Antero Midstream 10K 2022 Annual report

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, 2022
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, 2022, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $3.0 billion based on the $9.05 per share closing price of Antero Midstream Corporation’s common stock as reported on that day on the New York Stock Exchange.

The registrant had 478,613,386 shares of common stock outstanding as of February 10, 2023.

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	15
Item 1B.	Unresolved Staff Comments	38
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	39
PART II		40
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Reserved	41
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 8.	Financial Statements and Supplementary Data	56
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	56
Item 9A.	Controls and Procedures	56
Item 9B.	Other Information	57
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	58
PART III		58
Item 10.	Directors, Executive Officers and Corporate Governance	58
Item 11.	Executive Compensation	58
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	58
Item 13.	Certain Relationships and Related Transactions and Director Independence	58
Item 14.	Principal Accountant Fees and Services	58
PART IV		59
Item 15.	Exhibit and Financial Statement Schedules	59
SIGNATURES		63

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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.

“Antero Water.” Antero Water 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.” Collectively, the senior secured revolving credit facility in effect for periods before October 26, 2021 and the senior secured revolving credit facility in effect on and after October 26, 2021.

“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.

“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.

“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.

“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.

“Transactions.” On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP (“AMGP”), Antero Midstream Partners and certain of Antero Midstream Partners’ affiliates (the “Simplification Agreement”) (i) AMGP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation (together with its consolidated subsidiaries, as appropriate, “Antero Midstream”), and (ii) an indirect, wholly owned subsidiary of Antero Midstream was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream.

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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;

●

impacts to producer customers of insufficient storage capacity;

●

our ability to execute our business strategy;

●

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;

●

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

●

natural gas, NGLs and oil prices;

●

impacts of geopolitical events, including the Russia-Ukraine conflict, and world health events, including the coronavirus (“COVID-19”) pandemic;

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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;

●

our ability to execute our return of capital program;

●

competition;

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government regulations and changes in laws;

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

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pending legal or environmental matters;

●

costs of conducting our operations;

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

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general economic conditions;

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credit markets;

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

●

expectations regarding the amount and timing of litigation awards;

●

uncertainty regarding our future operating results; and

●

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

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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 disruptions, environmental risks, Antero Resources’ drilling and completion and other operating risks, regulatory changes or changes in laws, the uncertainty inherent in projecting Antero Resources’ future rates of production, cash flows and access to capital, the timing of development expenditures, impacts of geopolitical and world health events (including the COVID-19 pandemic), 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.

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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.

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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.

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Our exposure to commodity price risk may change over time.

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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.

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

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Increasing attention to ESG matters and conservation measures may adversely impact our business.

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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.

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A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.

Capital Structure and Access to Capital

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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.

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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

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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.

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

Joint Ventures

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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.

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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

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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.

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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.

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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.

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Our operations are subject to a series of risks related to climate change 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.

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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 29.1% ownership interest in us as of December 31, 2022.

Acquisitions

On October 25, 2022, we acquired certain Marcellus gas gathering and compression assets from Crestwood Equity Partners LP (NYSE: CEQP) (“Crestwood”) for $205 million in cash, before closing adjustments, which was funded by borrowings under our Credit Facility. These assets include 72 miles of dry gas gathering pipelines and nine compressor stations with approximately 700 MMcf/d of compression capacity. Current throughput of the assets is approximately 200 MMcf/d, resulting in significant available capacity for growth.

Additionally, on December 21, 2022, we acquired certain Utica compression assets from EnLink Midstream LLC (NYSE: ENLC) (“EnLink”) for $10 million in cash, before closing adjustments, which was funded by borrowings under our Credit Facility. These assets include four compressor stations with approximately 380 MMcf/d of compression capacity. The acquired compression assets are interconnected with the Company’s existing low pressure and high pressure gathering systems and service Antero Resources’ production. Current throughput of the assets is approximately 100 MMcf/d. See Note 6—Property and Equipment to the consolidated financial statements for more information on our asset acquisitions.

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 with MarkWest 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 will allow 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 180^th 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

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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 a premier midstream energy company to service Antero Resources and the other operators in the Appalachian Basin.

Culture of Continuous Improvement and Responsible Stewardship

We 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. We believe natural gas is key to the energy transition because of its ability to provide energy security to developing nations and replace more GHG-intensive sources of fuel. We embrace our role in providing the infrastructure that supports a low-carbon future and seek to build upon past GHG emission reduction efforts. Our 2021 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 2021 ESG Report and other 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. Additionally, see “—Regulation of Environmental and Occupational Safety and Health Matters” for more information on GHG emissions and “Item 1A. Risk Factors” for risks and uncertainties related to our business operations.

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 16—Reportable Segments to our consolidated financial statements.

Our Assets

Our gathering and compression 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, 2022:


	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	390	230	4.6	226	137

During the year ended December 31, 2022, we added (i) 126 miles of gathering and compression pipelines, including 72 miles of acquired gathering pipelines, (ii) 1.2 Bcf/d of compression capacity, including approximately 1.1 Bcf/d of acquired compression capacity, and (iii) 13 miles of buried and surface water pipelines in the Appalachian Basin. As of December 31, 2022, we had the ability to store 5.5 million barrels of water in 36 impoundments. 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. See Note 6—Property and Equipment to our consolidated financial statements for more information. 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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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, 2022, substantially all of Antero Resources’ approximate 553,000 gross acres (504,000 net acres) are dedicated to us for gathering, compression and water services. During the year ended December 31, 2022, Antero Resources produced, on average, 3.2 Bcfe/d net (32% liquids). As of December 31, 2022, Antero Resources’ estimated net proved reserves were 17.8 Tcfe, which were comprised of 58% natural gas, 41% NGLs and 1% oil. As of December 31, 2022, Antero Resources’ drilling inventory consisted of 1,819 identified gross potential horizontal well locations (approximately 1,816 of which were located 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 drilling program continues. Antero Resources announced its 2023 drilling and completion budget is $875 million to $925 million, and includes plans to complete 75 to 80 gross wells in the Appalachian Basin. Additionally, Antero Resources’ 2023 capital budget includes $150 million for leasehold expenditures, all of which will be dedicated to us. 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—Risks Related to Our Business.”

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) gathering and compression agreements acquired with the Crestwood assets (the “Marcellus gathering and compression agreements”) and (iii) a compression agreement acquired with the EnLink assets (the “Utica compression agreement” and, together with the 2019 gathering and compression agreement and the Marcellus gathering and compression agreements, the “gathering and compression agreements”). See “—Acquisitions” and Note 6—Property and Equipment 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. Our 2019 gathering and compression agreement has an initial term through 2038, our Marcellus gathering and compression agreements expire between 2023 and 2031 and our Utica compression agreement has two dedicated areas that expire in 2024 and 2030. Upon expiration of each of the Marcellus gathering and compression service agreements and Utica compression agreement, the Company 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 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.

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, substantially all of which are subject to annual CPI-based adjustments. 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% and 70%, respectively, of the 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. In addition, the Marcellus gathering and compression agreements provides for a minimum volume commitment that requires Antero Resources to utilize or pay for 25% of the capacity of new compressor station construction for 10 years. Minimum volume commitments are aggregated such that there is a single minimum volume commitment for the respective service each year for each agreement. Additional gathering lines and compressor stations installed on our own initiative are not subject to these minimum volume commitment 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.

Our 2019 gathering and compression agreement includes a growth incentive fee program that allows for a reduction in our low pressure gathering fees if Antero Resources achieves certain volumetric targets. Antero Resources’ throughput on acquired assets is not considered in low pressure gathering volume targets. Antero Resources earned $48 million in fee rebates during the year ended December 31, 2022 by achieving all of its quarterly volumetric targets. The growth incentive fee rebate program expires December 31, 2023, and the following table summarizes the remaining low pressure gathering growth incentive targets for 2023. If actual low pressure volumes are below the lowest tier for the respective quarterly period, Antero Resources will not receive a fee rebate on low

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pressure gathering fees.


	Low Pressure Gathering	Quarterly Fee
	Volume Growth Incentive	Reduction
	Targets (MMcf/d)	(in millions)
Calendar Year 2023
Threshold 1	>2,900 and <3,150	$12.0
Threshold 2	>3,150 and <3,400	$15.5
Threshold 3	>3,400	$19.0

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 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. Under the agreement, we receive a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. 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.

Gas Processing and NGL 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 NGL 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

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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 its material leases, easements, rights-of-way, permits and licenses.

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 this contract, see “—Our Relationship with Antero Resources—Contractual 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 NGL 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 NGL’s final destination, absent a break in the interstate movement. Antero Midstream believes that the crude oil and NGL 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 NGL 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 NGL 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

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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 2023, FERC issued an order (Order No. 886) 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 $1,496,035 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 NGL pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil, NGL and natural gas transmission pipelines in certain high risk areas, such as high-consequence areas (“HCAs”) or moderate consequence areas (“MCAs”).

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:

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perform ongoing assessments of pipeline integrity;

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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 pipelines as necessary; and

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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 January 2023, those maximum civil penalties were increased to $257,664 and $2,576,627, 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 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. 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. We are in the process of assessing the impact of these rules on our future costs of operations and revenue from operations, but we do not expect our operations to be affected by these new rules 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. 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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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;

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

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

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

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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 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. 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

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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 it 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.

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. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, for ozone from 75 to 70 parts per billion, and completed attainment/non-attainment designations in July 2018. Subsequently, in 2020, the Trump Administration decided to leave this standard in place, but the Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard. A final decision is not expected until 2023. These decisions are subject to legal challenge, and any proposed rule will likely be subject to legal challenge as well. 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 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.

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 federal and state waters. 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. In 2015 and 2020, respectively, the Obama and Trump

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Administrations each published final rules attempting to define the federal jurisdictional reach over waters of the United States (“WOTUS”). However, both of these rulemakings have been subject to legal challenge, and the Biden administration has announced plans to establish its own definition of WOTUS. Most recently, the EPA and Corps published a final rule based on the pre-2015 definition, with updates to incorporate existing Supreme Court decisions and regulatory guidance. However, several legal challenges have been filed against the final rule, the outcomes of which cannot be predicted at this time. Additionally, in October 2022, the Supreme Court heard arguments on a case on the scope and authority of the CWA and the definition of WOTUS, a decision on which is expected in 2023. As a result of these developments, the scope of jurisdiction under the CWA is uncertain at this time. To the extent 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 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. This vacatur was subsequently stayed by the U.S. Supreme Court in April 2022, and the EPA has proposed a rule to update and replace the relevant regulations, for which public comment closed in August 2022. While the Corps has resumed permitting decisions for such NWPs, the Corps has advised that, as part of the permitting decision process, the Corps will coordinate with certifying authorities on Section 401 certifications as needed, which may result in permit delays or otherwise impact our operations. Litigation regarding the use of NWP 12 is ongoing. Additionally, in March 2022, the Corps announced it would seek stakeholder input on a formal review of NWP 12, which is also ongoing. 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.

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 will be 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

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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.

Climate Change

In response to findings that emissions 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. 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. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified and existing oil and gas facilities. Subsequently, Congress approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. In November 2022, the EPA published a supplemental proposal which, among other items, would impose expanded inspection, monitoring and emissions control requirements on oil and gas sites, as well as strengthen requirements related to emissions from equipment and routine flaring. The proposal would also establish a “Super Emitter Response Program” that would require operator response to emissions events exceeding 200 pounds per hour, as detected by regulatory authorities or qualified third parties. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, all of these regulatory actions will likely be subject to legal challenges. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. These rules (and any additional regulations) could impose new compliance costs and permitting burdens on natural gas operations.

In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed legislation such as the IRA 2022 advances numerous climate-related objectives. President Biden has highlighted that addressing climate change is a priority of his administration. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the oil and natural gas industry and increased emphasis on climate-related risks across agencies and economic sectors. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. Most recently, in August 2022 the Inflation Reduction Act (“IRA 2022”) was signed into law, appropriating significant federal funding for renewable energy initiatives and, for the first time ever, imposing a federal fee on excess methane emissions from certain oil and gas facilities. The emissions fee and renewable and low-carbon energy funding provisions of the law 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. Internationally, 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. Additionally, in November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain oil and natural gas subsidies and pursue further action on

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non-CO2 GHGs. These goals were reaffirmed at the 27^th Conference of the Parties in November 2022, and countries were called upon to accelerate efforts towards the phase-out of inefficient oil and natural gas subsidies, though no firm commitment or timeline was made. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” an initiative committing to a collective goal of reducing global methane emissions by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.

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 2021 was 0.029%, 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 2022, our GHG/methane emission reduction efforts included the following activities:

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Conducted quarterly facility LDAR inspections on all of our compressor stations, excluding the compressor stations acquired during the fourth quarter of 2022.

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Installed pigging blowdown capture systems at eight locations including six pipeline interchanges and two compressor stations.

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

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Conducted a successful field pilot test with major engine manufacturer to reduce total carbon emissions while increasing the efficiency of the engine by adding additional horsepower, and developed a solution to deploy such technology on additional engines within our fleet.

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Utilized continuous monitoring technology over a tank farm at one of our compressor stations to identify and correct fugitive emissions that may occur between forward-looking infrared camera inspections.

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Developed, field tested and submitted patent pending technology that passed proof of concept examination for hydraulic emission displacement designed to eliminate GHG emissions from pipeline maintenance activities.

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Held meetings with our ESG Advisory Council that is comprised of a cross-disciplinary group of internal subject matter experts who partner with our GHG/Methane Reduction Team to manage ESG (including climate change) risks, opportunities and strategies.

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Held quarterly meetings with our GHG/Methane Reduction Team comprised of internal subject matter experts to review emerging methane detection and quantification technologies applicable to midstream operations.

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 connection with complying with environmental laws or environmental remediation matters in 2022. 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 matters, see “Item 1A. Risk Factors—Compliance with Regulations—Increasing attention to ESG matters and conservation measures may adversely impact our business.”

Increasingly, oil and natural gas companies are exposed to litigation risks from climate change. A number of parties have brought suits against oil and natural gas companies in state or federal court for alleged contributions to, or failures to disclose the impacts of, climate change. While we are not currently party to any such litigation, we could be named in future actions making similar claims of liability. Moreover, to the extent that societal pressures or political or other factors are involved, it is possible that 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 change policies. Financial institutions may adopt policies that

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have the effect of reducing the funding provided to the oil and natural gas industry. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector 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. Additionally, financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the oil and natural gas industry. For example, the Federal Reserve has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. In January 2023, the Federal Reserve released instructions for a pilot climate scenario analysis being undertaken by six of the U.S.’s largest banks, which is expected to conclude near the end of 2023. While we cannot predict what policies may result from this, 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, the SEC has proposed a rule requiring registrants to include certain climate-related disclosures, including Scope 1, 2 and 3 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and periodic reports. The final rule is expected in 2023. Although the final form and substance of these requirements is not yet known, and we cannot predict what any such rules may require to the extent the rules impose additional reporting obligations, we could face increased costs. Additionally, we cannot predict how financial institutions and investors might consider any information disclosed under a final rule when making investment decisions, and it is possible as a result that we could face increases with respect to the costs of, or restrictions imposed on, our access to capital. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient.

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, 2022, approximately 586 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:

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comprehensive health insurance, including vision and dental; we have not increased employee premiums in over 15 years;

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

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

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competitive paid time off and sick leave programs;

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paid parental leave;

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student loan repayment matching opportunities; and

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wellness support benefits including an employee assistance program, short-term and long-term disability coverage and subsidized gym memberships 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.

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.

