cash flows. When the Company records its proportionate share of net income, it increases equity income in the statements of operations and comprehensive income and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the balance sheet.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities).

(c)	Use of Estimates

The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent liabilities. Items subject to estimates and assumptions include the useful lives of property and equipment, evaluating impairments of long-lived and intangible assets, as well as the valuation of accrued liabilities and deferred and current income taxes, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

(d)	Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable within its consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its consolidated statements of cash flows.

(e) ~~Property~~Restricted ~~and Equipment~~Cash

The Company classifies restricted cash as all cash that is legally or contractually restricted from withdrawal or usage, including amounts deposited in escrow that are restricted from use. The Company’s restricted cash is classified as a current asset as of December 31, 2025 because the restriction on such cash was released on February 3, 2026 at the closing of the HG Acquisition.

(f)	Property and Equipment

Property and equipment primarily consists of (i) gathering pipelines, (ii) compressor stations, (iii) the wastewater treatment facility (the “Clearwater Facility”), (iv) other flowback and produced water facilities and (v) water handling pipelines and facilities stated at historical cost less accumulated depreciation, amortization and impairment. The Company capitalizes construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred.

Depreciation of property and equipment is computed using the straight-line method over the estimated useful lives and salvage values of assets. The depreciation of fixed assets recorded under operating lease agreements is included in depreciation expense. Uncertainties that may impact these estimates of useful lives include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions and supply and demand for the Company’s services in the areas in which it operates. When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable. The Company reviews the estimated useful lives of its assets to determine if any changes are necessary as circumstances warrant.

The Company evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs and discount rates typical of third-party market participants, which is a Level 3 fair value measurement.

During the ~~years~~year ended December 31, ~~2022 and~~ 2024, the Company acquired certain Marcellus Shale gas gathering and compression assets ~~and Utica compression assets~~. ~~These~~This ~~transactions~~transaction ~~were~~was accounted for as asset ~~acquisitions~~acquisition in accordance with FASB ASC Topic 805-50, Business Combinations, Related Issues (“ASC 805-50”). Accordingly, the acquired assets were recorded based upon the cash consideration paid, with all value assigned to Property and equipment in the consolidated balance sheets. See Note 63— ~~Property~~Transactions ~~and Equipment~~ for additional information ~~on asset acquisitions~~.

(f) Investments in Unconsolidated Affiliates

The Company uses the equity method of accounting to account for its investments in the Joint Venture and Stonewall. The Company uses the equity method to account for its investments in companies if the investment provides the Company with the ability to exercise significant influence over, but not control of, the operating and financial policies of the investee. The Company’s judgment regarding the level of influence over each equity method investee includes considering key factors such as the Company’s ownership interest, representation on the board of directors, participation in policy-making decisions of the investee and material

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

~~intercompany~~(g) ~~transactions. Such~~Investments ~~investments are included~~ in ~~the~~Unconsolidated ~~investments in unconsolidated affiliates on the Company’s consolidated balance sheets.~~Affiliates

~~Income~~The ~~(loss)~~Company ~~from~~uses ~~investees that are accounted for under~~ the equity method isof ~~included~~accounting into ~~equity~~account infor ~~earnings~~its ~~(loss)~~investments ofin ~~unconsolidated affiliates on~~ the ~~Company’s~~Joint ~~consolidated~~Venture ~~statements of operations~~ and ~~comprehensive income and cash flows~~Stonewall. ~~When~~The ~~the~~ Company ~~records~~uses ~~its~~the ~~proportionate~~equity ~~share~~method ~~of net income (loss), it is recorded~~ to ~~equity~~account infor ~~earnings~~its ~~(loss)~~investments ~~of unconsolidated affiliates~~ in ~~the~~companies ~~consolidated~~if ~~statements of operations and comprehensive income and~~ the ~~carrying value of that~~ investment onprovides ~~its~~the ~~consolidated~~Company ~~balance~~with ~~sheet. Distributions~~the ~~received~~ability ~~from~~to ~~equity~~exercise ~~method~~significant ~~investees~~influence ~~are~~over, ~~recorded~~but asnot ~~reductions~~control toof, the ~~carrying~~operating ~~value~~and offinancial ~~the~~policies ~~investment~~of on the ~~consolidated balance sheet~~investee. The Company’s ~~equity~~judgment inregarding ~~earnings~~the ~~(loss)~~level of ~~unconsolidated~~influence ~~affiliates~~over iseach ~~adjusted~~equity ~~for~~method ~~basis~~investee ~~differences~~includes ~~recognized~~considering ~~due~~key tofactors ~~the~~such ~~difference~~as ~~between~~ the ~~cost~~Company’s ofownership ~~the~~interest, ~~equity~~representation ~~method~~on ~~investment and~~ the ~~amount~~board of ~~underlying~~directors, ~~equity~~participation in ~~the~~policy-making ~~net~~decisions ~~assets~~of asthe ofinvestee ~~March~~and ~~12,~~material ~~2019~~intercompany transactions. ~~Basis~~Such ~~difference~~investments are ~~amortized~~included ~~into equity~~ in ~~earnings~~the ~~(loss)~~investments ofin unconsolidated ~~affiliate~~affiliates on the Company’s consolidated ~~statements~~balance ~~of operations and comprehensive income over the remaining useful lives of the underlying assets and liabilities~~sheets.

