Antero Midstream Corp - Annual Report: 2020 (Form 10-K)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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Commission File No. 001-38075

ANTERO MIDSTREAM CORPORATION

(Exact name of registrant as specified in its charter)

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(303) 357-7310

(Registrant’s telephone number, including area code)

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.

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If an emerging growth company, indicate by checkmark if the registrant has elected 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. ◻

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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. ☒

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

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The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1.6 billion based on the $5.10 per share closing price of Antero Midstream Corporation’s common stock as reported on that day on the New York Stock Exchange.

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The registrant had 476,906,973 shares of common stock outstanding as of February 12, 2021.

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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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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:

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, environmental risks, Antero Resources’ drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting Antero Resources’ future rates of production, cash flows and access to

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capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production by producers due to lack of downstream demand or storage capacity and the other risks described under the heading “Risk Factors” in this Annual Report on Form 10-K.

Should one or more of the risks or uncertainties described 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.

Summary Risk Factors

Customer Concentration

Business Operations

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Capital Structure and Access to Capital

Acquisitions and Takeovers

Joint Ventures

Compliance with Regulations

Related Parties

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GLOSSARY OF COMMONLY USED TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in our industry:

“ASC” Accounting Standards Codification.

“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.

“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.

“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.

“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.

“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 L.P. (“Antero Midstream Partners”), which is our wholly owned subsidiary, and MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, LP (“MPLX”), 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.

“MBbl.” One thousand Bbls.

“MBbl/d.” One thousand Bbls per day.

“Mcf.” One thousand cubic feet of natural gas.

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“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, isobutene and normal butane and natural gasoline.

“NYMEX.” New York Mercantile Exchange.

“Oil.” Crude oil and condensate.

“SEC.” United States Securities and Exchange Commission.

“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

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PART I

References in this Annual Report on Form 10-K to the “Company,” “ARMM,” “we,” “our,” “us” or like terms, when referring to periods prior to May 4, 2017, refer to our predecessor, Antero Resources Midstream Management LLC and its consolidated subsidiaries, which did not include Antero Midstream Partners LP (“Antero Midstream Partners”) or its consolidated subsidiaries.  References to the “Company,” “AMGP,” “we,” “our,” “us” or like terms, when referring to periods beginning on May 4, 2017 and ending on March 12, 2019, refer to our predecessor, Antero Midstream GP LP and its consolidated subsidiaries, which did not include Antero Midstream Partners or its consolidated subsidiaries. References to the “Company,” “Antero Midstream,” “AM,” “we,” “our,” “us” or like terms, when referring to periods beginning on March 13, 2019 and prospectively, refer to Antero Midstream Corporation and its consolidated subsidiaries, including Antero Midstream Partners and its subsidiaries. References in this Annual Report on Form 10-K to the Company’s, Antero Midstream’s, AM’s or our (i) indebtedness refer to the indebtedness of Antero Midstream Partners and (ii) operational or capital spending information refer to the operational or capital spending information of (1) for all periods prior to March 12, 2019, Antero Midstream Partners and its consolidated subsidiaries, and (2) for all periods on or after March 13, 2019, Antero Midstream and its consolidated subsidiaries, including Antero Midstream Partners and its subsidiaries.

Items 1 and 2. Business and Properties

Overview

Antero Midstream Corporation was originally formed as Antero Resources Midstream Management LLC in 2013 to become the general partner of Antero Midstream Partners.  On May 4, 2017, ARMM converted from a limited liability company to a limited partnership under the laws of the State of Delaware and changed its name to Antero Midstream GP LP (“AMGP”) in connection with its initial public offering. On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among AMGP, Antero Midstream Partners and certain of their 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 (the “Conversion”), (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 (the “Merger”) and (iii) Antero Midstream exchanged (the “Series B Exchange” and, together with the Conversion, the Merger and the other transactions pursuant to the Simplification Agreement, the “Transactions”) each issued and outstanding Series B Unit (the “Series B Units”) representing a membership interest in Antero IDR Holdings LLC (“IDR Holdings”) for 176.0041 shares of its common stock, par value $0.01 per share.

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 such area. 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 located primarily in West Virginia and Ohio. Our assets also include two independent water handling systems that deliver fresh water from the Ohio River and several regional waterways. These water handling systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilities, as well as pumping stations and impoundments to transport the fresh water throughout the pipelines. In addition, we also provide fluid handling services for flowback and produced water, including blending, storage and transportation operations, which services utilize certain of our permanent buried pipelines and surface pipelines. 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.