We have continued to operate throughout the COVID-19 pandemic, in some cases subject to federal, state and local regulations, and we have taken and continue to take steps to protect the health and safety of our workers. In response to the COVID-19 pandemic, we have implemented protocols that we believe to be in the best interest of our employees, as well as the communities in which we operate, and that comply with government orders, when applicable. During 2022, we transitioned from a hybrid working arrangement for non-field level employees, which involved a combination of in-office and remote work-from-home arrangements, to an in-office working arrangement for all non-field level employees. We continue to monitor the COVID-19 environment in order to protect the health and safety of our employees.

Diversity, Inclusion and Workplace Culture

We are committed to building a culture where diversity and inclusion are core philosophies across our operations, including, but not limited to, our decisions around recruitment, promotion, transfer, leaves of absence, compensation, opportunities for career support and advancement, job performance and other relevant job-related criteria. We embrace an approach to hiring and

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advancement that considers the value of diversity, and we are also 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 diversity, inclusion and belonging. Finally, in line with our commitments to equal employment opportunity and diversity and inclusion, we expect recruiters operating on our behalf to provide us with a diverse pool of candidates.

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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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;

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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.

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, 2022 (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.

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 daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu in 2022, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $123.64 per barrel to a low of $71.05 per barrel during the same period. While oil and natural gas prices have recovered from the lows experienced in 2020, 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 (approximately 58% 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 lower prices experienced during 2020 together with an 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 agreements, 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.

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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. In response to the COVID-19 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. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, caused extreme market volatility and a substantial adverse effect on commodity prices. As vaccines became widely available, social distancing guidelines, travel restrictions and stay-at-home orders eased, activity in the global economy increased and demand for oil, natural gas and NGLs, and related commodity pricing, improved. The extent to which the pandemic will impact our business results and operations remains uncertain in light of the rapidly evolving environment, duration and severity of the spread of the virus, and emerging variants, effectiveness of the vaccine and booster shots, public acceptance of safety protocols, and government measures, including vaccine mandates, designed to slow and contain the spread of COVID-19, among others. Also, as a result of this imbalance, the industry has experienced and may experience in the future storage capacity constraints with respect to oil and certain NGL products. 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, 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. For example, the construction of our water treatment facility took longer than planned and the facility ran at operating rates below the designed capacity and did not meet certain completion milestones under the terms of the construction contract. As a result, in September 2019, we decided to idle such facility for the foreseeable future. Following such idling, we recorded aggregate non-cash impairment charges of approximately $463 million and expect to incur additional idling costs going forward. 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. In addition, 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

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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 those articles. On August 28, 2020, the U.S. announced that it would lower one of the quantitative limitations on imports of 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 also engaged in discussions regarding steel imports pursuant to their Joint Statement of May 17, 2019. On August 31, 2020, the Office 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 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 have risen and are expected to continue to rise. These price increases 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, NGL and oil prices, especially in light of the recent declines,

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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, NGL and oil exploration and production activities. Water is an essential component of natural gas, NGL 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 change-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.

Increasing attention to ESG matters and conservation measures may adversely impact our business.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG 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. Increasing attention to climate change 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. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.

Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets, including our goals 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, 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 impact instead of actual changes in our ESG 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. 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. Also, despite these aspirational goals, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals, but we

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cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG 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, institutional lenders may decide not to provide funding for oil and natural gas companies or the corresponding infrastructure projects based on climate change related concerns, which could affect our access to capital for potential growth projects. Moreover, to the extent ESG 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 ESG 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:

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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;

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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;

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

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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;

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fires, ruptures and explosions;

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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

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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:

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injury or loss of life;

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

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations; and

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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.

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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.

A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.

The global or national outbreak of an infectious disease, such as COVID-19, 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, to address the COVID-19 pandemic 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 any such outbreak may also adversely affect our business and results of operations. For example, the effects of COVID-19 and concerns regarding its global spread have negatively impacted global demand for crude oil and natural gas, which could continue to contribute to price volatility impacting the price Antero Resources receives for its natural gas, NGLs and oil. In addition, COVID-19 could continue to materially and adversely affect the demand for and marketability of natural gas, NGLs and oil production and production levels. Although Antero Resources has not been required to curtail or shut-in a portion of its production, it may do so in the future. 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,” the effects of which may be heightened to the extent the COVID-19 pandemic adversely affects our business and financial results.

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. 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, 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 of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. 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 or loss of our proprietary and potentially sensitive data, delays in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions or other operational disruptions and third-party liabilities. Moreover, we may not be able to anticipate, detect or prevent all cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until such attack is underway, 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, and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.

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. 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

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infrastructure may result in increased capital and operating costs. A cyberattack or security breach could result in liability under data privacy laws, regulatory penalties, damage to our reputation or a 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. 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 our revolving 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 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 capital markets, including the market for senior unsecured notes, and our financial condition at such time. Any refinancing of our indebtedness, including using borrowings under our revolving 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 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. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our revolving 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 addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing shares of common stock may result in significant stockholder dilution. Neither Antero Resources or any of its affiliates is committed to providing any direct or indirect support to fund our growth.

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 improved in 2022 and 2021 as compared to 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.

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

Our revolving credit facility limits our ability to, among other things:

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incur or guarantee additional debt;

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redeem or repurchase units or make distributions under certain circumstances;

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make certain investments;

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enter into mergers;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

The indentures governing our senior notes contains similar restrictive covenants. In addition, our revolving 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 our revolving credit facility if doing so would cause us to breach a financial covenant.

The provisions of our revolving 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 our revolving credit facility or the indentures governing our senior notes could result in a default or an event of default that 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

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:

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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;

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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;

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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

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pursue growth opportunities, reduce cash flow used for our services and place us at a competitive disadvantage. For example, during 2022, we had average outstanding borrowings under our revolving credit facility of approximately $619 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 approximately $6 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

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.

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. Our revolving 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;

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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;

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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 and (iii) we have, subject to limited exceptions, renounced, to the fullest extent permitted by law, any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities;

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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

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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.

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:

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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 NGL products.

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.

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

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Environmental Policy Act 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 example, 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 has proposed a rule to update and replace the relevant regulations, public comment on which closed in August 2022. While the Corps has resumed permitting decisions for such NWPs, the Corps has advised that, as part of the permitting decision process, the Corps will coordinate with certifying authorities on Section 401 certifications as needed, which may result in permit delays or otherwise impact our operations. 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 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. 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. In 2015 and 2020, respectively, the Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over WOTUS. However, both of these rulemakings have been subject to legal challenge, and the Biden administration has announced plans to establish its own definition of WOTUS. More recently, the EPA and Corps published a rule to finalize a rule based on the pre-2015 regulations, incorporating updates from Supreme Court decisions and regulatory guidance. However, this rule is currently subject to legal challenge. Additionally, in October 2022, the Supreme Court heard arguments on a case on the scope and authority of the CWA and the definition of WOTUS. As a result, the scope of the CWA’s jurisdiction is uncertain at this time. To the extent any action further expands 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. 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.

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

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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 $1,496,035 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.

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. For example, President Biden has made action on environmental matters, and climate change in particular, a focus of his administration, and our operations and those of our clients, may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and GHG emissions.

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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 accelerate the transition to a low carbon economy 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. In addition, the IRA 2022 imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. The methane charge and the incentives for renewable energy infrastructure development could impose additional costs on our operations and further accelerate the transition of the economy away from the use of oil and natural gas towards lower- or zero-carbon emissions alternatives. This could decrease demand for oil and gas and consequently, adversely affect our business and results of operations and those of our customers.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration, which includes certain potential initiatives for climate change legislation to be proposed and passed into law. Moreover, 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. For example, in response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, 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.

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. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified and existing oil and gas facilities. Subsequently, the U.S. Congress approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated

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emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. In November 2022, the EPA published a supplemental proposal which, among other items, would impose expanded inspection, monitoring and emissions control requirements on oil and gas sites, as well as strengthen requirements related to emissions from equipment and routine flaring. The proposal would also establish a “Super Emitter Response Program” that would require operator response to emissions events exceeding 200 pounds per hour, as detected by regulatory authorities or qualified third parties. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, all of these regulatory actions will likely be subject to legal challenges. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. 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. Additionally, in November 2021, the international community gathered again in Glasgow COP26, during which multiple announcements were made, including a call for parties to eliminate certain oil and natural gas subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” an initiative committing to a collective goal of reducing global methane pollution by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.

Concern over the threat of climate change has also resulted in increasing political risks in the United States, including climate-change related pledges made by President Biden and other public office representatives. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the oil and natural gas industry and increased emphasis on climate-related risks across agencies and economic sectors. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide. Other actions that could be pursued by the Biden administration include more restrictive requirements for the development of pipeline infrastructure or LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities.

Increasingly, oil and natural gas companies are also exposed to litigation risks from climate change. A number of parties have brought suits against oil and natural gas companies in state or federal court for alleged contributions to, or failures to disclose the impacts of, climate change. While we are not currently party to any such litigation, we could be named in future actions making similar claims of liability. Moreover, to the extent that societal pressures or political or other factors are involved, it is possible that 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, in response to concerns related to climate change, 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. Institutional lenders who provide financing to oil and natural gas companies have also become more attentive to sustainable lending practices, and some of them may elect in future not to provide funding for oil and natural gas companies. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. In addition, at COP26, GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector 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. The Federal Reserve has joined the NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. The Federal Reserve also recently released instructions for a pilot climate scenario analysis being undertaken by six of the U.S.’s largest banks through 2023. A material reduction in the capital

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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, the SEC proposed a rule requiring registrants to include certain climate-related disclosures, including Scope 1, 2 and 3 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and periodic reports. The final rule is expected in 2023. Although the final form and substance of these requirements is not yet known, and we cannot predict what any such rules may require to the extent the rules impose additional reporting obligations, we could face increased costs or limitations or restrictions on our access to capital. Separately, the SEC has also announced that is scrutinizing existing climate-change related disclosures in public filings, increasing 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 change 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.

Moreover, climate change 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. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

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:

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perform ongoing assessments of pipeline integrity;

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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

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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 January 2023, those maximum civil penalties were increased to $257,664 and $2,576,627, 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.

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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. We are in the process of assessing the impact of these rules on our future costs of operations and revenue from operations, but we do not expect our operations to be affected by these new rules 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. 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 regulatory changes could have a material effect on our cash flow. See “Business—Pipeline Safety Regulation” for more information.

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 threatened 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 M. Rady, Chairman, President and Chief Executive Officer, could have a material adverse effect on our business, financial condition and results of operations.

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, 2022, Antero Resources beneficially owned 29.1% 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

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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.

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.

Income Taxes

Our future tax liability 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 certain of 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 2027. 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, such as the classification of assets under the income tax depreciation rules, the characterization of expenses for income tax purposes and the tax characterization of the Transactions. Further, any change in law may affect our tax position. 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 (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 affect our business and

future profitability.

We are subject to various complex and evolving U.S. federal, state and local taxes. 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, and may have an adverse effect on our business and future profitability.

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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 majority of our distributions to be in excess of our earnings and profits through 2027. 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.

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

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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;

●

levels of indebtedness;

●

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

●

speculation by the press or investment community;

●

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;

●

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 earnings 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

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the 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. 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.

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 3. Legal Proceedings

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Veolia

The Company is currently involved in a consolidated lawsuit with Veolia Water Technologies, Inc. (“Veolia”) relating to the Clearwater Facility.

On March 13, 2020, Antero Treatment, a wholly owned subsidiary of the Company, filed suit against Veolia in the district court of Denver County, Colorado, asserting claims of fraud, breach of contract and other related claims. Antero Treatment alleges that Veolia failed to meet its contractual obligations to design and build a “turnkey” wastewater disposal facility under a Design/Build Agreement dated August 18, 2015 (the “DBA”), and that Veolia fraudulently concealed certain miscalculations and design flaws during contract negotiations and continued to conceal and fraudulently misrepresent the impact of certain design changes post-execution of the DBA. On March 13, 2020, Veolia filed a separate suit against the Company, Antero Resources, and certain of the Company’s wholly owned subsidiaries (collectively, the “Antero Defendants”) in Denver County, Colorado. In its lawsuit, Veolia asserted breach of contract and equitable claims against the Antero Defendants for alleged failures under the DBA. Veolia’s suit was consolidated into the action filed by Antero Treatment.

Veolia and the Antero Defendants each filed partial motions to dismiss and motions for summary judgment directed at certain claims asserted by the opposing party. A bench trial on the remaining claims was held from January 24 through February 10, 2022 and concluded on February 24, 2022. At trial, Antero Treatment sought damages from Veolia of approximately $450 million, which represents the Company’s out-of-pocket costs associated with the Clearwater Facility project. In the alternative, Antero Treatment sought damages related to multiple breaches of the DBA, totaling approximately $370 million. Also, at trial, Veolia sought monetary damages of approximately $118 million, including alleged delay and extra-contractual costs and a contract balance relating to an allegation that Antero Defendants improperly terminated the DBA.

On January 3, 2023, the Court found that Antero Treatment had prevailed on its claims for breach of contract and fraud, and awarded approximately $242 million in damages to Antero Treatment, plus pre- and post-judgment interest and reasonable costs and attorneys’ fees. The Court also found in Antero Defendants’ favor on all of Veolia’s affirmative claims. On January 27, 2023 the Court entered judgment in favor of Antero Treatment in the amount of $309,183,975 in damages, which includes pre-judgment interest. Antero was also awarded costs and attorneys’ fees, the amount of which will be determined in separate proceedings. The judgment remains subject to appeal and applicable post-judgment proceedings.

Item 4. Mine Safety Disclosures

Not applicable.

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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 10, 2023, shares of our common stock were held by 40 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 10, 2023, Antero Resources and its subsidiaries owned 139,042,345 shares of our common stock, which represented a 29.1% interest in us.

Issuer Purchases of Equity Securities

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


					Approximate
				Total Number of	Dollar Value of
	Total Number	Average Price		Shares Purchased	Shares that May
	of Shares	Paid per		as Part of Publicly	Yet be Purchased
Period	Purchased ⁽¹⁾	Share		Announced Plans ⁽²⁾	Under the Plan
October 1, 2022 – October 31, 2022	11,812	$	9.79	—	$	149,767,409
November 1, 2022 – November 30, 2022	—		—	—		N/A
December 1, 2022 – December 31, 2022	—		—	—		N/A
Total	11,812	$	9.79	—	$	149,767,409

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

(2)

In August 2019, the Board authorized a $300 million share repurchase program, which was extended through June 30, 2023 during the first quarter of 2021. During the three months ended December 31, 2022, we did not make any repurchases under this program. Our share repurchase program will be subject to the new 1% excise tax on stock repurchases imposed under the IRA 2022 for all repurchases on or after January 1, 2023.

Dividends

On January 11, 2023, 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, 2022. The dividend was paid on February 8, 2023 to stockholders of record as of January 25, 2023.

The Board also declared a cash dividend of $138 thousand on shares of our Series A Non-Voting Perpetual Preferred Stock, par value $0.01 (the “Series A Preferred Stock”), that was paid on February 14, 2023 in accordance with the terms of the Series A Preferred Stock, which are discussed in Note 12—Equity and Earnings Per Common Share to our consolidated financial statements. As of December 31, 2022, there were dividends in the amount of $69 thousand 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

Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2017, in each of (i) our predecessor’s, AMGP, common shares through March 12, 2019 and our common stock thereafter (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.

In this section, references to “Antero Midstream,” “AM,” the “Company,” “we,” “us,” and “our” refer to Antero Midstream Corporation and its consolidated subsidiaries, unless otherwise indicated or the context otherwise requires.

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 Acquisitions

On October 25, 2022, we acquired certain Marcellus gas gathering and compression assets from Crestwood for $205 million in cash, before closing adjustments, which was funded by borrowings under our Credit Facility. These assets include 72 miles of dry gas gathering pipelines and nine compressor stations with approximately 700 MMcf/d of compression capacity. Current throughput of the assets is approximately 200 MMcf/d, resulting in significant available capacity for growth.