Income (loss) from investees that are accounted for under the equity method is included in equity in earnings (loss) of unconsolidated affiliates on the Company’s consolidated statements of operations and comprehensive income and cash flows. When the Company records its proportionate share of net income (loss), it is recorded to equity in earnings (loss) of unconsolidated affiliates in the consolidated statements of operations and comprehensive income and the carrying value of that investment on its consolidated balance sheet. Distributions received from equity method investees are recorded as reductions to the carrying value of the investment on the consolidated balance sheet. The Company’s equity in earnings (loss) of unconsolidated affiliates is adjusted for basis differences recognized due to the difference between the cost of the equity method investment and the amount of underlying equity in the net assets as of March 12, 2019. Basis differences are amortized into equity in earnings (loss) of unconsolidated affiliate on the Company’s consolidated statements of operations and comprehensive income over the remaining useful lives of the underlying assets and liabilities.

The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash provided by operating activities) or a return of investment (classified as cash provided by investing activities).

(gh) Intangible Assets

Amortization of intangible assets with definite lives is calculated using the straight-line method, which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. Intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible asset may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.

(hi) Income Taxes

The Company recognizes deferred income tax assets and liabilities for temporary differences resulting from net operating loss and charitable contribution carryforwards and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred income tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred income tax assets will not be realized. The Company regularly reviews its tax positions in each significant taxing jurisdiction during the process of evaluating its tax provision. The Company makes adjustments to its tax provision when: (i) facts and circumstances regarding a tax position change, causing a change in management’s judgment regarding that tax position; and/or (ii) a tax position is effectively settled with a tax authority at a differing amount.

~~(i)~~On ~~Asset~~July 4, ~~Retirement~~2025, ~~Obligations~~Public Law No. 119-21, commonly referred to as the One Big Beautiful Bill Act, was enacted. The OBBB contains a broad range of changes to U.S. federal income tax laws and makes permanent or modifies certain provisions of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act. These changes include, among others, permanently restoring an earnings before interest, taxes, depreciation and amortization based business interest deduction limitation, 100% bonus depreciation for certain property and immediate expensing for certain domestic research and experimental expenditures. All effects of changes in tax laws are recognized in the consolidated financial statements during the period of enactment. As such, the effects of the OBBB are reflected in the Company's provision for income taxes as of and for the year ended December 31, 2025. The OBBB did not have a material effect on income tax expense for the year ended December 31, 2025, and the Company expects a refund of substantially all of the cash paid for income taxes during the year ended December 31, 2025 when it files its 2025 U.S. federal income tax return as a result of the OBBB.

The Company’s asset retirement obligations include its obligation to close, maintain and monitor landfill cells and support facilities. After the landfill is certified closed, the Company must continue to maintain and monitor the landfill for a post-closure period, which generally extends for 30 years. The Company records the fair value of its landfill retirement obligations as a liability in the period in which the regulatory obligation to retire a specific asset is triggered. For the Company’s individual landfill cells, the required closure and post-closure obligations under the terms of its permits and its intended operation of the landfill cell are triggered and recorded when the cell is placed into service and salt is initially disposed in the landfill cell. The fair value is based on the total estimated costs to close the landfill cell and perform post-closure activities once the landfill cell has reached capacity and is no longer accepting salt. Retirement obligations are increased each year to reflect the passage of time by accreting the balance at the weighted average credit-adjusted risk-free rate that is used to calculate the recorded liability, with accretion charged to direct costs. Actual cash expenditures to perform closure and post-closure activities reduce the retirement obligation liabilities as incurred. After initial measurement, asset retirement obligations are adjusted at the end of each period to reflect changes, if any, in the estimated future cash flows underlying the obligation. Landfill retirement assets are capitalized as the related retirement obligations are incurred, and are amortized on a units-of-consumption basis as the disposal capacity is consumed. During the year ended December 31, 2021, the Company commenced closure and reclamation operations on the landfill, and such closure and reclamation operations were substantially complete as of December 31, 2024.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(j)	Asset Retirement Obligations

Asset retirement obligations are recorded for water impoundments and wastewater pits when an abandonment date is identified. The Company records the fair value of its water impoundment and wastewater pit retirement obligations as liabilities in the period in which the regulatory obligation to retire a specific asset is triggered. The fair value is based on the total reclamation costs of the assets. Retirement obligations are increased each year to reflect the passage of time by accreting the balance at the weighted average credit-adjusted risk-free rate that is used to calculate the recorded liability, with accretion charged to direct costs. Actual cash expenditures to perform remediation activities reduce the retirement obligation liabilities as incurred. After initial measurement, asset retirement obligations are adjusted at the end of each period to reflect changes, if any, in the estimated future cash flows underlying the obligation. Water impoundments and wastewater pit retirement assets are capitalized as the related retirement obligations are incurred, and are amortized on a straight-line basis until reclamation.

The Company (i) is under no legal obligations, neither contractually nor under the doctrine of promissory estoppel, to restore or dismantle its gathering pipelines, compressor stations, water delivery pipelines, flowback and produced water facilities and the Clearwater Facility upon abandonment or (ii) intends to operate and maintain its assets as long as supply and demand for natural gas exists, which the Company expects to continue into the foreseeable future.