We utilize our midstream infrastructure assets to 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 contracts, limiting our direct exposure to commodity price risk.  As of December 31, 2020, all of Antero Resources’ approximate 582,000 gross acres (515,000 net acres) are dedicated to us for gathering, compression and water services, except for approximately 135,000 gross acres subject to third-party gathering and compression commitments.  We also own a 15% equity interest in the gathering system of Stonewall Gas Gathering LLC (“Stonewall”) and a 50% equity interest in the Joint Venture to develop processing and fractionation assets in Appalachia with MarkWest.  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.  Under its agreements with us and subject to any pre-existing dedications or other third-party commitments, Antero Resources has 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.  We also have certain rights of first offer with respect to gathering, compression, processing and fractionation services and water services for acreage located outside of the existing

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dedicated areas.  The gathering and compression agreement expires in 2038, and the water services agreement expires in 2035.  Both agreements are subject to automatic annual renewal with rights by either party to terminate on or before the 180^th day prior to the anniversary of such effective date.

In connection with our entrance into the water services agreement, 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. As of December 31, 2019, we had delivered 176 million barrels of fresh water, which entitled Antero Resources to $125 million pursuant to clause (a) above. In January 2020, Antero Midstream Partners paid Antero Resources $125 million. In the three-year period ended December 31, 2020, we delivered 163 million of the 219 million barrels of fresh water, and therefore, no such payment is due to Antero Resources’ pursuant to clause (b) above. As of December 31, 2020, no additional contingent acquisition consideration is expected to be earned.

Due to the extensive geographic distribution of our water pipeline systems in both West Virginia and Ohio, we are able to provide, and have in the past provided, water delivery services to other oil and gas producers operating within and adjacent to Antero Resources’ operating area in an effort to further leverage the use of our existing system.

Operating Segments

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

2020 Capital Investments

For the year ended December 31, 2020, our total capital spending was $182 million, which included $141 million of expansion capital and $41 million of maintenance capital.  We spent an aggregate of $141 million for gathering and compression infrastructure.  The additional gathering and compression infrastructure included 34 miles of pipelines in the Appalachian Basin.  Additionally, we invested an aggregate of $41 million in water infrastructure to construct six miles of additional buried water pipelines and surface pipelines in the Appalachian Basin.  We also invested $25 million in our unconsolidated affiliates.

2021 Capital Budget

During 2021, we plan to expand our existing Appalachian Basin gathering, processing and water handling infrastructure to accommodate Antero Resources’ development plans. Antero Resources announced that it plans to operate three drilling rigs and complete between 65 and 70 horizontal wells, substantially all of which are expected to be located on acreage dedicated to us. Antero Resources’ announced 2021 drilling and completion capital budget is $590 million. Our 2021 capital budget is a range of $240 million to $260 million, which includes approximately $65 million of additional growth capital supporting the increased volumes expected from Antero Resources’ drilling partnership in addition to its previously disclosed maintenance capital program for 2021.

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 fresh 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 water handling systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilities, as well as pumping stations and impoundments to transport fresh water throughout the systems used to deliver water to Antero Resources’ well completions. Our assets also include other flowback and produced water treatment facilities that we use to provide water treatment services to Antero Resources.

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The following table provides information regarding our gathering and processing systems and water handling systems as of December 31, 2020:

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As of December 31, 2020, we had the ability to store 5.7 million barrels of fresh water in 37 impoundments. Additionally, we own water blending and storage assets 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, waste water pits and a related landfill used for the disposal of salt therefrom (collectively, the “Clearwater Facility”), which we idled in September 2019.

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Idling of the Clearwater Facility

On September 18, 2019, we commenced a strategic evaluation of the Clearwater Facility. Based on the preliminary results of our evaluation and ongoing discussions with the Clearwater Facility’s contractor, the Clearwater Facility was idled. We expect the Clearwater Facility to continue to be idled for the foreseeable future. The decision to idle the Clearwater Facility was driven by its inability to operate at its intended specifications. Accordingly, we recorded impairment charges related to the Clearwater Facility of $409 million for property and equipment, $42 million of goodwill and $12 million in customer relationships during the year ended December 31, 2019. Additionally, during the year ended December 31, 2020, we determined that the carrying value of the landfill was no longer recoverable resulting in an impairment charge to property and equipment of $7 million. See Note 4—Clearwater Facility Idling to our consolidated financial statements. During the year ended December 31, 2019 and 2020, we incurred $11 million and $15 million, respectively, in facility idling costs for the care and maintenance of the Clearwater Facility. Since idling the Clearwater Facility, we have satisfied our obligation to handle Antero Resources’ flowback and produced water through our blending operations and third parties.