Additionally, on December 21, 2022, we acquired certain Utica compression assets from EnLink for $10 million in cash, before closing adjustments, which was funded by borrowings under our Credit Facility. These assets include four compressor stations with approximately 380 MMcf/d of compression capacity. The acquired compression assets are interconnected with the Company’s existing low pressure and high pressure gathering systems and service Antero Resources’ production. Current throughput of the assets is approximately 100 MMcf/d. See Note 6—Property and Equipment to the consolidated financial statements for more information on our asset acquisitions.

Market Conditions and Business Trends

Commodity Markets

Prices for natural gas, NGLs and oil increased significantly during the year ended December 31, 2022 as compared to the year ended December 31, 2021. 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, to the extent Antero Resources maintains a maintenance capital program as it has done in recent years, we do not expect to experience substantial variability in our throughput volumes resulting from volatile commodity prices.

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Growth Incentive Fee Program with Antero Resources

Our 2019 gathering and compression agreement with Antero Resources includes a growth incentive fee program whereby we agreed to provide quarterly fee rebates to Antero Resources through December 31, 2023, contingent upon Antero Resources achieving volumetric growth targets on low pressure gathering. Antero Resources’ throughput on the acquired assets is not considered in the low pressure gathering volume targets. If actual low pressure volumes are below the lowest threshold for the respective period, Antero Resources will not earn a reduction in low pressure gathering fees.

The growth incentive fee rebate program expires December 31, 2023, and the following table summarizes the remaining low pressure gathering growth incentive targets through 2023:


	Low Pressure Gathering	Quarterly Fee
	Volume Growth Incentive	Reduction
	Targets (MMcf/d)	(in millions)
Calendar Year 2023
Threshold 1	>2,900 and <3,150	$12.0
Threshold 2	>3,150 and <3,400	$15.5
Threshold 3	>3,400	$19.0

Antero Resources earned $48 million in fee rebates during the year ended December 31, 2022 by achieving all four quarterly volumetric targets for the year. Antero Resources earned $12 million in fee rebates during the year ended December 31, 2021 by achieving the quarterly volumetric target during the fourth quarter of 2021.

Economic Indicators

The economy is experiencing elevated inflation levels as a result of global supply and demand imbalances, where global demand continues to outpace current supplies. For example, the CPI for all urban consumers increased 8% from year ended December 31, 2021 to year ended December 31, 2022 as compared to the Federal Reserve’s stated goal of 2%. See “—Capital Resources and Liquidity—Capital Investment” for more information. In order to manage the inflation risk currently present in the United States’ economy, the Federal Reserve has utilized monetary policy in the form of interest rate increases in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis.

The global economy also continues to be impacted by the effects of the COVID-19 pandemic and global events, among other factors. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. However, neither our nor Antero Resources’ supply chain has experienced any significant interruptions due to the COVID-19 pandemic or global supply and demand imbalances.

Inflationary pressures and supply chain disruptions could result in further increases to our operating and capital costs that are not fixed. Additionally, these economic variables could lead to a renegotiation of contracts and/or supply agreements, among others. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

COVID-19 Pandemic

We continue to operate throughout the COVID-19 pandemic, in some cases subject to federal, state and local regulations, and we have taken and continue to take steps to protect the health and safety of our workers. We have implemented protocols to reduce the risk of an outbreak within our field operations and offices, and these protocols have not impacted Antero Resources’ production, our throughput or our business activities. During 2022, we transitioned from a hybrid working arrangement for non-field level employees, which involved a combination of in-office and remote work-from-home arrangements, to an in-office working arrangement for all non-field level employees. We have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting. We continue to monitor the COVID-19 environment in order to protect the health and safety of our employees.

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

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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 2032. 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 the consolidated financial statements for more 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’ 553,000 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, 2022, Antero Resources had disclosed estimated net proved reserves of 17.8 Tcfe, of which 58% was natural gas, 41% were NGLs and 1% was oil. As of December 31, 2022, Antero Resources’ drilling inventory consisted of 1,819 gross identified potential horizontal well locations, substantially all of which were 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 the consolidated financial statements for more information on our water services agreement.

Principal Components of Our Cost Structure

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

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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 to a lesser extent 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.

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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 (i) costs allocated to Antero Midstream by Antero Resources for grants made prior to March 12, 2019 pursuant to the Antero Resources Corporation Long-Term Incentive Plan and (ii) costs related to the Antero Midstream Corporation Long-Term Incentive Plan.

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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.

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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.

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

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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 tax liabilities exceed our deferred tax assets. Our deferred tax assets result primarily from net operating loss carryforwards. As of December 31, 2022, we had approximately $415 million of U.S. federal NOL carryforwards, and approximately $478 million of state NOL carryforwards. The Company currently considers all of its deferred tax assets, except for those related to charitable contributions, realizable. The amount of deferred 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 a discussion of our deferred tax position and income tax expense.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to evaluate our performance. These metrics help us identify factors and trends that impact our operating results, profitability and financial condition. The following are the key metrics we use to evaluate our business:

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Adjusted EBITDA. We use Adjusted EBITDA as a corporate-level performance measure to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and return capital to stockholders. Adjusted EBITDA is a non-GAAP financial measure. See “—Non-GAAP Financial Measures” below for more information regarding this financial measure, including a reconciliation to its most directly comparable GAAP measure.

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Gathering and Compression Throughput. We must continually obtain additional supplies of natural gas to maintain or increase throughput on our systems. Our ability to maintain existing supplies of natural gas and obtain additional supplies is primarily impacted by (i) our acreage dedication and the level of successful drilling activity by Antero Resources and (ii) the potential for acreage dedications with and successful drilling by third-party producers. Any increase in our throughput volumes over the near term will likely be driven by Antero Resources continuing its drilling and development activities on its Appalachian Basin acreage.

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Water Handling Volumes. Our fresh water volumes are primarily driven by hydraulic fracturing activities conducted as part of well completions. Our other fluid handling volumes are driven by hydraulic fracturing activities and produced water volumes, which are primarily a function of Antero Resources’ completion activities and production. Antero Resources’ consolidated acreage position allows us to provide fresh water and other fluid handling services for Antero Resources’ completion activities in a more efficient manner. However, to the extent that Antero Resources’ drilling and completion schedule is not met, or Antero Resources uses less fresh water and other fluid handling services in its well completion operations than expected (for example, due to a reduction in completions), and production declines, our water volumes may decline.

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Results of Operations

We have two operating 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, fractionation and high-pressure gas gathering services 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.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2022

The operating results of our reportable segments were as follows:


	Year Ended December 31, 2021
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated ⁽¹⁾		Total
Revenues:
Revenue–Antero Resources	$	761,737		218,621		—		980,358
Revenue–third-party		—		516		—		516
Gathering—low pressure fee rebate		(12,000)		—		—		(12,000)
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		712,651		185,551		—		898,202
Operating expenses:
Direct operating		65,983		91,137		—		157,120
General and administrative (excluding equity-based compensation)		26,261		20,317		3,731		50,309
Equity-based compensation		10,119		2,500		910		13,529
Facility idling		—		3,997		—		3,997
Depreciation		59,692		49,098		—		108,790
Impairment of property and equipment		4,608		434		—		5,042
Accretion of asset retirement obligations		—		460		—		460
Loss on asset sale		3,628		—		—		3,628
Total operating expenses		170,291		167,943		4,641		342,875
Operating income		542,360		17,608		(4,641)		555,327
Other income (expense):
Interest expense, net		—		—		(175,281)		(175,281)
Equity in earnings of unconsolidated affiliates		90,451		—		—		90,451
Loss on early extinguishment of debt		—		—		(21,757)		(21,757)
Total other income (expense)		90,451		—		(197,038)		(106,587)
Income before income taxes		632,811		17,608		(201,679)		448,740
Income tax expense		—		—		(117,123)		(117,123)
Net income and comprehensive income	$	632,811		17,608		(318,802)		331,617

Adjusted EBITDA ⁽²⁾							$	876,438

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

(2)	Adjusted EBITDA is a non-GAAP financial measure. For a discussion of this measure, including a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, see “—Non-GAAP Financial Measures”.

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	Year Ended December 31, 2022
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated ⁽¹⁾		Total
Revenues:
Revenue–Antero Resources	$	791,265		244,770		—		1,036,035
Revenue–third-party		—		2,622		—		2,622
Gathering—low pressure fee rebate		(48,000)		—		—		(48,000)
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		706,179		213,806		—		919,985
Operating expenses:
Direct operating		75,889		104,365		—		180,254
General and administrative (excluding equity-based compensation)		24,578		13,080		4,813		42,471
Equity-based compensation		14,394		4,415		845		19,654
Facility idling		—		4,166		—		4,166
Depreciation		81,390		50,372		—		131,762
Impairment of property and equipment		1,130		2,572		—		3,702
Accretion of asset retirement obligations		—		222		—		222
Loss on settlement of asset retirement obligations		—		539		—		539
Gain on asset sale		(2,120)		(131)		—		(2,251)
Total operating expenses		195,261		179,600		5,658		380,519
Operating income		510,918		34,206		(5,658)		539,466
Other income (expense):
Interest expense, net		—		—		(189,948)		(189,948)
Equity in earnings of unconsolidated affiliates		94,218		—		—		94,218
Total other income (expense)		94,218		—		(189,948)		(95,730)
Income before income taxes		605,136		34,206		(195,606)		443,736
Income tax expense		—		—		(117,494)		(117,494)
Net income and comprehensive income	$	605,136		34,206		(313,100)		326,242

Adjusted EBITDA ⁽²⁾							$	884,226

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

(2)	Adjusted EBITDA is a non-GAAP financial measure. For a discussion of this measure, including a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, see “—Non-GAAP Financial Measures”.

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The operating data for Antero Midstream is as follows:


	Year Ended				Amount of
	December 31,				Increase		Percentage
	2021		2022		or Decrease		Change
Operating Data:
Gathering—low pressure (MMcf)		1,060,444		1,088,036		27,592		3	%
Compression (MMcf)		1,006,366		1,034,052		27,686		3	%
Gathering—high pressure (MMcf)		1,037,094		1,027,459		(9,635)		(1)	%
Fresh water delivery (MBbl)		34,572		37,685		3,113		9	%
Other fluid handling (MBbl)		16,930		19,059		2,129		13	%
Wells serviced by fresh water delivery		75		76		1		1	%
Gathering—low pressure (MMcf/d)		2,905		2,981		76		3	%
Compression (MMcf/d)		2,757		2,833		76		3	%
Gathering—high pressure (MMcf/d)		2,841		2,815		(26)		(1)	%
Fresh water delivery (MBbl/d)		95		103		8		8	%
Other fluid handling (MBbl/d)		46		52		6		13	%
Average Realized Fees:
Average gathering—low pressure fee ($/Mcf) ⁽¹⁾	$	0.33	��	0.34		0.01		3	%
Average compression fee ($/Mcf)	$	0.20		0.21		0.01		3	%
Average gathering—high pressure fee ($/Mcf)	$	0.20		0.21		0.01		3	%
Average fresh water delivery fee ($/Bbl)	$	3.97		4.07		0.10		3	%
Joint Venture Operating Data:
Processing—Joint Venture (MMcf)		543,649		540,052		(3,597)		(1)	%
Fractionation—Joint Venture (MBbl)		13,644		13,022		(622)		(5)	%
Processing—Joint Venture (MMcf/d)		1,489		1,480		(9)		(1)	%
Fractionation—Joint Venture (MBbl/d)		37		36		(1)		(3)	%

(1)	The year ended December 31, 2021 average realized fee does not include $2.4 million of low pressure gathering fee revenues which volumes relate to prior periods.

Revenues. Total revenues increased by $22 million, from $898 million for the year ended December 31, 2021, to $920 million for the year ended December 31, 2022. Amortization of customer relationships was $71 million during the years ended December 31, 2021 and 2022. Gathering and processing revenues decreased by 1%, from $713 million for the year ended December 31, 2021 to $706 million for the year ended December 31, 2022. Water handling revenues increased by 15%, from $185 million for the year ended December 31, 2021 to $214 million for the year ended December 31, 2022. These fluctuations primarily resulted from the following:

Gathering and Processing

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Low pressure gathering revenue decreased $22 million period over period primarily due to $36 million in higher fee rebates to Antero Resources during the year ended December 31, 2022, partially offset by a 3% increase in the low pressure gathering rate as a result of the annual CPI-based adjustment and by increased throughput volumes of 28 Bcf, or 76 MMcf/d. Low pressure gathering volumes increased between periods primarily due to 327 additional wells being connected to our system since December 31, 2021, of which 253 wells are from our asset acquisitions that closed during the fourth quarter of 2022.

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Compression revenue increased $11 million period over period due to a 3% increase in the compression rate as a result of the annual CPI-based adjustment, as well as increased throughput volumes of 28 Bcf, or 76 MMcf/d and our asset acquisitions during the fourth quarter of 2022. Compression volumes increased primarily due to additional wells connected to our system since December 31, 2021 and 12 compressor stations that were acquired during the fourth quarter of 2022.

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High pressure gathering revenue increased $4 million period over period due to a 3% increase to the high pressure gathering rate as a result of the annual CPI-based adjustment partially offset by decreased throughput volumes of 10 Bcf, or 26 MMcf/d. The high pressure gathering volumes decreased period over period primarily as a result of higher production from Antero Resources that was subject to a third-party high pressure gathering acreage dedication, partially offset by 74 new wells connected to our high pressure system since December 31, 2021. The assets we acquired during the year ended

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December 31, 2022 were connected to our high pressure system prior to such acquisitions, and therefore, the 253 wells connected to such assets were already gathered by our existing high-pressure gathering system.

Water Handling

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Fresh water delivery revenue increased $16 million period over period primarily due to increased fresh water delivery volumes of 3 MMBbl, or 8 MBbl/d and a 3% increase to the fresh water delivery rate as a result of the annual CPI-based adjustment.

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Other fluid handling services revenue increased $13 million period over period primarily due to increased costs, partially due to inflationary pressures that impact our cost plus 3% and cost of service rates, and increased other fluid handling volumes of 2 MMBbl, or 6 MBbl/d.

Direct operating expenses. Total direct operating expenses increased by 15%, from $157 million for the year ended December 31, 2021 to $180 million for the year ended December 31, 2022. Gathering and processing direct operating expenses increased 15% from $66 million for the year ended December 31, 2021 to $76 million for the year ended December 31, 2022 primarily due to (i) higher throughput volumes between periods, (ii) 12 acquired compressors that came online during the fourth quarter of 2022 and (iii) higher chemical, fuel, labor and heavy maintenance expense. Water handling direct operating expenses increased by 15%, from $91 million for the year ended December 31, 2021 to $104 million for the year ended December 31, 2022 primarily due to increased water blending locations, trucking rates, labor costs and Utica fresh water deliveries between periods.

General and administrative (excluding equity-based compensation) expenses. General and administrative expenses (excluding equity-based compensation expense) decreased 16%, from $50 million for the year ended December 31, 2021 to $42 million for the year ended December 31, 2022 primarily due to (i) lower legal costs associated with the Veolia legal matter between periods and (ii) lower costs allocated to us from Antero Resources.

Equity-based compensation expenses. Equity-based compensation expenses increased by 45% from $14 million to $20 million for the years ended December 31, 2021 and 2022, respectively, primarily due to an increase in the annual equity awards granted during the year ended December 31, 2022 compared to prior years.

Facility idling expenses. Facility idling expenses remained consistent at $4 million for each of the years ended December 31, 2021 and 2022.