(jk) Litigation and Other Contingencies

A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of ~~our~~its accruals and related disclosures. The ultimate amount of losses, if any, may differ from these estimates. Any contingency that could result in a gain is recorded when realized.

The Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time a remediation feasibility study or an evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.

As of December 31, ~~2023~~2024 and ~~December 31~~2025, ~~2024,~~ the Company had not recorded any liabilities for litigation, environmental or other contingencies.

(kl)Dividends

Preferred and common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings were available at the close of the quarter prior to the dividend declaration date, with any excess recorded as a reduction of additional paid-in capital.

(l)Treasury Share Retirement

The Company periodically retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to retained earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares outstanding, to the balance of additional paid-in capital as of retirement.

(m) Revenue Recognition

The Company provides gathering, compression and water handling services under fee-based contracts primarily based on throughput or at cost plus a margin. Certain of these contracts contain operating leases of the Company’s assets under GAAP. Under these arrangements, the Company receives fees for gathering, compression and water handling services. The revenue the Company earns from these arrangements is directly related to (i) in the case of natural gas gathering and compression, the volumes of metered natural gas that it gathers, compresses and delivers to natural gas compression sites or other transmission delivery points, (ii) in the case of fresh water services, the quantities of fresh water delivered to its customers for use in their well completion operations, (iii) in the case of other fluid handling services provided by third parties, the third-party costs the Company incurs plus 3% or (iv) in the case of other fluid handling services performed by the Company, a cost of service fee based on the costs incurred by the Company. The Company recognizes revenue when it satisfies a performance obligation by delivering a service to a customer or the use of leased assets to a customer. The Company includes lease revenue within revenues by service. See Note 5—Revenue.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(nm)Treasury ~~Equity-Based~~Share ~~Compensation~~Retirement

The Company recognizes compensation cost related to all equity-based awards in the financial statements based on the estimated grant date fair value. The Company’s equity-based compensation expense is included in general and administrative expenses, and recorded as a credit to additional paid-in capital. The Company is authorized to grant various types of equity-based compensation awards, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit (“RSU”) awards, dividend equivalent awards and other types of awards. The grant date fair values of such awards are determined based on the type of award and may utilize market prices on the date of grant, Black-Scholes option-pricing model, Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of equity-based award. Compensation cost is recognized ratably over the applicable vesting or service period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. See Note 10—Equity-Based Compensation.

~~(o)~~The ~~Fair~~Company ~~Value~~periodically ~~Measures~~retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to retained earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares outstanding, to the balance of additional paid-in capital as of retirement.

The FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (~~e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets~~n)~~. The~~ ~~fair~~Revenue value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. See Note 13—Fair Value Measurement.Recognition

The Company provides gathering, compression and water handling services under fee-based contracts primarily based on throughput or at cost plus a margin. Certain of these contracts contain operating leases of the Company’s assets under GAAP. Under these arrangements, the Company receives fees for gathering, compression and water handling services. The revenue the Company earns from these arrangements is directly related to (pi) ~~Recently~~in ~~Adopted~~the case of natural gas gathering and compression, the volumes of metered natural gas that it gathers, compresses and delivers to natural gas compression sites or ~~Issued~~other ~~Accounting~~transmission ~~Standards~~delivery points, (ii) in the case of fresh water services, the quantities of fresh water delivered to its customers for use in their well completion operations, (iii) in the case of other fluid handling services provided by third parties, the third-party costs the Company incurs plus 3% or (iv) in the case of other fluid handling services performed by the Company, a cost of service fee based on the costs incurred by the Company. The Company recognizes revenue when it satisfies a performance obligation by delivering a service to a customer or the use of leased assets to a customer. The Company includes lease revenue within revenues by service. See Note 6—Revenue.

(o)	Equity-Based Compensation

(p)	Fair Value Measures

The FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. See Note 14—Fair Value Measurement.

(q)	Recently Adopted or Issued Accounting Standards

Reportable Segments

In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 is intended to improve reportable segment disclosures primarily through enhanced disclosure of reportable segment expenses. This ASU is effective for annual reporting periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-07 in ~~this~~the ~~Annual~~2024 ~~Report on~~ Form 10-K ~~for the year ended December 31~~, ~~2024,~~ and it did not have a material impact on the Company’s consolidated financial statements.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 is intended to improve income tax disclosures primarily through enhanced disclosure of income tax rate reconciliation items, and disaggregation of income (loss) from continuing operations, income tax (expense) benefit and income taxes paid, net disclosures by federal, state and foreign jurisdictions, among others. This ASU is effective for annual reporting periods beginning after December 15, 2024~~, although early adoption is permitted~~. ASU 2023-09 should be applied on a prospective basis, although retrospective application is permitted. The Company isadopted ~~evaluating~~ASU ~~the impact that ASC~~ 2023-09 ~~will~~retrospectively ~~have~~in onthis ~~the~~Annual ~~consolidated~~Report ~~financial~~on ~~statements~~Form 10-K, and ~~the transition method~~ it ~~plans~~did tonot ~~use~~have ~~for~~a ~~adoption. The~~material ~~Company~~impact ~~plans to adopt ASU 2023-09 in the Annual Report~~ on ~~Form 10-K for~~ the ~~year~~Company’s ~~ending~~consolidated ~~December 31,~~financial ~~2025~~statements.