Our Relationship with Antero Resources

Antero Resources has a 29.2% ownership interest in us as of December 31, 2020. Antero Resources is our most significant customer and is one of the largest producers of natural gas and NGLs in the Appalachian Basin, where it produced, on average, 3.6 Bcfe/d net (33% liquids) during 2020, an increase of 11% as compared to 2019. As of December 31, 2020, Antero Resources’ estimated net proved reserves were 17.6 Tcfe, which were comprised of 57% natural gas, 42% NGLs and 1% oil. As of December 31, 2020, Antero Resources’ drilling inventory consisted of 2,133 identified potential horizontal well locations (approximately 1,531 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 and its production increases. Antero Resources announced its 2021 drilling and completion budget is $590 million, and includes plans to operate three drilling rigs, in the Appalachian Basin. Antero Resources relies significantly on us to deliver the midstream infrastructure necessary to accommodate its production growth. For additional information regarding our contracts with Antero Resources, please read “—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, please read “Item 1A. Risk Factors—Risks Related to Our Business.”

Operational and Managerial Arrangements with Antero Resources

Gathering and Compression

Pursuant to the gathering and compression agreement with Antero Resources, Antero Resources has dedicated all of its current and future acreage in West Virginia, Ohio and Pennsylvania to Antero Midstream Partners for gathering and compression except for acreage attributable to third-party commitments in effect prior to the agreement, or acreage Antero Resources acquires that is subject to pre-existing dedications. In December 2019, we and Antero Resources agreed to extend the initial term of the agreement to 2038 and established a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent Antero Resources achieves certain volumetric targets. For a discussion of Antero Resources’ existing third-party commitments

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and pre-existing dedications, please read “—Antero Resources’ Existing Third-Party Commitments.” 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. Under the gathering and compression agreement, we receive a low pressure gathering fee per Mcf, a high-pressure gathering fee per Mcf and a compression fee per Mcf, in each case subject to CPI-based adjustments. If and to the extent Antero Resources requests that we construct new high pressure lines and compressor stations, the gathering and compression agreement contain 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 service fee that allows us to earn a 13% rate of return on such new construction over seven years. Additional high pressure lines and compressor stations installed on our own initiative are not subject to these options. These minimum volume commitments and rate of return options on new infrastructure are intended to support the stability of our cash flows.

Antero Resources achieved all of its low pressure gathering growth incentive targets for 2020 and earned $48 million in fee reductions during the year. The following table summarizes the remaining low pressure gathering growth incentive targets for 2021 through 2023. If actual low pressure volumes are below the lowest tier for the respective calendar years, Antero Resources will not receive a reduction in low pressure gathering fees.

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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 per barrel in West Virginia and Ohio and all other locations for fresh water deliveries by pipeline directly to the well site. Antero Resources also agreed to pay us a fixed fee per barrel for wastewater treatment at the Clearwater Facility, which was idled in the third quarter of 2019 and we expect will remain idled for the foreseeable future. Additionally, we provide or manage other fluid handling services for well completion and production operations in Antero Resources’ operating areas. The fees for such services are all subject to CPI adjustments. In addition, we also provide fluid handling services for flowback and produced water, including blending, storage and transportation operations. 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 flowback and produced water services provided by third-parties, Antero Resources reimburses our third-party out-of-pocket costs plus 3%. For flowback and produced water 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. 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. For additional information, please read “—Antero Resources’ Existing Third-Party Commitments.”

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

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reimbursement of any direct expenses and an allocation of any indirect expenses attributable to its provision of such services. These agreements extend through 2039.

Antero Resources’ Existing Third-Party Commitments

Excluded Acreage

Antero Resources previously dedicated a portion of its acreage in the Appalachian Basin to certain third parties’ gathering and compression services. We refer to this acreage dedication as the “excluded acreage.” As of December 31, 2020, the excluded acreage consisted of approximately 135,000 of Antero Resources’ existing gross leasehold acreage, which included approximately 602 of Antero Resources’ 2,133 potential horizontal well locations. As part of its five year drilling plan, Antero Resources expects to drill most of its wells on acreage dedicated to us.

Other Commitments

In addition to the excluded acreage, Antero Resources has entered into contracts with certain third-parties that include minimum volume commitments for high pressure gathering and/or compression services. Specifically, those volume commitments consist of up to an aggregate of 450 MMcf/d on high pressure gathering pipelines and approximately 560 MMcf/d for compression services.

Acreage Dispositions

In addition to the excluded acreage and Antero Resources’ other commitments with third parties, each of the gathering and compression agreement, water services agreement and right of first offer agreement between Antero Resources and us permit 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.