Depreciation expense. Total depreciation expense increased by 21% from $109 million for the year ended December 31, 2021 to $132 million for the year ended December 31, 2022. This increase is primarily due to (i) $16 million for a phased early retirement of an underutilized compressor station, (ii) $6 million related to gathering and processing system assets placed in service during 2022 and (iii) $1 million for our asset acquisitions during the fourth quarter of 2022. The phased early retirement of an underutilized compressor station began in the second quarter of 2022 and will be completed by the first half of 2023, and allows us to relocate and reuse the compressor units and equipment to (i) expand an existing compressor station and/or (ii) contribute to a new compressor station. There are certain costs associated with the underutilized compressor station that cannot be relocated or reused, and such costs will be fully depreciated during the first half of 2023.

Impairment of property and equipment expense. Impairment of property and equipment expense of $5 million for the year ended December 31, 2021 was primarily a lower of cost or net realizable value adjustment for pipe inventory. Impairment of property and equipment expense of $4 million for the year ended December 31, 2022 was primarily due to (i) a write-down of the Clearwater Facility related to the retirement obligation for the facility and (ii) cancelled projects.

Loss (gain) on asset sale. Loss on asset sale of $4 million for the year ended December 31, 2021 primarily relates to the sale of excess pipe inventory. Gain on asset sale of $2 million for the year ended December 31, 2022 primarily relates to (i) the sale of four compressor engines, (ii) reimbursement of certain cancelled projects and (iii) sale of miscellaneous equipment and excess pipe inventory.

Interest expense. Interest expense increased by 8%, from $175 million for the year ended December 31, 2021 to $190 million for the year ended December 31, 2022 primarily due to (i) the issuance of $750 million of 5.375% senior notes due June 15, 2029 (the “2029 Notes”) on June 8, 2021, (ii) increased interest rates on our Credit Facility due to higher benchmark rates during the year ended December 31, 2022, and (iii) increased borrowings on our Credit Facility due to our asset acquisitions, partially offset by the redemption of all $650 million of the 2024 Notes on June 8, 2021.

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Equity in earnings of unconsolidated affiliates. Equity in earnings in unconsolidated affiliates increased by 4%, from $90 million for the year ended December 31, 2021 to $94 million for the year ended December 31, 2022 primarily due to higher Joint Venture earnings as a result of annual CPI-based adjustments for processing and fractionation fees, partially offset by lower processed volumes at the Joint Venture between periods.

Loss on early extinguishment of debt. Loss on early extinguishment of debt for the year ended December 31, 2021 of $22 million primarily relates to the redemption of all $650 million of the 2024 Notes at a premium to par of $17 million as well as the write-off of $6 million of unamortized deferred financing costs, partially offset by $2 million of unamortized premium. There was no loss on early extinguishment of debt for the year ended December 31, 2022.

Income tax expense. Income tax expense remained consistent for the years ended December 31, 2021 and 2022 at $117 million, which reflects effective tax rates of 26.1% and 26.5%, respectively.

Net income. Net income decreased by 2% from $332 million for the year ended December 31, 2021 to $326 million for the year ended December 31, 2022. The decrease between periods was primarily related to higher direct operating costs, depreciation expense and interest expense and lower gathering and processing revenues, partially offset by higher water handling revenues, higher equity in earnings from unconsolidated affiliates and lower general and administrative costs.

Adjusted EBITDA. Adjusted EBITDA increased by 1%, from $876 million for the year ended December 31, 2021 to $884 million for the year ended December 31, 2022. The increase between periods was primarily due to higher water handling revenues and lower general and administrative costs, excluding equity-based compensation, partially offset by higher direct operating costs and lower gathering and processing revenues. For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, read “—Non-GAAP Financial Measures” below.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2021

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” in our 2021 Annual Report on Form 10-K for a discussion of the results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2021.

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 and capital market transactions. See Note 8—Long-Term Debt to our consolidated financial statements. We expect that the combination of these capital resources will be adequate to meet our working capital requirements, capital expenditures program, expected quarterly cash dividends and share repurchases under our share repurchases program for at least the next 12 months.

During the year ended December 31, 2022, we paid dividends of $0.90 per share, or a total of $433 million, to holders of our common stock, as applicable, and we paid $550 thousand of dividends on our Series A Preferred Stock. On January 11, 2023, the Board declared a cash dividend on the shares of our common stock of $0.2250 per share for the quarter ended December 31, 2022 paid on February 8, 2023 to stockholders of record as of January 25, 2023. The Board also declared an aggregate cash dividend of $138 thousand on our Series A Preferred Stock that was paid on February 14, 2023. As of December 31, 2022, there were dividends in the amount of $69 thousand accumulated in arrears on our Series A Preferred Stock.

As of December 31, 2022, we did not have any off-balance sheet arrangements.

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Cash Flows

The following table and discussion presents a summary of our net cash provided by (used in) operating activities, investing activities and financing activities for the periods indicated:


	Year Ended December 31,
(in thousands)	2021		2022
Net cash provided by operating activities	$	709,752		699,604
Net cash used in investing activities		(233,242)		(493,826)
Net cash used in financing activities		(477,150)		(205,778)
Net decrease in cash and cash equivalents	$	(640)		—

Year Ended December 31, 2021 Compared to Year Ended December 31, 2022

Operating Activities. Net cash provided by operating activities was $710 million and $700 million for the years ended December 31, 2021 and 2022, respectively. The decrease in net cash provided by operating activities between periods was primarily the due to (i) $16 million in income tax refunds received during the year ended December 31, 2021 from certain net operating loss carryback provisions included in the Coronavirus Aid, Relief, and Economic Security Act that was enacted in March 2020, (ii) higher direct operating costs, (iii) lower gathering and processing revenues, (iv) higher asset retirement obligation settlement costs and (v) higher interest expense payments, partially offset by higher water handling revenues and lower general and administrative costs, excluding equity-based compensation.

Investing Activities. Net cash flows used in investing activities was $233 million and $494 million for the years ended December 31, 2021 and 2022, respectively. The increase in cash flows used in investing activities between periods was primarily due to (i) gathering systems and facilities asset acquisitions of $217 million during the year ended December 31, 2022, (ii) an increase in capital spending for expansion of our gathering systems of $41 million and (iii) an increase in capital spending for expansion of our water handling systems of $25 million, partially offset by a $17 million return of capital distribution from the Joint Venture for a processing plant held in inventory that was sold by the Joint Venture during 2022 and an increase in asset sale proceeds of $4 million between periods.

Financing Activities. Net cash used in financing activities was $477 million and $206 million for the years ended December 31, 2021 and 2022, respectively. The decrease in net cash used in financing activities between periods is primarily related to lower debt repurchases, higher net borrowings on our Credit Facility and lower total dividends paid to our common stockholders and preferred stockholders, partially offset by lower debt issuances. Net cash used in financing activities for the year ended December 31, 2021 included: (i) issuance of the 2029 Notes of $750 million; (ii) repayment of the 2024 Notes of $667 million, which includes the redemption premium at 102.688% of par, (iii) total dividends to our common stockholders and preferred stockholders of $472 million; (iv) $66 million in net payments on the Credit Facility; and (v) $17 million in deferred financing costs payments associated with the issuance of the 2029 Notes and the senior secured revolving credit facility amendment. Net cash used in financing activities for the year ended December 31, 2022 included net borrowings of $235 million on our Credit Facility and total dividends to our common stockholders and preferred stockholders of $433 million

Year Ended December 31, 2020 Compared to Year Ended December 31, 2021

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, 2021 for a discussion of the cash flows for the year ended December 31, 2020 compared to the year ended December 31, 2021.

Capital Investments

Our capital expenditures for the year ended December 31, 2022 were $265 million, including $209 million for gathering and compression infrastructure and $73 million for water infrastructure, partially offset by a $17 million return of capital distribution from the Joint Venture for a processing plant held in inventory that was sold by the Joint Venture during year ended December 31, 2022.

Our 2023 capital budget is $195 million to $215 million, which includes growth capital supporting the increased volumes expected from Antero Resources’ drilling partnership in addition to its maintenance capital program for 2023. Our capital budgets may be adjusted as business conditions warrant. If natural gas, NGLs and oil prices decline to levels below acceptable levels or costs increase to levels above acceptable levels, Antero Resources could choose to defer a significant portion of its budgeted capital expenditures until later periods. As a result, we may also defer a significant portion of our budgeted capital expenditures to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected

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returns and potential to generate consistent cash flows. We routinely monitor and adjust our capital expenditures in response to changes in Antero Resources’ development plans, changes in prices, availability of financing, acquisition costs, industry conditions, the timing of regulatory approvals, success or lack of success in Antero Resources’ drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Debt Agreements

Credit Facility

Antero Midstream Partners, as borrower (the “Borrower”), an indirect, wholly owned subsidiary of Antero Midstream Corporation, has a senior secured revolving credit facility with a consortium of banks. On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility, the Credit Facility. The Credit Facility provides for borrowing under either Adjusted Term Secured Overnight Financing Rate (“SOFR”) or the Base Rate (as each term is defined in the Credit Facility).

The Credit Facility has lender commitments of $1.25 billion and matures on October 26, 2026; provided that if on November 17, 2025 any of the 7.875% senior notes due May 15, 2026 (the “2026 Notes”) are outstanding, the Credit Facility will mature on such date. As of December 31, 2022, we had $782 million of borrowings and no letters of credit outstanding under the Credit Facility.

We have a choice of borrowing at Adjusted Term SOFR or at the base rate. Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable (i) with respect to base rate loans, quarterly and (ii) with respect to SOFR Loans, the last day of each Interest Period (as defined below); provided that if any Interest Period for a SOFR Loan exceeds three months, interest will be payable on the respective dates that fall every three months after the beginning of such Interest Period. SORF Loans bear interest at a rate per annum equal to the rate for SOFR rate loans for three or six months (the “Interest Period”) plus an applicable margin ranging from 150 to 250 basis points (subject to certain exceptions), depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month SOFR Rate loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points (subject to certain exceptions) depending on the leverage ratio then in effect.

The Credit Facility is guaranteed by our subsidiaries and is secured by mortgages on substantially all of Antero Midstream Partners’ and its subsidiaries’ properties. The Credit Facility contains restrictive covenants that may limit our ability to, among other things:

●

incur additional indebtedness;

●

sell assets;

●

make loans to others;

●

make investments and acquisitions;

●

enter into mergers;

●

make certain restricted payments;

●

incur liens; and

●

engage in certain other transactions without the prior consent of the lenders.

The Credit Facility also requires us to maintain the following financial ratios (subject to certain exceptions):

●

a consolidated interest coverage ratio, which is the ratio of our consolidated EBITDA to its consolidated current interest charges of at least 2.5 to 1.0 at the end of each fiscal quarter;

●

a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 5.00 to 1.00 at the end of each fiscal quarter; provided that, at our election (the “Financial Covenant Election”), the consolidated total leverage ratio shall be no more than 5.25 to 1.0; and

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●

after a Financial Covenant Election, a consolidated senior secured leverage ratio covenant rather than the consolidated total leverage ratio covenant, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.75 to 1.0.

We were in compliance with the applicable covenants and ratios as of December 31, 2022.

See Note 8—Long-Term Debt to the consolidated financial statements for more information on our Credit Facility.

Senior Notes

The following table summarizes the material terms of our senior unsecured notes as of December 31, 2022:


	2026 Notes			2027 Notes			2028 Notes			2029 Notes
Outstanding principal (in thousands)	$	550,000		$	650,000		$	650,000		$	750,000
Interest rate		7.875	%		5.75	%		5.75	%		5.375	%
Maturity date		May 15, 2026			March 1, 2027			January 15, 2028			June 15, 2029
Interest payment dates		May 15, Nov. 15			Mar. 1, Sept. 1			Jan. 15, July 15			Jun. 15, Dec. 15
Make-whole redemption date ⁽¹⁾		May 15, 2025			March 1, 2025			January 15, 2026			June 15, 2026

(1)

On or after these dates, we may redeem the applicable series of senior notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. Prior to such date, we may, in certain circumstances, redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.

See Note 8—Long-Term Debt to the consolidated financial statements for more information.

Non-GAAP Financial Measures

We use Adjusted EBITDA as an important indicator of our performance. We define Adjusted EBITDA as net income before net interest expense, income tax expense, depreciation, impairments, accretion of asset retirement obligations, equity-based compensation, excluding equity in earnings of unconsolidated affiliates, amortization of customer relationships, loss on early extinguishment of debt, loss on settlement of asset retirement obligations, loss (gain) on asset sale and including distributions from unconsolidated affiliates.

We use Adjusted EBITDA to assess:

●

the financial performance of our assets, without regard to financing methods, capital structure or historical cost basis;

●

our operating performance and return on capital as compared to other publicly traded companies in the midstream energy sector, without regard to financing or capital structure; and

●

the viability of acquisitions and other capital expenditure projects.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income. Adjusted EBITDA presentations are not made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect net income. You should not consider Adjusted EBITDA in isolation or as a substitute for analyses of results as reported under GAAP. Our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other corporations.

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The following table represents a reconciliation of our Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods presented:


	Year Ended December 31,
(in thousands)	2021		2022
Net income	$	331,617		326,242
Interest expense, net		175,281		189,948
Income tax expense		117,123		117,494
Depreciation expense		108,790		131,762
Amortization of customer relationships		70,672		70,672
Equity-based compensation		13,529		19,654
Impairment of property and equipment		5,042		3,702
Accretion of asset retirement obligations		460		222
Equity in earnings of unconsolidated affiliates		(90,451)		(94,218)
Distributions from unconsolidated affiliates		118,990		120,460
Loss on early extinguishment of debt		21,757		—
Loss on settlement of asset retirement obligations		—		539
Loss (gain) on asset sale		3,628		(2,251)
Adjusted EBITDA	$	876,438		884,226

Critical Accounting Policies and 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. 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. Certain accounting policies involve judgments and uncertainties to such an extent that 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 carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2—Summary of Significant Accounting Policies to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Fair Value Measurement

The FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and sets forth disclosure requirements 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 we estimate 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. Our 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.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. We test goodwill for impairment annually in the fourth quarter and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. The fair value is 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. If the fair value of the reporting unit is less than the carrying value, including goodwill, the excess of the book value over the fair value of goodwill is charged to net income as an impairment expense.

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We utilized a combination of approaches to estimate the fair value of our assets including the discounted cash flow approach, comparable company method and the cost approach, whereby certain property and equipment was adjusted for recent purchases of similar items, economic and functional obsolescence, location, normal useful lives and capacity (if applicable). We performed our first quarter of 2020 quantitative analysis using a weighted-average cost of capital of 18.0%, which was based on significant inputs not observable in the market, and thus represents a Level 3 measurement within the fair value hierarchy.

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.

We utilized a discounted cash flow approach to estimate the fair value of our assets. We performed our first quarter of 2020 quantitative analysis using a weighted-average cost of capital of 19.0%, which was based on significant inputs not observable in the market, and thus represents a Level 3 measurement within the fair value hierarchy.

Contingent Acquisition Consideration

In connection with our September 2015 acquisition of certain water handling assets, we agreed to pay Antero Resources (a) $125 million in cash if we delivered 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if we delivered 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. This contingent consideration liability was valued based on Level 3 inputs related to the expected average volumes and weighted average cost of capital and was recorded at the time of such acquisition in accordance with accounting guidance for business combinations. In January 2020, Antero Midstream Partners paid Antero Resources $125 million and, as of December 31, 2020, no additional contingent acquisition consideration was earned.

General and Administrative and Equity-Based Compensation Costs

General and administrative costs are charged or allocated to us based on the nature of the expenses and are allocated based on our proportionate share of Antero Resources’ gross property and equipment, capital expenditures and labor costs, as applicable. These allocations are based on estimates and assumptions that management believes are reasonable.

Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Estimating the fair value of each award requires management to apply judgment.