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 is intended to improve the disclosure about certain operating expenses primarily through enhanced disclosure of cost of sales and selling, general and administrative expenses. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. ASU 2024-03 can be applied on either a prospective or a retrospective basis at the Company’s election. The Company is evaluating the impact that ASU 2024-03 will have on the ~~consolidated~~ financial statements and its plans for adoption, including its transition method and adoption date.

~~F-12~~

(3) Transactions

(a)	Summit Asset Acquisition

On May 1, 2024, the Company acquired certain Marcellus Shale gas gathering and compression assets from Summit for $70 million in cash, before closing adjustments, with an effective date of April 1, 2024. The acquired assets include 48 miles of high pressure gathering pipelines and two compressor stations with 100 MMcf/d of compression capacity. These assets were already interconnected to the Company’s low pressure and high pressure gas gathering systems at the time of acquisition and service Antero Resources’ production. Substantially all of the cash consideration for this asset acquisition was allocated to gathering systems and facilities, included in property and equipment, net in the consolidated balance sheets.

(b)	HG Acquisition

On December 5, 2025, Antero Midstream Partners, an indirect, wholly-owned subsidiary of the Company, 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 includes gathering pipelines and integrated water handling assets in the core of the Marcellus Shale in West Virginia. Pursuant to the same agreement, Antero Resources agreed 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 Upstream Acquisition includes approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia. In connection with the Company’s entry into the definitive agreement relating to the HG Acquisition, the Company and Antero Resources agreed to allocate between the parties certain benefits and costs under the agreement and the buyer-side representations and warranties insurance policies. On December 8, 2025, the Company deposited approximately $83 million into escrow to be credited towards the cash consideration payable at the closing of the HG Acquisition, which is classified as restricted cash on the Company’s consolidated balance sheets as of December 31, 2025. These acquisitions closed on February 3, 2026, with effective dates of January 1, 2026. The Company intends to make certain modifications to its existing commercial arrangements with Antero Resources to provide for on-pad compression with respect to certain wells and to provide a transition period through 2026 before certain water services would be provided under the existing agreements with Antero Resources.

The disclosure of certain financial information required by FASB ASC Topic 805, Business Combinations, has been omitted as it is impracticable to provide such information due to the timing of the closing of the HG Acquisition and issuance of the Company’s consolidated financial statements.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(3c) ~~Intangibles~~ Utica Shale Divestiture

~~All~~On ~~customer~~December ~~relationships~~5, ~~are~~2025, ~~subject~~certain wholly-owned subsidiaries of the Company entered into the Utica Shale PSA with the Buyer Parties to ~~amortization~~sell ~~and~~the ~~are~~Utica ~~amortized~~Shale ~~over~~Property aand ~~weighted-average~~Equipment, ~~period~~for aggregate cash consideration of 17$400 ~~years~~million, ~~which~~subject ~~reflects~~to the ~~remaining~~terms ~~economic~~and ~~life~~conditions thereof. The Utica Shale Property and Equipment includes 118 miles of ~~the~~gathering ~~relationships~~pipelines, as0.7 Bcfe/d of ~~December 31~~compression capacity, ~~2024~~85 miles of water pipelines and 12 water impoundments with storage capacity of approximately 2 million barrels. The ~~Company~~Utica ~~recorded~~Shale ~~amortization~~Divestiture ~~expense~~is ofexpected ~~$71~~to ~~million~~close ~~for~~in ~~each~~February of2026, ~~the~~with ~~years~~an ~~ended~~effective ~~December 31~~date of July 1, ~~2022~~2025, ~~2023~~subject ~~and~~to ~~2024~~the satisfaction of certain customary closing conditions.

The Utica Shale Property and Equipment and its associated assets and liabilities have been classified as held for sale as of December 31, 2025 on the Company’s consolidated balance sheets, which relate to both the Company’s gathering and processing and water handling reportable segments. The Utica Shale Divestiture does not qualify as a discontinued operation under FASB ASC Topic 205, Presentation of Financial Statements, as it does not represent a strategic shift that will have a major effect on the Company’s operations or financial results.

The cash consideration expected to be received for the Utica Shale Divestiture less costs to sell was less than its carrying value of the Utica Shale Property and Equipment’s net assets as of December 5, 2025. Accordingly, the Company reduced the carrying value of the Utica Shale Property and Equipment to the estimated selling price less costs to sell and recorded a loss on long-lived assets of $87 million during the year ended December 31, 2025 in its statements of operations and comprehensive income.

The carrying value of the Utica Shale Property and Equipment’s assets and liabilities held for sale were as follows:


(in thousands)	December 31, 2025
Current assets:
Accounts receivable–Antero Resources	$	4,600
Long-term assets:
Property and equipment, net		378,560
Other assets, net		476
Total	$	383,636

Current liabilities:
Accounts payable–third party	$	634
Accrued liabilities		1,663
Long-term liabilities:
Other long-term liabilities		3,021
Total	$	5,318

(4) Intangibles

All customer relationships are subject to amortization and are amortized over a weighted-average period of 16 years, which reflects the remaining economic life of the relationships as of December 31, 2025. The Company recorded amortization expense of $71 million for each of the years ended December 31, 2023, 2024 and 2025.