Title to Properties

Our real property is classified into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned these lands without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of 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, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. 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 agreement; (ii) our water handling services agreement; and (iii) our right-of-first-offer agreement with Antero Resources for the provision of processing and fractionation

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services. For a description of this contract, please read “—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 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.

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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 2021, FERC issued an order (Order No. 865) 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 $1,307,164 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 “PIPES Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). 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 high-consequence areas or high consequence areas (“HCAs”).

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. The regulations require operators, including us, to:

● perform ongoing assessments of pipeline integrity;

● identify and characterize applicable threats to pipeline segments that could impact an HCA;

● improve data collection, integration and analysis;

● repair and remediate pipelines as necessary; and

● implement preventive and mitigating actions.

The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the 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 series of violations. Those maximum civil penalties have increased to $218,647 per violation per day, with a maximum of $2,186,465 for a series of violations, 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 October 2019, PHMSA published three final rules on pipeline safety. The Enhanced Emergency Order Procedures rule (effective December 2, 2019) implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if unsafe conditions or practices, or a combination thereof, constitutes or causes an imminent hazard. The Safety of Hazardous Liquid Pipelines rule (effective July 1, 2020) expands PHMSA’s regulation of the safety of hazardous liquid pipelines by extending reporting requirements to certain hazardous liquid gravity flow and rural gathering pipelines, establishing new requirements for integrity management programs for hazardous liquid pipelines in HCAs and certain other hazardous liquid pipelines and expanding various inspection and leak detection requirements. The Safety of Gas Transmission Pipelines rule (effective July 1, 2020) requires operators of certain gas transmission pipelines to reconfirm the Maximum Allowable Operating Pressure (MAOP) of their lines and establishes a new “Moderate Consequence Area” for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting baseline assessments and incorporates industry standards and

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guidelines as well as new requirements for integrity management programs. 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.

PHMSA has also been working on two additional rules related to gas pipeline safety, though we cannot predict when they will be 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” is expected to adjust the repair criteria for pipelines in HCAs, create new criteria for pipelines in non-HCAs and strengthen integrity management assessment requirements. The rule entitled “Safety of Gas Gathering Pipelines” is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas.

Separately, in the Fiscal Year 2021 Omnibus Appropriations Bill, Congress directed PHMSA to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations to require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. 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:

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

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

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

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

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

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes

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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, in July 2015, the Ohio Department of Natural Resources issued final rules for horizontal drilling well-pad construction. The Ohio legislature has also adopted laws 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 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 customer’s 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

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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, 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 (“NAAQS”), for ozone from 75 to 70 parts per billion, and completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Applicable laws and regulations require pre-construction permits for the construction or modification of certain projects or facilities with the potential to emit air emissions above certain thresholds. These pre-construction permits generally require use of best available control technology (“BACT”), to limit air emissions. 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 (the “Clean Water Act”), 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. In September 2015, the EPA and the Corps issued a final rule defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the U.S. (the “WOTUS rule”). However, on January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows the definition of “waters of the United States” relative to the prior 2015 rulemaking. Legal challenges to both this and prior revisions to the definition of WOTUS are ongoing, and it is possible that a new presidential administration could propose a broader interpretation of the CWA’s jurisdiction. As a result of these developments, the scope of jurisdiction under the CWA is uncertain at this time. To the extent any rule 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 Clean Water Act Section 404 Nationwide Permit 12 (“NWP 12”)

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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 pending appeal and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts to the Nationwide Permit 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, the rulemaking may be subject to litigation or to further revision under the Biden Administration. While the full extent and impact of the vacatur 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 noncompliance with worker health and safety requirements 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, on January 28, 2020, the U.S. District Court for the District of Columbia ordered the USFWS to reconsider its decision to list the northern long-eared bat as threatened instead of endangered. The designation of previously unprotected species as threatened or endangered, or redesignation of a threatened species as endangered, in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or could result in limitations on our pipeline construction activities or the exploration and production activities of Antero Resources, any of which could have an adverse impact on our results of operations.

Climate Change

In response to findings that emissions of greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act, 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 BACT 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. In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that set emissions standards for methane and volatile organic compounds 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

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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. 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.