Equity-based compensation expenses that are subject to allocation as described in “—Principal Components of our Cost Structure,” are allocated to us based on our proportionate share of Antero Resources’ labor costs. These allocations are based on estimates and assumptions that management believes are reasonable.

New Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies to our consolidated financial statements for information on new accounting pronouncements.

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, 2022, we had $782 million of borrowings and no letters of credit outstanding under the Credit Facility. A 1.0% increase in the Credit Facility interest rate would have resulted in an estimated $6 million increase in interest expense for the year ended December 31, 2022.

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, 2022 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, 2022 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, 2022.

The effectiveness of our internal control over financial reporting as of December 31, 2022 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

Amended and Restated Bylaws

On February 14, 2023, the Board approved an amendment and restatement of the Company’s bylaws (as amended and restated, the “A&R Bylaws”), effective as of such date. Among other matters, the A&R Bylaws:

●

revise procedures and disclosure requirements for the nomination of directors to address new Rule 14a-19 of the Exchange Act; and

●

make other minor administrative, modernizing, clarifying and conforming changes, including adding certain clarifying language to better conform the A&R Bylaws to the DGCL.

The foregoing summary of the amendments to the Company’s bylaws does not purport to be complete and is qualified in its entirety by reference to the complete text of the A&R Bylaws, a copy of which is filed as Exhibit 3.3 to this Annual Report on Form 10-K and is incorporated herein by reference.

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Item 9C. disclosure regarding foreign jurisdictions that prevent inspections

Not applicable.

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 2023 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.

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.


Exhibit Number	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*	Amended and Restated Bylaws of Antero Midstream Corporation, dated February 14, 2023.
3.4	Certificate of Designations of Antero Midstream Corporation, dated March 12, 2019 (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 12, 2019).
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).
4.2	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).
4.3	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).
4.4	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).
4.5	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).
4.6	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).
4.7	Indenture, dated as of November 10, 2020, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee

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	(incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on November 10, 2020)
4.8	Form of 7.875% Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on November 10, 2020).
4.9	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended (incorporated by reference to Exhibit 4.11 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
4.10	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).
4.11	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).
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).
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

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	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†	Antero Midstream Corporation Long Term Incentive Plan, effective as of March 12, 2019 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K/A (Commission File No. 001-38075) filed on March 12, 2019).
10.14†	Letter to Phantom Unitholders under the Antero Midstream Partners LP Long-Term Incentive Plan Regarding the Phantom Unit Exchange (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on May 1, 2019).
10.15†	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 31, 2019).
10.16†	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).
10.17†	Form of Phantom Unit Agreement under the Antero Midstream Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to Antero Midstream Partners LP’s Registration Statement on Form S-8 (Commission File No. 333-200111) filed on November 12, 2014).
10.18†	Global Grant Amendment to Grant Notices and Award Agreements Under the Antero Midstream Partners LP Long-Term Incentive Plan, effective as of October 24, 2016 (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Quarterly Report on Form 10-Q (Commission File No. 001-36719) filed on October 26, 2016).
10.19†	Form of Retention Award Grant Notice and Retention Award 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 April 29, 2020).
10.20†	Form of Retention Award Grant Notice and Retention Award Agreement under the Antero Midstream Corporation Long Term Incentive Plan (Employees) (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 28, 2020).
10.21†	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).
10.22	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).
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).

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101*

The following financial information from this Form 10-K of Antero Midstream Corporation for the year ended December 31, 2022, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income (Loss), (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 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 E. KRUEGER
	Brendan E. Krueger
	Chief Financial Officer, Vice President – Finance and Treasurer

Date:	February 15, 2023

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 15, 2023
Paul M. Rady	(principal executive officer)

	Chief Financial Officer,
/s/ BRENDAN E. KRUEGER	Vice President – Finance and Treasurer	February 15, 2023
Brendan E. Krueger	(principal financial officer)

	Senior Vice President – Accounting and
/s/ SHERI L. PEARCE	Chief Accounting Officer	February 15, 2023
Sheri L. Pearce	(principal accounting officer)

/s/ MICHAEL N. KENNEDY	Director and Senior Vice President – Finance	February 15, 2023
Michael N. Kennedy

/s/ NANCY E. CHISHOLM	Director	February 15, 2023
Nancy E. Chisholm

/s/ PETER A. DEA	Director	February 15, 2023
Peter A. Dea

/s/ W. HOWARD KEENAN, JR.	Director	February 15, 2023
W. Howard Keenan, Jr.

/s/ DAVID H. KEYTE	Director	February 15, 2023
David H. Keyte

/s/ BROOKS J. KLIMLEY	Director	February 15, 2023
Brooks J. Klimley

/s/ JANINE J. MCARDLE	Director	February 15, 2023
Janine J. McArdle

/s/ JOHN C. MOLLENKOPF	Director	February 15, 2023
John C. Mollenkopf

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Audited Consolidated Financial Statements as of December 31, 2021 and 2022 and for the Years Ended December 31, 2020, 2021 and 2022
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-4
Consolidated Statements of Operations and Comprehensive Income (Loss)	F-5
Consolidated Statements of Stockholders’ Equity	F-6
Consolidated Statements of Cash Flows	F-7
Notes to Consolidated Financial Statements	F-8

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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, 2021 and 2022, the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2022, 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, 2022, 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, 2021 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022, 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, 2022 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.

Lease classification for ongoing modifications to the gathering and compression assets

As discussed in Note 5 to the consolidated financial statements, the Company determined that the gathering and compression agreements with Antero Resources Corporation are operating leases. The Company continues to expand its gathering and compression system to serve its customer and, as a result, the minimum volume commitments and the lease payments increase for the expanded system. The increases in volume commitments and lease payments are modifications of the agreements that require evaluation of the lease classification.

We identified the evaluation of lease classification for ongoing modifications to the gathering and compression assets as a critical audit matter. The evaluation of lease classification for these modified leases, including evaluating the economic life as a key estimate, required significant judgment.

The primary procedures we performed to address this critical audit matter included the following. We evaluated the design and tested the operating effectiveness of the internal control over the Company’s process for identifying lease modifications and evaluating lease classification for those modifications, including the review and approval of the Company’s lease modifications and the Company’s evaluation of the lease classification. We evaluated the Company’s accounting memoranda and documentation underlying the accounting conclusions reached, including application of relevant accounting guidance in regard to the modification accounting and subsequent lease classification. We evaluated the economic life used in the determination of lease classification by comparing it to relevant industry publications. We evaluated fixed assets that are placed in service for new minimum volume commitments which would require reassessment of the lease.

/s/ KPMG LLP

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

Denver, Colorado

February 15, 2023

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ANTERO MIDSTREAM CORPORATION

Consolidated Balance Sheets

(In thousands, except per share amounts)


	December 31,
	2021		2022
Assets
Current assets:
Accounts receivable–Antero Resources	$	81,197		86,152
Accounts receivable–third party		747		575
Income tax receivable		940		940
Other current assets		920		1,326
Total current assets		83,804		88,993

Property and equipment, net		3,394,746		3,751,431
Investments in unconsolidated affiliates		696,009		652,767
Customer relationships		1,356,775		1,286,103
Other assets, net		12,667		12,026
Total assets	$	5,544,001		5,791,320

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable–Antero Resources	$	4,956		5,436
Accounts payable–third party		23,592		22,865
Accrued liabilities		80,838		72,715
Other current liabilities		4,623		1,061
Total current liabilities		114,009		102,077
Long-term liabilities:
Long-term debt		3,122,910		3,361,282
Deferred income tax liability		13,721		131,215
Other		6,663		4,428
Total liabilities		3,257,303		3,599,002

Stockholders' Equity:
Preferred stock, $0.01 par value: 100,000 authorized as of December 31, 2021 and 2022
Series A non-voting perpetual preferred stock; 12 designated and 10 issued and outstanding as of December 31, 2021 and 2022		—		—
Common stock, $0.01 par value; 2,000,000 authorized; 477,495 and 478,497 issued and outstanding as of December 31, 2021 and 2022, respectively		4,775		4,785
Additional paid-in capital		2,414,398		2,104,740
Retained earnings (accumulated deficit)		(132,475)		82,793
Total stockholders' equity		2,286,698		2,192,318
Total liabilities and stockholders' equity	$	5,544,001		5,791,320

See accompanying notes to consolidated financial statements.

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ANTERO MIDSTREAM CORPORATION

Consolidated Statements of Operations and Comprehensive Income (Loss)

(In thousands, except per share amounts)


	Year Ended December 31,
	2020		2021		2022
Revenue:
Gathering and compression–Antero Resources	$	711,459		749,737		743,265
Water handling–Antero Resources		259,932		218,621		244,770
Water handling–third party		—		516		2,622
Amortization of customer relationships		(70,672)		(70,672)		(70,672)
Total revenue		900,719		898,202		919,985
Operating expenses:
Direct operating		165,386		157,120		180,254
General and administrative (including $12,778, $13,529 and $19,654 of equity-based compensation in 2020, 2021 and 2022, respectively)		52,213		63,838		62,125
Facility idling		15,219		3,997		4,166
Depreciation		108,790		108,790		131,762
Impairment of property and equipment		98,179		5,042		3,702
Impairment of goodwill		575,461		—		—
Accretion of asset retirement obligations		180		460		222
Loss on settlement of asset retirement obligations		—		—		539
Loss (gain) on asset sale		2,929		3,628		(2,251)
Total operating expenses		1,018,357		342,875		380,519
Operating income (loss)		(117,638)		555,327		539,466
Other income (expense):
Interest expense, net		(147,007)		(175,281)		(189,948)
Equity in earnings of unconsolidated affiliates		86,430		90,451		94,218
Loss on early extinguishment of debt		—		(21,757)		—
Total other expense		(60,577)		(106,587)		(95,730)
Income (loss) before income taxes		(178,215)		448,740		443,736
Income tax benefit (expense)		55,688		(117,123)		(117,494)
Net income (loss) and comprehensive income (loss)	$	(122,527)		331,617		326,242

Net income (loss) per share–basic	$	(0.26)		0.69		0.68
Net income (loss) per share–diluted	$	(0.26)		0.69		0.68

Weighted average common shares outstanding:
Basic		478,278		477,270		478,232
Diluted		478,278		479,736		480,300

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		Total
	Stock		Shares		Amount		Capital		Deficit)		Equity
Balance at December 31, 2019	$	—		484,042	$	4,840		3,480,139		(341,565)		3,143,414
Dividends to stockholders		—		—		—		(590,190)		—		(590,190)
Equity-based compensation		—		—		—		12,778		—		12,778
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes		—		507		5		(481)		—		(476)
Repurchases and retirement of common stock		—		(7,910)		(79)		(24,634)		—		(24,713)
Net loss and comprehensive loss		—		—		—		—		(122,527)		(122,527)
Balance at December 31, 2020		—		476,639		4,766		2,877,612		(464,092)		2,418,286
Dividends to stockholders		—		—		—		(471,721)		—		(471,721)
Equity-based compensation		—		—		—		13,529		—		13,529
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes		—		856		9		(5,022)		—		(5,013)
Net income and comprehensive income		—		—		—		—		331,617		331,617
Balance at December 31, 2021		—		477,495		4,775		2,414,398		(132,475)		2,286,698
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

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,
	2020		2021		2022
Cash flows provided by (used in) operating activities:
Net income (loss)	$	(122,527)		331,617		326,242
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		108,790		108,790		131,762
Accretion of asset retirement obligations		180		460		222
Payment of contingent consideration in excess of acquisition date fair value		(8,076)		—		—
Impairment		673,640		5,042		3,702
Deferred income tax expense (benefit)		(171)		117,123		117,494
Equity-based compensation		12,778		13,529		19,654
Equity in earnings of unconsolidated affiliates		(86,430)		(90,451)		(94,218)
Distributions from unconsolidated affiliates		98,858		118,990		120,460
Amortization of customer relationships		70,672		70,672		70,672
Amortization of deferred financing costs		4,503		5,549		5,716
Settlement of asset retirement obligations		(2,183)		(1,385)		(5,454)
Loss on settlement of asset retirement obligations		—		—		539
Loss (gain) on asset sale		2,929		3,628		(2,251)
Loss on early extinguishment of debt		—		21,757		—
Changes in assets and liabilities:
Accounts receivable–Antero Resources		27,306		(7,475)		(3,354)
Accounts receivable–third party		1,434		904		723
Income tax receivable		(17,251)		16,311		—
Other current assets		155		550		(313)
Accounts payable–Antero Resources		716		792		782
Accounts payable–third party		1,201		695		7,973
Accrued liabilities		(13,142)		(7,346)		(747)
Net cash provided by operating activities		753,382		709,752		699,604
Cash flows provided by (used in) investing activities:
Additions to gathering systems and facilities		(157,931)		(186,588)		(227,561)
Additions to water handling systems		(38,793)		(46,237)		(71,363)
Investments in unconsolidated affiliates		(25,267)		(2,070)		—
Return of investment in unconsolidated affiliate		—		—		17,000
Acquisition of gathering systems and facilities		—		—		(216,726)
Cash received in asset sale		822		1,653		5,726
Change in other assets		1,938		—		(98)
Change in other liabilities		—		—		(804)
Net cash used in investing activities		(219,231)		(233,242)		(493,826)
Cash flows provided by (used in) financing activities:
Dividends to stockholders		(589,640)		(471,171)		(432,825)
Dividends to preferred stockholders		(550)		(550)		(550)
Repurchases of common stock		(24,713)		—		—
Issuance of senior notes		550,000		750,000		—
Redemption of senior notes		—		(667,472)		—
Payments of deferred financing costs		(6,283)		(16,603)		(302)
Borrowings (repayments) on bank credit facilities, net		(346,000)		(66,300)		234,800
Payment of contingent acquisition consideration		(116,924)		—		—
Employee tax withholding for settlement of equity compensation awards		(476)		(5,013)		(6,901)
Other		(160)		(41)		—
Net cash used in financing activities		(534,746)		(477,150)		(205,778)
Net decrease in cash and cash equivalents		(595)		(640)		—
Cash and cash equivalents, beginning of period		1,235		640		—
Cash and cash equivalents, end of period	$	640		—		—

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	140,732		179,748		183,079
Cash received during the period for income taxes	$	39,205		16,311		—
Increase (decrease) in accrued capital expenditures and accounts payable for property and equipment	$	(14,472)		26,995		(17,003)

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 gathering and compression assets comprise 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 14—Investments in Unconsolidated Affiliates.

The Company’s corporate headquarters is located in Denver, Colorado.

(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, 2021 and 2022, and the results of the Company’s operations and its cash flows for the years ended December 31, 2020, 2021 and 2022. The Company has no items of other comprehensive income (loss); therefore, net income (loss) is equal to comprehensive income (loss).

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, including equity-based compensation.

Transactions between the Company and Antero Resources have been identified in the consolidated financial statements (see Note 4—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 cash flows. When the Company records its proportionate share of net income, it increases equity income in the statements of operations and comprehensive income (loss) and the

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

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.

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)	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.

(d)	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 assets, goodwill 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.

(e)	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.

(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 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. See Note 6— Property and Equipment for further information on property and equipment impairments.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

During the year ended December 31, 2022, the Company acquired certain Marcellus gas gathering and compression assets and Utica compression assets. These transactions were accounted for as asset acquisitions 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 6— Property and Equipment for further information on asset acquisitions.

(g)	Asset Retirement Obligations

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 are currently ongoing as of December 31, 2022.

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.

(h)	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 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, 2021 and 2022, the Company had not recorded any liabilities for litigation, environmental or other contingencies.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(i)	Equity-Based Compensation

The Company’s consolidated financial statements include equity-based compensation costs related to awards granted by its own plans, as in place before and after March 12, 2019, as well as costs allocated by Antero Resources for grants made prior to March 12, 2019. Costs allocated from Antero Resources are offset to additional paid in capital on the consolidated balance sheet. See Note 4—Transactions with Affiliates for additional information regarding Antero Resources’ allocation of expenses to the Company. For awards granted under its own plan, 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 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 and Cash Awards.