The carrying amount of customer relationships were as follows:


	December 31,
(in thousands)	2023		2024
Gross carrying value of customer relationships	$	1,555,000		1,555,000
Accumulated amortization of customer relationships		(339,569)		(410,241)
Customer relationships	$	1,215,431		1,144,759

Future amortization expense as of December 31, 2024 is as follows (in thousands):


	December 31,
(in thousands)	2024		2025
Gross carrying value of customer relationships	$	1,555,000		1,555,000
Accumulated amortization of customer relationships		(410,241)		(480,913)
Customer relationships	$	1,144,759		1,074,087


Year ending December 31, 2025	$	70,672
Year ending December 31, 2026		70,672
Year ending December 31, 2027		70,672
Year ending December 31, 2028		70,672
Year ending December 31, 2029		70,672
Thereafter		791,399
Total	$	1,144,759

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

Future amortization expense as of December 31, 2025 is as follows (in thousands):


Year ending December 31, 2026	$	70,672
Year ending December 31, 2027		70,672
Year ending December 31, 2028		70,672
Year ending December 31, 2029		70,672
Year ending December 31, 2030		70,672
Thereafter		720,727
Total	$	1,074,087

(45) Transactions with Affiliates

(a)

Revenues

Substantially all revenues earned during the years ended December 31, ~~2022~~2023, ~~2023~~2024 and ~~2024~~2025 were earned from Antero Resources, under various agreements for gathering and compression and water handling services. Revenues earned from gathering and compression services consist of lease income.

(b)	Accounts receivable—Antero Resources and Accounts payable—Antero Resources

Accounts receivable—Antero Resources represents amounts due from Antero Resources, primarily related to gathering and compression services and water handling services. Accounts payable—Antero Resources represents amounts due to Antero Resources for general and administrative and other costs.

(c)	Allocation of Costs Charged by Antero Resources

The employees supporting the Company’s operations are concurrently employed by Antero Resources and the Company. Direct operating expense includes costs charged to the Company of $14 18 million, $18 20 million and $2021 million during the years ended December 31, ~~2022~~2023, ~~2023~~2024 and ~~2024~~2025, respectively. These costs were for services provided by employees associated with the operation of the Company’s gathering lines, compressor stations and water handling assets. For the years ended December 31, ~~2022~~2023, ~~2023~~2024 and ~~2024~~2025, general and administrative expense includes costs charged to the Company by Antero Resources of $3029 million, $2932 million and $3233 million, respectively. These costs relate to: (i) various business services, including payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation. These expenses are charged to the Company based on the nature of the expenses and are apportioned based on a combination of the Company’s proportionate share of gross property and equipment, capital expenditures and labor costs, as applicable. The Company reimburses Antero Resources directly for all general and administrative costs charged to it. ~~For further information on equity-based compensation, see Note 10—Equity-Based Compensation.~~

(6) Revenue

~~F-13~~All of the Company’s gathering and compression revenues are derived from operating lease agreements, and all of the Company’s water handling revenues are derived from service contracts with customers. The Company earned substantially all of its revenues from Antero Resources.

(a)	Gathering and Compression

The Company’s gathering and compression service agreements with Antero Resources include: (i) the 2019 gathering and compression agreement, (ii) the Marcellus gathering and compression agreement, (iii) the Utica compression agreement and (iv) the Mountaineer gathering and compression agreement. Pursuant to the gathering and compression agreements, Antero Resources has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to the Company for gathering and compression services. The 2019 gathering and compression agreement, Marcellus gathering and compression agreement and Mountaineer gathering and compression agreement have initial terms through 2038, 2031 and 2026, respectively, and the Utica compression agreement has one remaining acreage dedication that expires in 2030. Upon expiration of the Marcellus gathering and compression agreement, the Utica compression agreement and the Mountaineer gathering and compression agreement, the Company will continue to provide gathering and compression services under the 2019 gathering and compression agreement. The Company also has an option to gather and compress natural gas produced by Antero Resources on any additional undedicated acreage it acquires during the term of the 2019 gathering and compression agreement outside of West Virginia, Ohio and Pennsylvania on the same terms

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

~~(5) Revenue~~and conditions as the 2019 gathering and compression agreement. Upon completion of the initial contract term in 2038, the 2019 gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by notice from either the Company or Antero Resources to the other party on or before the 180th day prior to the anniversary of such agreement. The Utica compression agreement is included in the Utica Shale Divestiture.

~~All~~The of2019 gathering and compression agreement included a growth incentive fee program whereby low pressure gathering fees were reduced from 2020 through 2023 to the ~~Company~~extent Antero Resources achieved certain quarterly volumetric targets during such time. Only Antero Resources’s throughput gathered under the 2019 gathering and compression ~~revenues~~agreement ~~are~~was ~~derived~~considered ~~from~~in ~~operating~~low ~~lease~~pressure ~~agreements,~~gathering ~~and~~volume ~~all~~targets. For of the ~~Company’s~~year ~~water~~ended ~~handling~~December 31, ~~revenues~~2023, ~~are~~Antero ~~derived~~Resources ~~from~~earned ~~service~~a ~~contracts~~fee ~~with~~rebate ~~customers~~of $52 million. The ~~Company~~growth ~~earned~~incentive ~~substantially~~fee ~~all~~rebate ofprogram ~~its~~expired ~~revenues~~on ~~from~~December ~~Antero~~31, ~~Resources~~2023.