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In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by President Biden and other public office representatives. These have included promises to pursue actions to limit emissions and curtail the production of oil and gas, such as through banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. 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 fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. 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. Additionally, President Biden has issued executive orders recommitting the United States to the Paris Agreement and directing the federal government to begin formulating the United States’ nationally determined emissions reduction target under the agreement. The impacts of this order, and any legislation or regulation promulgated to fulfill the United States commitments under the Paris Agreement cannot be predicted at this time. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects and therefore are responsible for damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

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Additionally, our access to capital may be impacted by climate change policies. Financial institutions may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, the Federal Reserve recently announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. While we cannot predict what policies may result from this, a material reduction in the capital available to the fossil fuel 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. Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

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Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2020, nor do we anticipate that such expenditures will be material in 2021.

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.

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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, 2020, approximately 522 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.

Total Rewards

We have demonstrated a history of investing in our workforce by offering competitive salaries, wages and 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:

Role Based Support

We support our employees’ professional development. To help our personnel succeed in their roles, we emphasize continuous formal and informal training and development opportunities. We disseminate training by department to focus on job and area specific training. 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.

In response to the COVID-19 pandemic, we have implemented significant changes 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. These include having our office employees work from home to the extent they are able and implementing additional safety measures, including required weekly testing and other recommended public health measures, for our field and other employees continuing critical on-site work.

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.

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Address, Internet Website and Availability of Public Filings

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

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

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

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

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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

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.

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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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. The low commodity price environment has negatively impacted natural gas producers causing some producers in 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.

Please see Item 1A, “Risk Factors” in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, 2020 (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.

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.

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

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or other producers or their development plan decisions, which are affected by, among other things:

The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu in 2020, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $63.27 per barrel to a low of $(36.98) per barrel during the same period. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. Because Antero Resources’ production and reserves predominantly consist of natural gas (approximately 57% 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.

These lower prices have compelled most natural gas and oil producers, including Antero Resources, to reduce the level of exploration, drilling and production activity and capital budgets. For example, Antero Resources’ 2021 capital budget is $625 million, compared to 2019 and 2020 capital expenditures of $1.3 billion and $785 million, respectively. This will have a significant effect on our capital resources, liquidity and expected operating results. Natural gas and oil prices directly affect Antero Resources’ production. If prices remain at low levels or decrease further, 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, each of the gathering and compression agreement, water services agreement and right of first offer agreement between us and Antero Resources permits Antero Resources to sell, transfer, convey, assign, grant or otherwise dispose of dedicated properties free of the dedication under such agreements, provided that the number of net acres of dedicated properties so disposed of, when added to the number of net acres of dedicated properties previously disposed of free of the dedication since the respective effective dates of the agreements, does not exceed the aggregate number of net acres of dedicated properties acquired by Antero Resources since such effective dates. Accordingly, under certain circumstances, Antero Resources may dispose of a significant number of net acres of dedicated properties free from dedication without our consent, and we have no control over the timing or extent of such dispositions. Any such dispositions could adversely affect our business and operating results. Even if the disposed property remains dedicated to us, the goals and intention of 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 have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have 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, have caused extreme market volatility and a substantial adverse effect on commodity prices. 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, our 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.

The gathering and compression agreement includes minimum volume commitments only under certain circumstances.

The gathering and compression agreement includes minimum volume commitments only on new high pressure pipelines and compressor stations constructed subsequent to November 2014 at Antero Resources’ request. The high pressure pipelines and compressor stations that existed prior to November 2014 are not supported by minimum volume commitments from Antero Resources. There are no minimum volume commitments on the low pressure pipelines or fresh water distribution pipelines. Any decrease in the current levels of throughput on our gathering, compression and fresh water distribution systems could reduce our revenue and cash flows.

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.

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.

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.

The construction of gathering pipelines, compressor stations, processing and fractionation facilities and water handling assets is subject to construction cost overruns due to costs and availability of equipment and materials such as steel.  If third party providers of steel products essential to our capital improvements and additions are unable to obtain raw materials, including steel, at historical prices, they may raise the price we pay for such products.  On March 8, 2018, the President of the United States issued two

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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.

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

Our 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, could have a material adverse effect on our business, financial condition and results of operations.

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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.

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, or if our customers do not renew or extend their contracts with us, or if 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. Restrictions on the ability to obtain water may incentivize water recycling efforts by oil and natural gas producers, which would decrease the demand for our fresh water delivery services.

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. These improvements allowed Antero Resources to reuse a portion of its produced water through our blending 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.  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.

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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. 

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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.    

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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 fossil fuel energy companies or the corresponding infrastructure projects based on climate change related concerns, which could affect our access to capital for potential growth projects.

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.

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

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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:

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.

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

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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 or cyber-attacks and threats could have a material adverse effect on our business, financial condition and results of operations.