(j)	Income Taxes

The Company recognizes deferred 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 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 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.

In March 2020, the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted. The CARES Act allows corporations with NOL carryforwards incurred in 2018, 2019 and 2020 to carryback such NOL carryforwards to each of the five years preceding the year of the NOL carryforwards, beginning with the earliest year in which there was taxable income, and claim an income tax refund in the applicable carryback years. As a result of this NOL carryforwards carryback provision in the CARES Act, the Company was able to recognize an income tax refund receivable in March 2020 of $55 million, including $11 million in income tax benefit for the current year and $44 million of previously recognized deferred income tax benefit. As of December 31, 2021, the Company had received all of this refund.

(k)	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.

The carrying values on the consolidated balance sheet of the Company’s cash and cash equivalents, accounts receivable—Antero Resources, accounts receivable—third party, other current assets, accounts payable—Antero Resources, accounts payable—third party, accrued liabilities and, other current liabilities approximate fair values due to their short-term maturities. The Company uses certain valuation techniques in performing its annual goodwill impairment test described below and in determining the fair value of property and equipment. See Note 13—Fair Value Measurement.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(l)	Investments in Unconsolidated Affiliates

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 consolidated net income includes the Company’s proportionate share of the net income or loss of such companies. 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 and participation in policy-making decisions of the investee and material intercompany transactions. See Note 14—Investments in Unconsolidated Affiliates.

(m)	Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment annually in the fourth quarter and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. The fair value is 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. If the fair value of the reporting unit is less than the carrying value, including goodwill, the excess of the book value over the fair value of goodwill is charged to net income as an impairment expense. As of March 31, 2020, the Company’s goodwill was fully impaired. See Note 3—Goodwill and Intangibles.

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.

(n)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.

(o)	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 (accumulated deficit). 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.

(p)	Recently Adopted Accounting Standard

In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes. This ASU removes certain exceptions to the general principles in ASC 740, Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods after December 15, 2020. The Company adopted this ASU on January 1, 2021, and it did not have a material impact on the Company’s consolidated financial statements.

(3) Goodwill and Intangibles

(a)

Goodwill

The Company evaluates goodwill for impairment annually during the fourth quarter and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its carrying amount. Significant assumptions used to estimate the reporting units’ fair value include the discount rate as well as estimates of future cash flows, which are impacted primarily by commodity prices and producer customers’ development plans (which impact volumes and

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

capital requirements).

During the first quarter of 2020, the Company performed an interim impairment analysis of the goodwill due to changes in Antero Resources’ drilling plans as a result of the decline in commodity prices. As a result of this evaluation, the Company impaired all remaining goodwill of $575 million associated with its gathering and processing segment.

The changes in the carrying amount of goodwill by reportable segment were as follows:


	Gathering and		Water
(in thousands)	Processing		Handling		Total
Goodwill as of December 31, 2019	$	575,461		—		575,461
Impairment of goodwill		(575,461)		—		(575,461)
Goodwill as of December 31, 2020	$	—		—		—

(b)	Customer Relationships Intangibles

All customer relationships are subject to amortization and will be amortized over a weighted-average period of 19 years, which reflects the remaining economic life of the relationships as of December 31, 2022.

The changes in the carrying amount of customer relationships were as follows (in thousands):


Customer relationships as of December 31, 2019	$	1,498,119
Amortization of customer relationships		(70,672)
Customer relationships as of December 31, 2020		1,427,447
Amortization of customer relationships		(70,672)
Customer relationships as of December 31, 2021		1,356,775
Amortization of customer relationships		(70,672)
Customer relationships as of December 31, 2022	$	1,286,103

Future amortization expense is as follows (in thousands):


Year ending December 31, 2023	$	70,672
Year ending December 31, 2024		70,672
Year ending December 31, 2025		70,672
Year ending December 31, 2026		70,672
Year ending December 31, 2027		70,672
Thereafter		932,743
Total	$	1,286,103

(4) Transactions with Affiliates

(a)

Revenues

Substantially all revenues earned in the years ended December 31, 2020, 2021 and 2022 were earned from Antero Resources, under various agreements for gathering and compression and water handling services. Revenues earned from gathering and compression services consists 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

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

Company. Direct operating expense includes costs charged to the Company of $7 million, $9 million and $14 million during the years ended December 31, 2020, 2021 and 2022, 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, 2020, 2021 and 2022, general and administrative expenses charged to the Company by Antero Resources were $25 million, $32 million and $30 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, 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. The Company reimburses Antero Resources directly for all general and administrative costs charged to it, except costs attributable to noncash equity-based compensation, see Note 10—Equity-Based Compensation and Cash Awards.

(5) Revenue

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 currently earns 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) Marcellus gathering and compression agreements and (iii) the Utica compression agreement. See Note 6—Property and Equipment for additional information. The 2019 gathering and compression agreement has an initial term through 2038, the Marcellus gathering and compression agreements expire between 2023 and 2031, and the Utica compression agreement has two dedicated areas that expire in 2024 and 2030. Upon expiration of each of the Marcellus gathering and compression service agreements and the Utica 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 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 compression agreement.

The 2019 gathering and compression agreement includes a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent Antero Resources achieves certain quarterly volumetric targets during such time. Antero Resources’ throughput on acquired assets is not considered in low pressure gathering volume targets. For years ended December 31, 2020, 2021 and 2022, Antero Resources earned $48 million, $12 million and $48 million, respectively, in fee rebates. 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 either the Company or Antero Resources on or before the 180^th day prior to the anniversary of such effective date.

Under the gathering and compression agreements, the Company receives a low pressure gathering fee, a high pressure gathering fee and a compression fee, as applicable, substantially all of which are subject to annual CPI-based adjustments or a cost of service fee, as applicable, at the Company’s election when such assets are placed in-service. In addition, 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 asset 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 plant or a Joint Venture 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 plant or a Joint Venture plant. Each set of assets in an agreement are 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-

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

elapsed measures.

The gathering and compression agreements 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% rate of return on such new construction over seven years, which election is made individually for each piece of equipment placed in service. In addition, the Marcellus gathering and compression agreements provide for a minimum volume commitment that requires Antero Resources to utilize or pay for 25% of the capacity of new compressor station construction for 10 years. All lease payments under the minimum volume commitments and cost of service fees are considered to be in-substance fixed lease payments under the gathering and compression agreements.

The Company recognizes lease income from its minimum volume commitments and cost of service fees under its gathering and compression agreements on a straight-line basis. Additional variable operating lease income is earned when volumes in excess of the minimum commitments 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 are aggregated such that there is a single minimum volume commitment for the respective service each year for each 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.

Minimum future lease cash flows to be received by the Company under the gathering and compression agreements as of December 31, 2022 are as follows (in thousands):


Year ending December 31, 2023	$	313,838
Year ending December 31, 2024		312,284
Year ending December 31, 2025		293,736
Year ending December 31, 2026		279,921
Year ending December 31, 2027		219,743
Thereafter		359,554
Total	$	1,779,076

(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 either the Company or Antero Resources on or before the 180^th day prior to the anniversary of such effective date. 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 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 the Company’s service 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, which 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.

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. For more information on reportable segments, see Note 16—Reportable Segments.


	Year Ended December 31,
(in thousands)	2020		2021		2022		Reportable Segment
Type of service
Gathering—low pressure	$	353,491		354,941		368,996	Gathering and Processing ⁽¹⁾
Gathering—low pressure fee rebate		(48,000)		(12,000)		(48,000)	Gathering and Processing ⁽¹⁾
Compression		195,147		198,992		210,329	Gathering and Processing ⁽¹⁾
Gathering—high pressure		210,821		207,804		211,940	Gathering and Processing ⁽¹⁾
Fresh water delivery		158,707		137,278		153,546	Water Handling
Other fluid handling		101,225		81,859		93,846	Water Handling
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
Total	$	900,719		898,202		919,985

Type of contract
Per Unit Fixed Fee	$	759,459		761,737		791,265	Gathering and Processing ⁽¹⁾
Gathering—low pressure fee rebate		(48,000)		(12,000)		(48,000)	Gathering and Processing ⁽¹⁾
Per Unit Fixed Fee		158,707		137,278		154,993	Water Handling
Cost plus 3%		90,478		65,007		71,490	Water Handling
Cost of service fee		10,747		16,852		20,909	Water Handling
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
Total	$	900,719		898,202		919,985

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

The Company’s receivables from its contracts with customers and operating leases as of December 31, 2021 and 2022 were $81 million and $86 million, respectively.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(6) Property and Equipment

(a) Summary of Property and Equipment


	Estimated	December 31,
(in thousands)	Useful Lives	2021		2022
Land	n/a	$	23,369		31,668
Gathering systems and facilities	40-50 years ⁽¹⁾		2,817,918		3,281,872
Permanent buried pipelines and equipment	7-20 years		582,481		601,347
Surface pipelines and equipment	1-7 years		54,542		66,726
Heavy trucks and equipment	3-5 years		5,157		5,157
Above ground storage tanks	5-10 years		2,946		2,953
Construction-in-progress	n/a		174,271		158,977
Total property and equipment			3,660,684		4,148,700
Less accumulated depreciation			(265,938)		(397,269)
Property and equipment, net		$	3,394,746		3,751,431

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

(b) Asset Acquisitions

On October 25, 2022, the Company acquired certain Marcellus gas gathering and compression assets from Crestwood for $205 million in cash, before closing adjustments. These assets include 72 miles of dry gas gathering pipelines and nine compressor stations with approximately 700 MMcf/d of compression capacity. The cash consideration for this asset acquisition was allocated to land and gathering systems and facilities, included in Property and equipment in the consolidated balance sheets, for $3 million and $202 million, respectively.

Additionally, on December 21, 2022, the Company acquired certain Utica compression assets from EnLink for $10 million in cash, before closing adjustments. These assets include four compressor stations with approximately 380 MMcf/d of compression capacity. The acquired compression assets are interconnected with the Company’s existing low pressure and high pressure gathering systems and service Antero Resources’ production. The cash consideration for this asset acquisition was allocated to gathering systems and facilities included in Property and equipment in the consolidated balance sheets.

During the first quarter of 2020, the Company evaluated its assets for impairment due to the decline in the industry environment as a result of low commodity prices. As a result of this evaluation, the Company recorded an impairment expense of $89 million, which included an $83 million impairment expense to its permanent buried pipelines and equipment and a $6 million impairment expense to its surface pipelines and equipment. Additionally, during the year ended December 31, 2020, the Company determined that the carrying value of the landfill associated with the Clearwater Facility was no longer recoverable resulting in an impairment charge to property and equipment of $7 million.

(d) Clearwater Facility Idling

On September 18, 2019, the Company commenced a strategic evaluation of the Clearwater Facility at which time, such facility was idled. The Company expects the facility to be idled for the foreseeable future, and as such, the Clearwater Facility was fully impaired at the time of idling. The Company incurred $15 million, $4 million and $4 million in facility idling costs for the care and maintenance of the Clearwater Facility during the years ended December 31, 2020, 2021 and 2022, respectively.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(7) Income Taxes

Income tax expense (benefit) consisted of the following:


	Year Ended December 31,
(in thousands)	2020		2021		2022
Current income tax expense (benefit)	$	(55,517)		—		—
Deferred income tax expense (benefit)		(171)		117,123		117,494
Total income tax expense (benefit)	$	(55,688)		117,123		117,494

Income tax expense differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 21% to income before taxes as a result of the following:


	Year Ended December 31,
(in thousands)	2020		2021		2022
Federal income tax expense (benefit)	$	(37,426)		94,235		93,185
State income tax expense (benefit), net of federal effect		(6,998)		21,375		20,891
Equity-based compensation		516		1,713		1,027
Carryback of NOLs		(11,225)		—		—
Change in valuation allowance		—		—		2,582
Other		(555)		(200)		(191)
Total income tax expense (benefit)	$	(55,688)		117,123		117,494

Deferred income taxes reflect the impact of temporary differences between assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities is as follows:


	December 31,
(in thousands)	2021		2022
Deferred tax assets:
NOL carryforwards	$	92,896		111,615
Equity-based compensation		1,815		2,766
Charitable contributions		2,582		2,582
Total deferred tax asset		97,293		116,963
Valuation allowance		—		(2,582)
Net deferred tax asset		97,293		114,381

Deferred tax liabilities:
Investment in Antero Midstream Partners		111,014		245,596
Total deferred tax liability		111,014		245,596
Net deferred tax liability	$	(13,721)		(131,215)

In assessing the realizability of all of the deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the Company’s temporary differences become deductible. Management considers projected future taxable income and tax planning strategies in making this assessment. Based upon the projections of future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of certain of these deductible differences and has recorded a valuation allowance of $3 million during the year ended December 31, 2022 related to charitable contributions.

The calculation of the Company’s tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. As of December 31, 2021 and 2022, the Company did not have any uncertain tax positions.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

As of December 31, 2022, the Company has U.S. federal and state NOL carryforwards before the effect of income taxes of $415 million and $478 million, respectively, which have no expiration date. Tax years 2019 through 2022 remain open to examination by the U.S. Internal Revenue Service, and tax year 2019 is currently under audit. The Company to date has not been notified of any adjustments to its federal taxable income or associated tax liability for any year under audit. The Company and its subsidiaries file tax returns with various state taxing authorities and those returns remain open to examination for tax years 2018 through 2022.

(8) Long-Term Debt

The Company’s long-term debt is as follows:


	December 31,
(in thousands)	2021		2022
Credit Facility (a)	$	547,200		782,000
7.875% senior notes due 2026 (c)		550,000		550,000
5.75% senior notes due 2027 (d)		650,000		650,000
5.75% senior notes due 2028 (e)		650,000		650,000
5.375% senior notes due 2029 (f)		750,000		750,000
Total principal		3,147,200		3,382,000
Unamortized debt premiums		2,106		1,698
Unamortized debt issuance costs		(26,396)		(22,416)
Total long-term debt	$	3,122,910		3,361,282

(a)	Credit Facility

Antero Midstream Partners, an indirect, wholly owned subsidiary of Antero Midstream Corporation, as borrower (the “Borrower”), has a senior secured revolving credit facility with a consortium of banks. On October 26, 2021, the Company entered into an amended and restated senior secured revolving credit facility, the Credit Facility. As of December 31, 2022, the Credit Facility had lender commitments of $1.25 billion and matures on October 26, 2026; provided that if on November 17, 2025 any of the 2026 Notes (as defined below) are outstanding, the Credit Facility will mature on such date. As of December 31, 2022, the Credit Facility had an available borrowing capacity of $468 million.

The Credit Facility contains certain covenants including restrictions on indebtedness, and requirements with respect to leverage and interest coverage ratios. The Credit Facility permits distributions to the holders of the Borrower’s equity interests in accordance with the cash distribution policy, provided that no event of default exists or would be caused thereby, and only to the extent permitted by the Borrower’s organizational documents. The Borrower was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2021 and 2022.

The Credit Facility in effect prior to October 26, 2021 provided for borrowing under either the Base Rate or the Eurodollar Rate (as each term is defined in the Credit Facility), and the Credit Facility in effect on and after October 26, 2021 provides for borrowing under either Adjusted Term SOFR or the Base Rate (as each term is defined in the Credit Facility). Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable with respect to (i) base rate loans, quarterly and (ii) SOFR Loans at the end of the applicable interest period if three months (or shorter, if applicable), or every three months if the applicable interest period is longer than three months. Interest was payable at a variable rate based on LIBOR or the base rate, determined by election at the time of borrowing, plus an applicable margin rate under the Credit Facility agreement in effect prior to October 26, 2021. Interest is payable at a variable rate based on SOFR or the base rate, determined by election at the time of borrowing, plus an applicable margin rate under the Credit Facility in effect on and after October 26, 2021. Interest at the time of borrowing is determined with reference to the Borrower’s then-current leverage ratio subject to certain exceptions. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.25% to 0.375% subject to certain exceptions based on the leverage ratio then in effect.