(a) Gathering and Compression

The Company’s gathering and compression service agreements with Antero Resources include: (i) the 2019 gathering and compression agreement, (ii) the Marcellus gathering and compression agreement, (iii) the Utica compression agreement and (iv) the Mountaineer gathering and compression agreement. The 2019 gathering and compression agreement, Marcellus gathering and compression agreement and Mountaineer gathering and compression agreement have initial terms through 2038, 2031 and 2026, respectively, and the Utica compression agreement has two acreage dedications, one of which expired in 2024 and one that expires in 2030. Upon expiration of the Marcellus gathering and compression service agreement, the Utica compression agreement and the Mountaineer gathering and compression agreement, the Company will continue to provide gathering and compression services under the 2019 gathering and compression agreement. Pursuant to the gathering and compression agreements, Antero Resources has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to the Company for gathering and compression services. The Company also has an option to gather and compress natural gas produced by Antero Resources on any additional undedicated acreage it acquires during the term of the 2019 gathering and compression agreement outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions as the 2019 gathering and compression agreement. Upon completion of the initial contract term in 2038, the 2019 gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by notice from either the Company or Antero Resources to the other party on or before the 180th day prior to the anniversary of such agreement.

The 2019 gathering and compression agreement included a growth incentive fee program whereby low pressure gathering fees were reduced from 2020 through 2023 to the extent Antero Resources achieved certain quarterly volumetric targets during such time. Only Antero Resources’ throughput gathered under the 2019 gathering and compression agreement was considered in low pressure gathering volume targets. For the years ended December 31, 2022 and 2023, Antero Resources earned fee rebates of $48 million and $52 million, respectively. The growth incentive fee rebate program expired on December 31, 2023.

Under the gathering and compression agreements, the Company receives, where applicable, a low pressure gathering fee, a high pressure gathering fee and a compression fee, substantially all of which are subject to annual CPI-based adjustments (or, in the case of the 2019 gathering and compression agreement, the option in certain cases to elect a cost of service fee when such assets are placed in-service). In addition, under the 2019 gathering and compression agreement, the Company receives a reimbursement for certain variable costs, such as electricity and operating expenses.

The Company determined that its gathering and compression agreements are operating leases as Antero Resources obtains substantially all of the economic benefit of the assets and has the right to direct the use of the assets. Each gathering and compression system is an identifiable asset, and consists of a network of assets that may include underground low pressure pipelines that connect and deliver gas from specific well pads to compressor stations to compress the gas before delivery to underground high pressure pipelines that transport the gas to a third-party pipeline, third-party processing plant or a Joint Venture processing plant. Each compression system is an identifiable asset, and consists of a network of assets that include compressor stations that connect to underground high pressure pipelines that transport the gas to a third-party pipeline, third-party processing plant or a Joint Venture processing plant. Each set of assets in an agreement is considered to be a single lease due to the interrelated network of the assets required to provide services under each respective agreement. When a modification to an agreement occurs, the Company reassesses the classification of the lease. The Company accounts for its lease and non-lease components as a single lease component as the lease component is the predominant component. The non-lease components consist of operating, oversight and maintenance of the gathering systems, which are performed on time-elapsed measures.

The 2019 gathering and compression agreement, the Marcellus gathering and compression agreement and the Mountaineer gathering and compression agreement include certain fixed fee provisions. If and to the extent Antero Resources requests that the Company construct new low pressure lines, high pressure lines and/or compressor stations, the 2019 gathering and compression agreement contains options at the Company’s election for either (i) minimum volume commitments that require Antero Resources to utilize or pay for 75% of the high pressure gathering capacity and 70% of the compression capacity of such new construction for 10 years or (ii) a cost of service fee that allows the Company to earn a ~~13%~~return ~~rate~~on ofcapital ~~return~~invested onof ~~such~~13% ~~new~~per ~~construction~~annum over a period of seven years, which election is made individually for each piece of equipment placed in service. The Marcellus gathering and compression agreement provides for a minimum volume commitment that requires Antero Resources to utilize or pay for 25% of the compression capacity for a period of 10 years from the in-service date. The Mountaineer gathering and compression agreement provides for monthly minimum compression and gathering fees for each compressor station or high pressure gathering line, respectively, for a period of 12 years commencing 90 days after such asset’s in-service date. All lease payments under the minimum volume commitments, cost of service fees and minimum gathering and compression fees are considered to be in-substance fixed lease payments (“minimum lease payments”) under the gathering and compression agreements. As of December 31, 2025, the minimum lease payments for the 2019 gathering and compression agreement and Mountaineer gathering and compression agreement end in 2035 and 2026, respectively. As of January 1, 2025, there were no minimum lease payments for the Marcellus gathering and compression agreement.