Terrorist or cyber-attacks 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. Our insurance may not protect us against such occurrences. 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. Deliberate attacks on our assets or our Joint Venture’s assets, security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties or the cloud, 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. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.

As cyber-attacks 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 cyber-attacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date, we have not experienced any material losses relating to cyber-attacks; 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

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.

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

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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.

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.

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 experienced periods of improvement in 2020, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms or at all, we may be unable to carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

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

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

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

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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. Please read “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:

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

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue growth opportunities, reduce cash flow used for our services and place us at a competitive disadvantage. For example, during 2020, we had average outstanding borrowings under our revolving credit facility of approximately $1.1 billion, 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 $11 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.

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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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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:

        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.

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

Certain funds affiliated with Yorktown Partners LLC (“Yorktown”), Paul M. Rady and Glen C. Warren, Jr. (collectively, the “Sponsors”) own a significant interest in us. Messrs. Rady and Warren and an individual affiliated with Yorktown serve as members of our Board and the board of directors of Antero Resources. The Sponsors also own a significant portion of the shares of common stock of Antero Resources. As a result of their investments in Antero Resources, the Sponsors may have conflicting interests with other stockholders. Conflicts of interest could arise in the future between us, on the one hand, and the Sponsors, 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.

Joint Ventures

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

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:

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 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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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

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.

Our operations are subject to complex and stringent federal, state and local laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations and the permits and other approvals issued thereunder. In addition, our costs of compliance may increase or operational delays may occur if existing laws and regulations are revised or reinterpreted, or if new laws and regulations apply to our operations. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations. Also, we might not be able to obtain or maintain all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.

In addition, new or additional regulations, new interpretations of existing requirements or changes in our operations could also trigger the need for Environmental Assessments or more detailed Environmental Impact Statements under the National Environmental Policy Act 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 Corps Clean Water Act Section 404 Nationwide 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 pending appeal and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts to the nationwide permit 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, the rulemaking may be subject to litigation or to further revision under the Biden Administration. While the full extent and impact of the vacatur 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, in January 2020, EPA and the Corps issued a final rule under the Clean Water Act (“CWA”) revising the definition of waters of the United States (“WOTUS”); however, both this and prior revisions to the definition of WOTUS are currently subject to litigation, and it is possible that a new presidential administration could propose a broader interpretation of the CWA’s jurisdiction. As a result, the scope of the CWA’s jurisdiction is uncertain at this time. To the extent any rule 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

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effect on our business, financial condition and results of operations. Further, the 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. Please read “Item 1. Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.

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.

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

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

Moreover, FERC regulations indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and market center promotion, indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our financial condition, cash flows and results of operations. The FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1,307,164 per day for each violation and disgorgement of profits associated with any violation.

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

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.

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 pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. In addition, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. New legislation regulating hydraulic fracturing may be considered again in future, though we cannot predict when or the scope of any such legislation at this time. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. At the state level, several states have adopted or are considering adopting regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic

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fracturing operations. For example, in July 2015, the Ohio Department of Natural Resources issued final rules for horizontal drilling well-pad construction. The Ohio legislature has also adopted laws 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, following the election of President Biden and a Democratic majority in both houses of Congress, it is possible that 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.

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. Please read “Business—Regulation of Environmental and Occupational Safety and Health Matters” for more information.

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.

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

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EPA has adopted regulations under existing provisions of the federal Clean Air Act 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.

In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that establish emission standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. The EPA’s rule package included first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rule package extended existing VOC standards under the EPA’s Subpart OOOO to include previously unregulated equipment within the oil and natural gas source category. 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. 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 United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had withdrawn from the Paris Agreement, effective January 20, 2021, President Biden has issued executive orders recommitting the United States to the Paris Agreement and directing the federal government to begin formulating the United States’ nationally determined emissions reduction target under the Paris Agreement. The impacts of this order, and any legislation or regulation promulgated to fulfill the United States commitments under the Paris Agreement 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. These have included promises to pursue actions to limit emissions and curtail the production of oil and gas, such as through the cessation of leasing public land for hydrocarbon development. 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 fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. 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, fossil fuel companies are also exposed to litigation risks from climate change. A number of cities and other local governments have brought suits against the largest fossil fuel companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer protection laws, alleging that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts. 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 fossil fuel sector 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-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to sustainable lending practices, and some of them may elect in future not to provide funding for fossil fuel energy companies. 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 fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available to the fossil fuel 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.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other

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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. Additionally, political, litigation and financial risks may result in our restricting or cancelling oil and natural gas production activities, incurring liability for damages resulting from climate change or impairing our ability to continue operating in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation. Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on exploration and production 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. The regulations require operators to:

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (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 Pipelines and Hazardous Materials Safety Administration (“PHMSA”), finalized rules consistent with the signed act 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 July 2019, those maximum civil penalties were increased to $218,647 and $2,186,465, 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.