As of December 31, 2021, the Borrower had outstanding borrowings under the Credit Facility of $547 million with a weighted average interest rate of 1.81%. As of December 31, 2022, the Borrower had outstanding borrowings under the Credit Facility of $782 million with a weighted average interest rate of 6.17%. No letters of credit under the Credit Facility were outstanding as of December 31, 2021 and 2022.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(b)	5.375% Senior Notes Due 2024

On September 13, 2016, Antero Midstream Partners and its wholly owned subsidiary Finance Corp (the “Issuers”), issued $650 million in aggregate principal amount of 5.375% senior notes due September 15, 2024 (the “2024 Notes”) at par. The 2024 Notes were recorded at their fair value of $652.6 million as of March 12, 2019, and the related premium of $2.6 million was amortized into interest expense over the life of the 2024 Notes. The Issuers redeemed all $650 million of the 2024 Notes at 102.688% of par on June 8, 2021, and recognized a loss of $21 million on the early extinguishment of debt during the year ended December 31, 2021, which included the write-off of all unamortized debt premium and issuance costs. Interest on the 2024 Notes was payable on March 15 and September 15 of each year.

(c)	7.875% Senior Notes Due 2026

On November 10, 2020, the Issuers issued $550 million in aggregate principal amount of 7.875% senior notes due May 15, 2026 (the “2026 Notes”) at par. The 2026 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2026 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners’ wholly owned subsidiaries (other than Finance Corp) and certain of its future restricted subsidiaries. Interest on the 2026 Notes is payable on May 15 and November 15 of each year. Antero Midstream Partners may redeem all or part of the 2026 Notes at any time on or after May 15, 2023 at redemption prices ranging from 103.938% on or after May 15, 2023 to 100.00% on or after May 15, 2025. In addition, prior to May 15, 2023, Antero Midstream Partners may redeem up to 35% of the aggregate principal amount of the 2026 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.875% of the principal amount of the 2026 Notes, plus accrued and unpaid interest. At any time prior to May 15, 2023, Antero Midstream Partners may also redeem the 2026 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2026 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream Partners undergoes a change of control followed by a rating decline, the holders of the 2026 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the 2026 Notes at a price equal to 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest.

(d)	5.75% Senior Notes Due 2027

On February 25, 2019, the Issuers issued $650 million in aggregate principal amount of 5.75% senior notes due March 1, 2027 (the “2027 Notes”) at par. The 2027 Notes were recorded at their fair value of $653.3 million as of March 12, 2019, and the related premium of $3.3 million will be amortized into interest expense over the life of the 2027 Notes. The 2027 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2027 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners’ wholly owned subsidiaries (other than Finance Corp) and certain of its future restricted subsidiaries. Interest on the 2027 Notes is payable on March 1 and September 1 of each year. Antero Midstream Partners may redeem all or part of the 2027 Notes at any time on or after March 1, 2022 at redemption prices ranging from 102.875% currently to 100% on or after March 1, 2025. If Antero Midstream Partners undergoes a change of control followed by a rating decline, the holders of the 2027 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the 2027 Notes at a price equal to 101% of the principal amount of the 2027 Notes, plus accrued and unpaid interest.

(e)5.75% Senior Notes Due 2028

On June 28, 2019, the Issuers issued $650 million in aggregate principal amount of 5.75% senior notes due January 15, 2028 (the “2028 Notes”) at par. The 2028 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2028 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners’ wholly owned subsidiaries (other than Finance Corp) and certain of its future restricted subsidiaries. Interest on the 2028 Notes is payable on January 15 and July 15 of each year. Antero Midstream Partners may redeem all or part of the 2028 Notes at any time on or after January 15, 2023 at redemption prices ranging from 102.875% on or after January 15, 2023 to 100.00% on or after January 15, 2026. In addition, prior to January 15, 2023, Antero Midstream Partners may redeem up to 35% of the aggregate principal amount of the 2028 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.75% of the principal amount of the 2028 Notes, plus accrued and unpaid interest. At any time prior to January 15, 2023, Antero Midstream Partners may also redeem the 2028 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2028 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream Partners undergoes a change of control followed by a rating decline, the holders of the 2028 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

2028 Notes at a price equal to 101% of the principal amount of the 2028 Notes, plus accrued and unpaid interest.

(f)	5.375% Senior Notes Due 2029

On June 8, 2021, the Issuers issued $750 million in aggregate principal amount of 5.375% senior notes due June 15, 2029 (the “2029 Notes”) at par. The 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2029 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners’ wholly owned subsidiaries (other than Finance Corp) and certain of its future restricted subsidiaries. Interest on the 2029 Notes is payable on June 15 and December 15 of each year. Antero Midstream Partners may redeem all or part of the 2029 Notes at any time on or after June 15, 2024 at redemption prices ranging from 102.688% on or after June 15, 2024 to 100.00% on or after June 15, 2026. In addition, prior to June 15, 2024, Antero Midstream Partners may redeem up to 35% of the aggregate principal amount of the 2029 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2029 Notes, plus accrued and unpaid interest. At any time prior to June 15, 2024, Antero Midstream Partners may also redeem the 2029 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2029 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream Partners undergoes a change of control followed by a rating decline, the holders of the 2029 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the 2029 Notes at a price equal to 101% of the principal amount of the 2029 Notes, plus accrued and unpaid interest.

(g)	Senior Notes Guarantors

The Company and each of the Company’s wholly owned subsidiaries (except for the Issuers) has fully and unconditionally guaranteed the 2026 Notes, 2027 Notes, 2028 Notes and 2029 Notes (collectively the “Senior Notes”). In the event a guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a Restricted Subsidiary (as defined in the applicable indenture governing the series of Senior Notes) of the Issuer or the sale of all or substantially all of its assets) and whether or not the guarantor is the surviving entity in such transaction to a person that is not an Issuer or a Restricted Subsidiary of an Issuer, such guarantor will be released from its obligations under its guarantee if the sale or other disposition does not violate the covenants set forth in the indentures governing the applicable Senior Notes.

In addition, a guarantor will be released from its obligations under the applicable indenture and its guarantee, upon the release or discharge of the guarantee of other indebtedness under a credit facility that resulted in the creation of such guarantee, except a release or discharge by or as a result of payment under such guarantee; if the Issuers designate such subsidiary as an unrestricted subsidiary and such designation complies with the other applicable provisions of the indenture governing the applicable Senior Notes or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the applicable Senior Notes.

During the years ended December 31, 2020, 2021 and 2022, all of the Company’s assets and operations are attributable to the Issuers and its guarantors.

(9) Accrued Liabilities

Accrued liabilities consisted of the following items:


	December 31,
(in thousands)	2021		2022
Capital expenditures	$	24,900		16,597
Operating expenses		10,417		11,118
Interest expense		36,794		37,947
Ad valorem taxes		5,400		5,661
Other		3,327		1,392
Total accrued liabilities	$	80,838		72,715

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(10) Equity-Based Compensation and Cash Awards

(a)	Summary of Equity-Based Compensation

The Company’s equity-based compensation includes (i) costs allocated to Antero Midstream by Antero Resources for grants made prior to March 12, 2019 pursuant to the Antero Resources Corporation Long-Term Incentive Plan (the “AR LTIP”) and (ii) costs related to the Antero Midstream Corporation Long-Term Incentive Plan (the “AM LTIP”). Antero Midstream’s equity-based compensation expense is included in general and administrative expenses, and recorded as a credit to the applicable classes of equity.

AR LTIP

Equity-based compensation expense allocated to Antero Midstream from Antero Resources was $5.2 million, $2.1 million and $0.4 million for the years ended December 31, 2020, 2021 and 2022, respectively, which includes expense related to the Converted AM RSU Awards (as defined below). For grants made prior to March 12, 2019, Antero Resources has total unamortized expense related to its various equity-based compensation plans that can be allocated to the Company of less than $0.1 million as of December 31, 2022, which includes the Converted AM RSU Awards (as defined below). The unamortized expense attributable to grants made prior to March 12, 2019 will be recorded during the first quarter of 2023. A portion of this unamortized cost will be allocated to Antero Midstream as it is amortized over the remaining service period of the related awards. The Company does not reimburse Antero Resources for noncash equity compensation allocated to it for awards issued under the AR LTIP.

AM LTIP

Effective March 12, 2019, the Board of Directors of Antero Midstream Corporation (the “Board”) adopted the AM LTIP under which awards may be granted to employees, directors, and other service providers of the Company and its affiliates. The Company is authorized to grant up to 15,398,901 shares of AM common stock under the AM LTIP. The AM LTIP provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units (“RSUs”), dividend equivalents, other stock-based awards, cash awards and substitute awards. The terms and conditions of the awards granted are established by the compensation committee of the Board. As of December 31, 2022, a total of 7,420,368 shares were available for future grant under the AM LTIP.

The Company’s equity-based compensation expense, by type of award, is as follows:



	Year Ended December 31,
(in thousands)	2020		2021		2022
Restricted stock units ⁽¹⁾	$	9,964		11,461		16,039
Performance share units ⁽¹⁾		1,912		1,158		2,770
Equity awards issued to directors		902		910		845
Total expense	$	12,778		13,529		19,654

(1)	Amounts include equity-based compensation expense allocated to the Company by Antero Resources.

The total fair value of the Company’s vested equity awards for the years ended December 31, 2020, 2021 and 2022 were $2 million, $12 million and $18 million, respectively.

(b)	Restricted Stock Unit Awards

RSU awards vest subject to the satisfaction of service requirements. Expense related to each RSU award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. The weighted average grant date fair value per share for RSUs granted during the years ended December 31, 2020, 2021 and 2022 were $6.32, $8.71 and $11.28, respectively.

The Company’s RSU awards include the unvested outstanding phantom units granted under the Antero Midstream Partners Long Term Incentive Plan that was assumed by the Company on March 12, 2019, and converted into 1.8926 RSUs under the AM LTIP representing a right to receive shares of the Company’s common stock for each converted phantom unit (all such RSUs, the “Converted AM RSU Awards”). The Converted AM RSU Awards are accounted for as if they are distributed by Antero Midstream

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

Partners to Antero Resources. Therefore, the expense related to the Converted AM RSU Awards is subject to allocation by Antero Resources.

A summary of the RSU awards activity, which includes the Converted AM RSU Awards, is as follows:


		Weighted Average
	Number	Grant Date
	of Units	Fair Value
Total AM LTIP RSUs awarded and unvested—December 31, 2021	3,573,377	$	8.11
Granted	2,750,896		11.28
Vested	(1,269,848)		8.35
Forfeited	(177,167)		9.43
Total AM LTIP RSUs awarded and unvested—December 31, 2022	4,877,258	$	9.79

As of December 31, 2022, unamortized expense of $34 million related to the unvested RSUs is expected to be recognized over a weighted average period of approximately 2.2 years.

(c)	Performance Share Unit Awards

2019 Performance Share Unit Awards

In 2019, the Company granted performance share units (“PSUs”) to certain of its employees and executive officers that vest based on the Company’s actual return on invested capital (“ROIC”) (as defined in the award agreement) over a three-year period as compared to a targeted ROIC (“2019 ROIC PSUs”). The number of shares of the Company’s common stock that could be earned with respect to the 2019 ROIC PSUs ranged from zero to 200% of the target number of the 2019 ROIC PSUs originally granted. The grant date fair value of these awards was based on the closing price of the Company’s common stock on the date of the grant, assuming target achievement of the performance condition. Expense related to the 2019 ROIC PSUs was recognized based on the number of shares of the Company’s common stock that are expected to be issued at the end of the measurement period. During the year ended December 31, 2022, the performance condition for the 2019 ROIC PSU’s was met at 200% of target and 137,712 target 2019 ROIC PSU’s converted into 275,424 shares of the Company’s common stock. As of December 31, 2022, there were no 2019 ROIC PSU’s outstanding.

2022 Performance Share Unit Awards

In April 2022, the Company granted PSUs to certain of its executive officers that vest based on the Company’s actual ROIC (as defined in the aware agreement) over a three-year period concluding on December 31, 2024 as compared to a targeted ROIC (“2022 ROIC PSUs”). The number of shares of the Company’s common stock that can be earned with respect to the 2022 ROIC PSUs ranges from zero to 200% of the target number of 2022 ROIC PSUs originally granted. The grant date fair value of these awards was based on the closing price of the Company’s common stock on the date of the grant, assuming target achievement of the performance condition. Expense related to the 2022 ROIC PSUs is recognized based on the number of shares of the Company’s common stock that are expected to be issued at the end of the measurement period, and such expense is reversed if the likelihood of achieving the performance condition decreases. The likelihood of achieving the performance conditions related to 2022 ROIC PSU awards was probable as of December 31, 2022.

A summary of the PSU awards activity is as follows:


		Weighted Average
	Number	Grant Date
	of Units	Fair Value
Total AM LTIP PSUs awarded and unvested—December 31, 2021	116,526	$	6.32
Granted	461,121		11.05
Vested	(137,712)		6.32
Total AM LTIP PSUs awarded and unvested—December 31, 2022	439,935	$	11.28

As of December 31, 2022, there was $8 million of unamortized equity-based compensation expense related to unvested PSUs that is expected to be recognized over a weighted average period of 2.3 years.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(d)	Cash Awards

In January 2020, the Company granted cash awards of $2.2 million to certain executives under the AM LTIP that vest ratably over a period of up to three years. In July 2020, the Company granted additional cash awards of $0.7 million to certain non-executive employees under the AM LTIP that vest ratably over a period of four years. The compensation expense for these awards is recognized ratably over the applicable vesting period. As of December 31, 2021 and 2022, the Company has accrued $1.1 million and $0.5 million, respectively, in other liabilities in the consolidated balance sheet related to unvested cash awards.

(11) Cash Dividends

The Company paid cash dividends for the quarter indicated as follows (in thousands, except per share data):


					Dividends
Period	Record Date	Dividend Date	Dividends		per Share
Q4 2019	January 31, 2020	February 12, 2020	$	148,876	$	0.3075
*	February 14, 2020	February 14, 2020		138		*
Q1 2020	April 30, 2020	May 12, 2020		147,519		0.3075
*	May 15, 2020	May 15, 2020		137		*
Q2 2020	July 30, 2020	August 12, 2020		146,664		0.3075
*	August 14, 2020	August 14, 2020		138		*
Q3 2020	October 29, 2020	November 12, 2020		146,581		0.3075
*	November 16, 2020	November 16, 2020		137		*
	Total 2020		$	590,190

Q4 2020	February 3, 2021	February 11, 2021	$	147,194	$	0.3075
*	February 16, 2021	February 16, 2021		138		*
Q1 2021	April 28, 2021	May 12, 2021		108,799		0.2250
*	May 17, 2021	May 17, 2021		137		*
Q2 2021	July 28, 2021	August 11, 2021		107,719		0.2250
*	August 16, 2021	August 16, 2021		138		*
Q3 2021	October 27, 2021	November 10, 2021		107,459		0.2250
*	November 15, 2021	November 15, 2021		137		*
	Total 2021		$	471,721

Q4 2021	January 26, 2022	February 9, 2022	$	108,149	$	0.2250
*	February 14, 2022	February 14, 2022		138		*
Q1 2022	April 27, 2022	May 11, 2022		109,296		0.2250
*	May 16, 2022	May 16, 2022		137		*
Q2 2022	July 27, 2022	August 10, 2022		107,675		0.2250
*	August 15, 2022	August 15, 2022		138		*
Q3 2022	October 26, 2022	November 9, 2022		107,705		0.2250
*	November 14, 2022	November 14, 2022		137		*
	Total 2022		$	433,375

*	Dividends are paid in accordance with the terms of the Series A Preferred Stock (as defined below) as discussed in Note 12—Equity and Earnings Per Common Share.