FThe Company recognizes lease income from its minimum lease payments under its gathering and compression agreements on a straight-14line basis. Additional variable operating lease income is earned when volumes in excess of the minimum commitments or fees are delivered under the contract. The Company recognizes variable lease income when low pressure volumes are delivered to a compressor station, compression volumes are delivered to a high pressure line and high pressure volumes are delivered to a processing plant or transmission pipeline, as applicable. Minimum volume commitments for the 2019 gathering and compression agreement are aggregated such that the agreement has a single minimum volume commitment for the respective service each year. The Mountaineer gathering and compression agreement minimum compression and gathering fees are not subject to aggregation and are determined on a monthly basis for each compressor station and gathering line, respectively, subject to such agreement. The Company invoices the

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

~~agreement~~customer ~~provides for a minimum volume commitment that requires Antero Resources to utilize or pay for 25% of~~ the ~~compression~~month ~~capacity~~after ~~for a period of 10 years from the in-service date. The Mountaineer gathering and compression agreement provides for monthly minimum compression and gathering fees for~~ each ~~compressor station or high pressure gathering line, respectively, for a period of 12 years commencing 90 days after such asset’s in-~~service ~~date. All~~is ~~lease payments under the minimum volume commitments~~performed, ~~cost of service fees~~ and ~~minimum~~payment ~~gathering~~is ~~and~~due ~~compression fees are considered to be~~ in~~-substance~~ ~~fixed lease payments (“minimum lease payments”) under~~ the ~~gathering~~same ~~and compression agreements~~month. AsThe ofCompany ~~December 31,~~is ~~2024,~~not ~~the~~party ~~minimum~~to ~~lease~~any ~~payments~~leases ~~for~~that ~~the~~have ~~2019~~not ~~gathering and compression agreement and Mountaineer gathering and compression agreement end in 2034 and 2026, respectively~~commenced. ~~As of January 1, 2025, there are no minimum lease payments for the Marcellus gathering and compression agreement.~~

~~The~~Minimum ~~Company~~future ~~recognizes~~ lease ~~income~~cash ~~from~~flows ~~its~~to ~~minimum~~be ~~lease~~received ~~payments~~by the Company under ~~its~~the gathering and compression agreements onas ~~a straight-line basis. Additional variable operating lease income is earned when volumes in excess~~ of ~~the minimum commitments or fees are delivered under the contract. The Company recognizes variable lease income when low pressure volumes are delivered to a compressor station~~December 31, ~~compression~~2025 ~~volumes~~ are ~~delivered to a high pressure line and high pressure volumes are delivered to a processing plant or transmission pipeline,~~ as ~~applicable. Minimum~~follows volume commitments for each of the 2019 gathering and compression agreement and Marcellus gathering and compression agreement are aggregated such that each agreement has a single minimum volume commitment for the respective service each year. The Mountaineer gathering and compression agreement minimum compression and gathering fees are not subject to aggregation and are determined on a monthly basis for each compressor station and gathering line, respectively, subject to such agreement. The Company invoices the customer the month after each service is performed, and payment is due (in ~~the same month. The Company is not party to any leases that have not commenced.~~thousands):

Minimum future lease cash flows to be received by the Company under the gathering and compression agreements as of December 31, 2024 are as follows (in thousands):


Year ending December 31, 2026	$	314,934
Year ending December 31, 2027		254,249
Year ending December 31, 2028		183,839
Year ending December 31, 2029		123,016
Year ending December 31, 2030		89,885
Thereafter		134,944
Total ⁽¹⁾	$	1,100,867


Year ending December 31, 2025	$	322,417
Year ending December 31, 2026		305,977
Year ending December 31, 2027		240,637
Year ending December 31, 2028		171,218
Year ending December 31, 2029		111,302
Thereafter		169,431
Total	$	1,320,982

(1)	Minimum future lease cash flows related to the Utica Shale Property and Equipment classified as held for sale were $48 million as of December 31, 2025.

(b)	Water Handling

The Company is party to a water services agreement with Antero Resources, whereby the Company provides certain water handling services to Antero Resources within an area of dedication in defined service areas in West Virginia and Ohio. The initial term of the water services agreement runs to 2035. Upon completion of the initial term in 2035, the water services agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by notice from either the Company or Antero Resources to the other party on or before the 180th day prior to the anniversary of such agreement. Under the agreement, the Company receives a fixed fee for fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. In addition, the Company ~~also~~ provides other fluid handling services. These operations, along with the Company’s fresh water delivery systems, support well completion and production operations for Antero Resources. These services are provided by the Company directly or through third-parties with which the Company contracts. For these other fluid handling services provided by third parties, Antero Resources reimburses the Company’s third-party out-of-pocket costs plus 3%. For these other fluid handling services provided by the Company, the Company charges Antero Resources a cost of service fee. The cost of service fee allows the Company to recover its share of capital expenditures to construct any new facilities required to provide other fluid handling services to Antero Resources and earn a return on capital invested of 13% per annum over a period of seven years. As of December 31, ~~2024~~2025, the Company had minimum future revenues for its cost of service fees of $3467 million to be received and recognized by the Company under the water services agreement during ~~2025~~2026 through ~~2031~~2032 ~~related~~as tothe ~~unsatisfied~~agreement’s performance obligations are satisfied.