In June 2016, the President of the United States signed into law important new legislation entitled Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “PIPES Act”). The PIPES Act facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. The PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from 2011 Pipeline Safety Act, of which several remain to be completed.

PHMSA regularly revises its pipeline safety regulations. For example, in October 2019, PHMSA published three final rules on pipeline safety. The Enhanced Emergency Order Procedures rule (effective December 2, 2019) implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if unsafe conditions or practices, or a combination thereof, constitutes or causes an imminent hazard.  The Safety of Hazardous Liquid Pipelines rule (effective July 1, 2020) expands PHMSA’s regulation of the safety of hazardous liquid pipelines by extending reporting requirements to certain hazardous liquid gravity flow and rural gathering pipelines, establishing new requirements for integrity management programs for hazardous liquid pipelines in HCAs and certain other hazardous liquid pipelines, and expanding various inspection and leak detection requirements.  The Safety of Gas Transmission Pipelines rule (effective July 1, 2020) requires operators of certain gas transmission

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pipelines to reconfirm the Maximum Allowable Operating Pressure (MAOP) of their lines and establishes a new “Moderate Consequence Area” for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting baseline assessments and incorporates industry standards and guidelines as well as new requirements for integrity management programs. The rule also includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards.  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.

PHMSA is working on two additional rules related to gas pipeline safety, though we cannot predict when they will be 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” is expected to adjust the repair criteria for pipelines in HCAs, create new criteria for pipelines in non-HCAs and strengthen integrity management assessment requirements. The rule entitled “Safety of Gas Gathering Pipelines” is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas.  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. Please read “Business—Pipeline Safety Regulation” for more information.

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 and Chief Executive Officer, and Glen C. Warren, Jr., President, 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

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.

All of our officers and certain of our directors are also officers or directors of Antero Resources. Also, as of December 31, 2020, Antero Resources beneficially owned 29.2% of our outstanding common stock. 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. Conflicts of interest will arise between Antero Resources and us. In resolving these actual or apparent conflicts of interest, members of our Board may choose strategies that favor Antero Resources over our interests and the interests of our stockholders. These conflicts 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

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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 the processing and fractionation services provided by the Joint Venture are supported by minimum volume commitments, the gathering and compression agreement includes minimum volumes commitments only on high pressure pipelines and compressor stations constructed at Antero Resources’ request after November 2014.  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.

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 2023. 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.

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 2023. 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

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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.

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General Risks

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

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

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

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

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

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

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

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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 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

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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

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.

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.

Veolia

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

On March 13, 2020, Antero Treatment LLC (“Antero Treatment”), a wholly owned subsidiary of the Company, filed suit against Veolia and Veolia North America 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 design flaws during contract negotiations and continued to conceal and fraudulently misrepresent the impact of certain design changes post-execution of the DBA. Antero Treatment is seeking damages from Veolia of at least $457 million, which represents the Company’s recorded impairment of the idled Clearwater Facility. In the alternative, Antero Treatment sought rescission of the DBA and restitution of, at a minimum, the $230 million out-of-pocket costs paid to Veolia pursuant to the DBA. Antero Treatment also asserts related claims against Veolia North America, including equitable claims with respect to certain amounts Antero paid to Veolia North America.

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 asserts breach of contract and equitable claims against the Antero Defendants for alleged failures under the DBA, including an allegation that the Antero Defendants improperly terminated the DBA to prevent Veolia from earning an approximate $26 million contract balance. The Antero Defendants vigorously deny Veolia’s claims. Veolia seeks money damages in an amount not yet specified. Veolia’s suit has been consolidated into the action filed by Antero Treatment.

On April 17, 2020, Veolia, Veolia North America and the Antero Defendants each filed partial motions to dismiss directed at certain claims asserted by the opposing party. On July 23, 2020, the Court dismissed Veolia’s equitable claims against the Antero

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Defendants and Antero Treatment’s alternative claim for rescission against Veolia. All other claims remain part of the consolidated action. The case is set for trial beginning on November 29, 2021.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Common Stock

We have one class of common equity outstanding, our common stock, par value $0.01 per share. Our common stock is listed on the New York Stock Exchange and traded under the symbol “AM.” On February 12, 2021, shares of our common stock were held by 49 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 12, 2021, Antero Resources and its subsidiaries owned 139,042,345 shares of our common stock, which represented a 29.2% interest in us.