On January 11, 2023, the Board announced the declaration of a cash dividend on the shares of AM common stock of $0.2250 per share for the quarter ended December 31, 2022. The dividend was paid on February 8, 2023 to stockholders of record as of January 25, 2023. The Company pays dividends (i) out of surplus or (ii) if there is no surplus, out of the net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year, as provided under Delaware law.

The Board also declared a cash dividend of $138 thousand on the shares of Series A Preferred Stock of Antero Midstream Corporation that was paid on February 14, 2023 in accordance with the terms of the Series A Preferred Stock, which are discussed in Note 12—Equity and Earnings Per Common Share. As of December 31, 2022, there were dividends in the amount of $69 thousand accumulated in arrears on the Company’s Series A Preferred Stock.

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Table of Contents

ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(12) Equity and Earnings Per Common Share

(a)Preferred Stock

The Board authorized 100,000,000 shares of preferred stock on March 12, 2019, and issued 10,000 shares of preferred stock designated as "5.5% Series A Non-Voting Perpetual Preferred Stock" (the "Series A Preferred Stock"), to The Antero Foundation on that date. Dividends on the Series A Preferred Stock are cumulative from the date of original issue and payable in cash on the 45^th day following the end of each fiscal quarter, or such other dates as the Board will approve, at a rate of 5.5% per annum on (i) the liquidation preference per share of Series A Preferred Stock (as described below) and (ii) the amount of accrued and unpaid dividends for any prior dividend period on such share of Series A Preferred Stock, if any. At any time following the date of issue, in the event of a change of control, or at any time on or after March 12, 2029, the Company may redeem the Series A Preferred Stock at a price equal to $1,000 per share, plus any accrued and unpaid dividends, payable in cash; provided that if any shares of the Series A Preferred Stock are held by The Antero Foundation at the time of such redemption, the price for redemption of each share of Series A Preferred Stock will be the greater of (i) $1,000 per share, plus any accrued but unpaid dividends, and (ii) the fair market value of the Series A Preferred Stock. On or after March 12, 2029, the holder of each share of Series A Preferred Stock (other than The Antero Foundation) may convert such shares, at any time and from time to time, at the option of the holder into a number of shares of AM common stock equal to the conversion ratio in effect on the applicable conversion date, subject to certain limitations. The Series A Preferred Stock ranks senior to the AM common stock as to dividend rights, as well as with respect to rights upon liquidation, winding-up or dissolution of the Company. Holders of the Series A Preferred Stock do not have any voting rights in the Company, except as required by law, or any preemptive rights.

(b)Weighted Average Shares Outstanding

The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding:


	Year Ended December 31,
(in thousands)	2020		2021		2022
Basic weighted average number of shares outstanding		478,278		477,270		478,232
Add: Dilutive effect of RSUs		—		1,201		1,050
Add: Dilutive effect of PSUs		—		232		91
Add: Dilutive effect of Series A Preferred Stock		—		1,033		927
Diluted weighted average number of shares outstanding		478,278		479,736		480,300

Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share ^(1):
RSUs		1,812		258		—
PSUs		148		—		—
Series A Preferred Shares		1,297		—		—

(1)	The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common shares, assuming dilution because the inclusion of these awards would have been anti-dilutive.

(c)Earnings Per Common Share

Earnings per common share—basic for each period is computed by dividing the net income or loss attributable to the Company by the basic weighted average number of shares outstanding during the period. Earnings per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is anti-dilutive.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)


		Year Ended December 31,
(in thousands, except per share amounts)	2020		2021		2022
Net income (loss)	$	(122,527)		331,617		326,242
Less preferred stock dividends		(550)		(550)		(550)
Net income (loss) available to common shareholders	$	(123,077)		331,067		325,692

Net income (loss) per share–basic	$	(0.26)		0.69		0.68
Net income (loss) per share–diluted	$	(0.26)		0.69		0.68

Weighted average common shares outstanding–basic		478,278		477,270		478,232
Weighted average common shares outstanding–diluted		478,278		479,736		480,300

(13) Fair Value Measurement

(a)Goodwill

The Company estimated the fair value of its assets in performing its goodwill impairment analysis. The Company utilized a combination of approaches to determine fair value that included a discounted cash flow approach, comparable company method and the market value approach. The Company used a weighted-average cost of capital of 18.0% as of March 31, 2020 which was based on significant inputs not observable in the market, and thus represents a Level 3 measurement within the fair value hierarchy.

(b) Property and Equipment

The Company estimated the undiscounted future cash flow projections to assess its property and equipment for impairment. The carrying values of certain fresh water permanent buried pipelines and equipment and fresh water surface pipelines and equipment were deemed not recoverable. As a result, the carrying values have been reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs and a discount rate typical of third-party market participants of 19.0% as of March 31, 2020, which is a Level 3 fair value measurement within the fair value hierarchy.

In connection with Antero Resources’ contribution of Antero Water and certain water handling assets to Antero Midstream Partners in September 2015 (the “Water Acquisition”), Antero Midstream Partners agreed to pay Antero Resources (a) $125 million in cash if Antero Midstream Partners delivered 176,295,000 barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream Partners delivered 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. This contingent consideration liability was valued based on Level 3 inputs related to expected average volumes and weighted average cost of capital.

In January 2020, Antero Midstream Partners paid Antero Resources $125 million and, as of December 31, 2020, no additional contingent acquisition consideration was earned.

(d) Senior Unsecured Notes

As of December 31, 2021 and 2022 the fair value and carrying value of the Company’s senior unsecured notes were as follows:


	December 31, 2021				December 31, 2022
(in thousands)	Fair Value ⁽¹⁾		Carrying Value ⁽²⁾		Fair Value ⁽¹⁾		Carrying Value ⁽²⁾
2026 Notes	$	604,450		544,294		556,985		545,416
2027 Notes		672,750		645,970		612,365		646,610
2028 Notes		680,225		643,902		601,575		644,776
2029 Notes		783,750		741,544		685,650		742,480
Total	$	2,741,175		2,575,710		2,456,575		2,579,282

(1)	Fair values are based on Level 2 market data inputs.

(2)	Carrying values are presented net of unamortized debt issuance costs and debt premiums.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(e) Other Assets and Liabilities

The carrying values of accounts receivable and accounts payable as of December 31, 2021 and 2022 approximated fair value because of their short-term nature. The carrying value of the amounts under the Credit Facility as of December 31, 2021 and 2022 approximated fair value because the variable interest rates are reflective of current market conditions.

(14) Investments in Unconsolidated Affiliates

(a)Summary of Investments in Unconsolidated Affiliates

The Company has a 50% equity interest in the Joint Venture to develop processing and fractionation assets with MarkWest, a wholly owned subsidiary of MPLX, LP. The Joint Venture was formed to develop processing and fractionation assets in Appalachia. MarkWest operates the Joint Venture assets, which consist of processing plants in West Virginia and a one-third interest in two MarkWest fractionators in Ohio.

The Company also has a 15% equity interest in a gathering system of Stonewall, which operates a 67-mile pipeline on which Antero Resources is an anchor shipper.

The Company’s net income (loss) includes its proportionate share of the net income of the Joint Venture and Stonewall. When the Company records its proportionate share of net income, it increases equity income in the consolidated statements of operations and comprehensive income and the carrying value of that investment on its balance sheet. When distributions on the Company’s proportionate share of net income are received, they are recorded as reductions to the carrying value of the investment on the balance sheet and are classified as cash inflows from operating activities in accordance with the nature of the distribution approach under FASB ASC Topic 230, Statement of Cash Flows. The Company uses the equity method of accounting to account for its investments in Stonewall and the Joint Venture because it exercises significant influence, but not control, over the entities. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as its ownership interest, representation on the applicable Board of Directors and participation in policy-making decisions of Stonewall and the Joint Venture.

The following table is a reconciliation of the Company’s investments in these unconsolidated affiliates:


					Total Investment
			MarkWest		in Unconsolidated
(in thousands)	Stonewall			Joint Venture	Affiliates
Balance as of December 31, 2020	$	137,632		584,846		722,478
Additional investments		—		2,070		2,070
Equity in earnings of unconsolidated affiliates ⁽¹⁾		6,560		83,891		90,451
Distributions from unconsolidated affiliates		(13,620)		(105,370)		(118,990)
Balance as of December 31, 2021		130,572		565,437		696,009
Equity in earnings of unconsolidated affiliates ⁽¹⁾		7,558		86,660		94,218
Distributions from unconsolidated affiliates		(12,015)		(108,445)		(120,460)
Return of investment in unconsolidated affiliate		—		(17,000)		(17,000)
Balance as of December 31, 2022	$	126,115		526,652		652,767

(1)	As adjusted for the amortization of the difference between the cost of the equity investments in Stonewall and the Joint Venture and the amount of the underlying equity in the net assets of Stonewall and the Joint Venture as of March 12, 2019.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

(b)Summarized Financial Information of Unconsolidated Affiliates

The following tables present summarized financial information for the Company’s investments in unconsolidated affiliates:

Combined Balance Sheets


	December 31,
(in thousands)	2021		2022
Current assets	$	74,704		74,852
Noncurrent assets		1,602,093		1,517,349
Total assets	$	1,676,797		1,592,201

Current liabilities	$	8,375		5,453
Noncurrent liabilities		4,827		4,427
Noncontrolling interest		161,842		154,100
Partners' capital		1,501,753		1,428,221
Total liabilities and partners' capital	$	1,676,797		1,592,201

Statements of Combined Operations


	Year Ended December 31,
(in thousands)	2020		2021		2022
Revenues	$	321,880		333,565		357,730
Operating expenses		122,660		130,080		153,383
Income from operations		199,220		203,485		204,347
Net income attributable to unconsolidated affiliates, including noncontrolling interest		230,564		236,444		248,458
Net income attributable to unconsolidated affiliates		238,991		245,256		257,458

(15) Contingencies

The Company is currently involved in a consolidated lawsuit with Veolia Water Technologies, Inc. (“Veolia”) relating to the Clearwater Facility.

Veolia and the Antero Defendants each filed partial motions to dismiss and motions for summary judgment directed at certain claims asserted by the opposing party. A bench trial on the remaining claims was held from January 24 through February 10, 2022 and concluded on February 24, 2022. At trial, Antero Treatment sought damages from Veolia of approximately $450 million, which represents the Company’s out-of-pocket costs associated with the Clearwater Facility project. In the alternative, Antero Treatment sought damages related to multiple breaches of the DBA, totaling approximately $370 million. Also at trial, Veolia sought monetary damages of approximately $118 million, including alleged delay and extra-contractual costs and a contract balance relating to an allegation that Antero Defendants improperly terminated the DBA.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

Court entered judgment in favor of Antero Treatment in the amount of $309,183,975 in damages, which includes pre-judgment interest. Antero was also awarded costs and attorneys’ fees, the amount of which will be determined in separate proceedings. The judgment remains subject to appeal and applicable post-judgment proceedings.

(16) Reportable Segments

The Company’s operations, which are located in the United States, are organized into two reportable segments: (i) gathering and processing and (ii) water handling. These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Management evaluates the performance of the Company’s business segments based on operating income. Interest expense is primarily managed and evaluated on a consolidated basis.

Gathering and Processing

The gathering and processing segment includes a network of gathering pipelines and compressor stations that collect and process production from Antero Resources’ wells in West Virginia and Ohio. The gathering and processing segment also includes equity in earnings from the Company’s investments in the Joint Venture and Stonewall.

Water Handling

The Company’s water handling segment includes two independent systems that deliver water from sources including the Ohio River, local reservoirs and several regional waterways. Portions of these water handling 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 for Antero Resources’ well completions.

The summarized operating results of the Company’s reportable segments are as follows:


	Year Ended December 31, 2020
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated ⁽¹⁾		Total
Revenues:
Revenue–Antero Resources	$	711,459		259,932		—		971,391
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		674,373		226,346		—		900,719
Operating expenses:
Direct operating		56,508		108,878		—		165,386
General and administrative		29,899		14,184		8,130		52,213
Facility idling		—		15,219		—		15,219
Depreciation		57,300		51,490		—		108,790
Impairment of property and equipment		947		97,232		—		98,179
Impairment of goodwill		575,461		—		—		575,461
Accretion of asset retirement obligations		—		180		—		180
Loss on asset sale		2,689		240		—		2,929
Total operating expenses		722,804		287,423		8,130		1,018,357
Operating loss	$	(48,431)		(61,077)		(8,130)		(117,638)

Equity in earnings of unconsolidated affiliates	$	86,430		—		—		86,430
Additions to property and equipment	$	157,931		38,793		—		196,724

(1)	Certain expenses that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)


	Year Ended December 31, 2021
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated ⁽¹⁾		Total
Revenues:
Revenue–Antero Resources	$	749,737		218,621		—		968,358
Revenue–third-party		—		516		—		516
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		712,651		185,551		—		898,202
Operating expenses:
Direct operating		65,983		91,137		—		157,120
General and administrative		36,380		22,817		4,641		63,838
Facility idling		—		3,997		—		3,997
Depreciation		59,692		49,098		—		108,790
Impairment of property and equipment		4,608		434		—		5,042
Accretion of asset retirement obligations		—		460		—		460
Loss on asset sale		3,628		—		—		3,628
Total operating expenses		170,291		167,943		4,641		342,875
Operating income	$	542,360		17,608		(4,641)		555,327

Equity in earnings of unconsolidated affiliates	$	90,451		—		—		90,451
Additions to property and equipment	$	186,588		46,237		—		232,825

(1)	Certain expenses that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis.


	Year Ended December 31, 2022
	Gathering and		Water				Consolidated
(in thousands)	Processing		Handling		Unallocated ⁽¹⁾		Total
Revenues:
Revenue–Antero Resources	$	743,265		244,770		—		988,035
Revenue–third-party		—		2,622		—		2,622
Amortization of customer relationships		(37,086)		(33,586)		—		(70,672)
Total revenues		706,179		213,806		—		919,985
Operating expenses:
Direct operating		75,889		104,365		—		180,254
General and administrative		38,972		17,495		5,658		62,125
Facility idling		—		4,166		—		4,166
Depreciation		81,390		50,372		—		131,762
Impairment of property and equipment		1,130		2,572		—		3,702
Accretion of asset retirement obligations		—		222		—		222
Loss on settlement of asset retirement obligations		—		539		—		539
Gain on asset sale		(2,120)		(131)		—		(2,251)
Total operating expenses		195,261		179,600		5,658		380,519
Operating income	$	510,918		34,206		(5,658)		539,466

Equity in earnings of unconsolidated affiliates	$	94,218		—		—		94,218
Additions to property and equipment, net	$	227,561		71,363		—		298,924

(1)	Certain expenses that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis.

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ANTERO MIDSTREAM CORPORATION

Notes to Consolidated Financial Statements (Continued)

The summarized total assets of the Company’s reportable segments are as follows:


	December 31,
(in thousands)	2021		2022
Gathering and Processing	$	4,450,939		4,711,069
Water Handling		1,092,122		1,079,297
Unallocated ⁽¹⁾		940		954
Total assets	$	5,544,001		5,791,320

(1)	Certain assets that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis.

F-31

Positive
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Uncertain
Constraining
Legalese
Litigous
Readability	H.S. junior Avg

Antero Midstream (AM) 10-K2022 FY Annual report

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