The Company satisfies its performance obligations and recognizes revenue when (i) the fresh water volumes have been delivered to the hydration unit of a specified well pad or (ii) other fluid handling services have been completed. The Company invoices the customer the month after water services are performed, and payment is due in the same month. For services contracted through third-party providers, the Company’s performance obligation is satisfied when the service to be performed by the third-party provider has been completed. The Company invoices the customer after the third-party provider billing is received, and payment is due in the same month.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

Transaction Price Allocated to Remaining Performance Obligations

The Company’s water service agreement with Antero Resources has a term greater than one year. The Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under this contract, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company also performs water services for third-party customers and such contracts are short-term in nature with a contract term of one year or less. Accordingly, the Company is exempt from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

Contract Balances

Under the Company’s water service contracts, the Company invoices customers after the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s water service contracts do not give rise to contract assets or liabilities.

(c)	Disaggregation of Revenue

In the following table, revenue is disaggregated by type of service and type of fee and is identified by the reportable segment to which such revenues relate. See Note 1617—Reportable Segments for additional information.


	Year Ended December 31,
(in thousands)	~~2022~~2023		~~2023~~2024		~~2024~~2025		~~Reportable Segment~~
Type of service
Reportable segment / Type of service
Gathering—low pressure	$	368,996	$	420,002		427,074	Gathering and Processing (1)
Gathering and Processing (1)
Gathering—low pressure fee rebate		(48,000)		(51,500)		—	Gathering and Processing (1)
Gathering—low pressure	$	420,002		427,074		451,168
Compression		210,329		246,952		252,984	Gathering and Processing (1)
Gathering—low pressure fee rebate		(51,500)		—		—
Gathering—high pressure		211,940		226,908		246,005	Gathering and Processing (1)
Compression		246,952		252,984		269,563
Fresh water delivery		153,546		164,641		149,072	Water Handling
Gathering—high pressure		226,908		246,005		266,553
Other fluid handling		93,846		105,440		101,730	Water Handling
Amortization of customer relationships		(37,086)		(37,086)		(37,086)
Amortization of customer relationships		(37,086)		(37,086)		(37,086)	Gathering and Processing
Water Handling
Amortization of customer relationships		(33,586)		(33,586)		(33,586)	Water Handling
Fresh water delivery		164,641		149,072		154,498
Total	$	919,985	$	1,041,771		1,106,193
Other fluid handling		105,440		101,730		117,316

Amortization of customer relationships		(33,586)		(33,586)		(33,586)
Type of contract
Total	$	1,041,771		1,106,193		1,188,426
Per unit fixed fee	$	791,265	$	893,862		926,063	Gathering and Processing (1)

Gathering—low pressure fee rebate		(48,000)		(51,500)		—	Gathering and Processing (1)
Reportable segment / Type of contract
Per unit fixed fee		154,993		166,055		151,016	Water Handling
Gathering and Processing (1)
Cost plus 3%		71,490		81,125		69,095	Water Handling
Per unit fixed fee	$	893,862		926,063		987,284
Cost of service fee		20,909		22,901		30,691	Water Handling
Gathering—low pressure fee rebate		(51,500)		—		—
Amortization of customer relationships		(37,086)		(37,086)		(37,086)	~~Gathering and Processing~~
Amortization of customer relationships		(33,586)		(33,586)		(33,586)	Water Handling
Water Handling
Total	$	919,985	$	1,041,771		1,106,193
Per unit fixed fee		166,055		151,016		156,914
Cost plus 3%		81,125		69,095		77,202
Cost of service fee		22,901		30,691		37,698
Amortization of customer relationships		(33,586)		(33,586)		(33,586)
Total	$	1,041,771		1,106,193		1,188,426

(1)	Revenue related to the gathering and processing segment is classified as lease income related to the gathering and compression systems.

The Company’s receivables from its contracts with customers and operating leases as of December 31, ~~2023~~2024 and ~~December 31,~~2025 ~~2024~~ were $89115 million and $~~115~~111 million, respectively.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(67) Property and Equipment

(a) Summary of Property and Equipment

Property and equipment, net consisted of the following items:


	Estimated	December 31,
(in thousands)	Useful Lives	~~2023~~2024		~~2024~~2025
Land	n/a	$	31,~~668~~237		3129,~~237~~435
Gathering systems and facilities	40-50 years (1)		3,~~345~~553,~~845~~934		3,~~553~~197,~~934~~948
Permanent buried pipelines and equipment	7-20 years		~~646~~653,~~469~~891		~~653~~651,~~891~~286
Surface pipelines and equipment	1-7 years		90110,~~871~~677		~~110~~161,~~677~~751
Heavy trucks and equipment	3-5 years		54,~~157~~413		4,413
Above ground storage tanks	5-10 years		5,~~130~~131		5,~~131~~481
Other assets	3-20 years		8,~~110~~111		8,~~111~~389
Construction-in-progress	n/a		~~192~~184,~~852~~680		~~184~~141,~~680~~233
Total property and equipment			4,~~326~~552,~~102~~074		4,~~552~~199,~~074~~936
Less accumulated depreciation			(~~532~~670,~~579~~453)		(~~670~~745,~~453~~364)
Property and equipment, net		$	3,~~793~~881,~~523~~621		3,~~881~~454,~~621~~572

(1) Gathering systems and facilities are recognized as a single-leased asset with no residual value.

(b8) Income ~~Asset~~Taxes ~~Acquisitions~~

Filing Compare · Antero Midstream Corp