Issuer Purchases of Equity Securities

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

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Dividends

On January 20, 2021, the Board declared an aggregate cash dividend on the shares of our common stock of $0.3075 per share for the quarter ended December 31, 2020. The dividend will be payable on February 11, 2021 to stockholders of record as of February 3, 2021.

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”), to be paid on February 16, 2021 in accordance with the terms of the Series A Preferred Stock, which are discussed in Note 14—Equity and Earnings Per Common Share to our consolidated financial statements. As of December 31, 2020, there were dividends in the amount of $69 thousand accumulated in arrears on our Series A Preferred Stock.

Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 on May 4, 2017, the date of our initial public offering, in each of our predecessor’s common shares through March 12, 2019 and our common stock thereafter, the

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Standard & Poor’s 500 (“S&P 500”) Index, and 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. Selected financial data

The following table presents our selected historical financial data, for the periods and as of the dates indicated, for the Company and its predecessors. Our predecessor, AMGP, was originally formed as ARMM to become the general partner of Antero Midstream Partners and converted into a limited partnership on May 4, 2017 in connection with our IPO. On March 12, 2019, pursuant to the Simplification Agreement, we completed the Transactions.

The Merger has been accounted for as an acquisition by AMGP of Antero Midstream Partners under ASC 805 – Business Combinations and accounted for as a business combination, with the assumed assets and liabilities of Antero Midstream Partners recorded at their estimated fair value. As a result of the Merger, our historical financial data for previous periods are not comparable to the years ended December 31, 2019 and 2020 or to our future financial results. The selected financial data for the years ended December 31, 2016, 2017 and 2018 are the financial statements of AMGP and its consolidated subsidiaries, which do not include Antero Midstream Partners and its subsidiaries.  Effective March 12, 2019, we began consolidating Antero Midstream Partners and its subsidiaries in our consolidated financial statements. As a result, our selected balance sheet financial data presented below at December 31, 2019 includes the financial position of Antero Midstream Partners and its subsidiaries, and our selected consolidated statements of operations and comprehensive income and cash flows data for the year ended December 31, 2019 include the results of operations of Antero Midstream Partners and its subsidiaries beginning on March 13, 2019. The historical selected consolidated statement of operations data included herein reflects that, prior to the Merger, AMGP’s only income resulted from distributions made on the incentive distribution rights (the “IDRs”) of Antero Midstream Partners and expenses were limited to general and administrative expenses and equity-based compensation. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Items Affecting Comparability of our Financial Results.”

Accordingly, we are also presenting our pro forma results of operations for the years ended December 31, 2018 and December 31, 2019, which give effect to the adjustments described in Exhibit 99.1 to this Annual Report on Form 10-K. The pro forma information presented below should be read in conjunction with the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K and describe the assumptions and adjustments used in preparing such information. The pro forma adjustments are based on currently available information and certain estimates and

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assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the results of operations on a more meaningful basis.

The selected statement of operations data and statement of cash flows data for the years ended December 31, 2018, 2019 and 2020 and the balance sheet data as of December 31, 2019 and 2020 are derived from our audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K. The selected statement of operations data and statement of cash flows data for the years ended December 31, 2016 and 2017 and the selected balance sheet data as of December 31, 2016, 2017 and 2018 is derived from our audited consolidated financial statements not included in Item 8 of this Annual Report on Form 10-K.

The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this report:

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The following table presents our pro forma results of operations for the years ended December 31, 2018 and 2019, which give effect to the adjustments described in Exhibit 99.1 to this Annual Report on Form 10-K. The pro forma information presented below should be read in conjunction with the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K and describe the assumptions and adjustments used in preparing such information.

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Non-GAAP Financial Measures

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We use Adjusted EBITDA as an important indicator of our performance. In our presentation of Adjusted EBITDA for the year ended December 31, 2020, net income (loss) and the corresponding adjustments reflect our actual results of operations.  In our presentation of Adjusted EBITDA for the years ended December 31, 2019 and 2018, net income (loss) and the corresponding adjustments reflect our pro forma results of operations. The pro forma information should be read in conjunction with the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K. For more information, see “Items Affecting Comparability of Our Financial Results.”

We define Adjusted EBITDA as net income before net interest expense, income tax expense, depreciation, impairment, accretion and changes in fair value of contingent acquisition consideration, accretion of asset retirement obligations, equity-based compensation, excluding equity in earnings of unconsolidated affiliates, contract restructuring expenses, amortization of customer relationships, gains and losses on asset sales and including cash 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.

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Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss). The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income (loss). 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 (loss). 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.

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