UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended | |
or | |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
Commission File No.
(Exact name of registrant as specified in its charter)
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(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act: | ||||
Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||
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. ⌧
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 ⌧
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. ⌧
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). ⌧
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.
Emerging growth company | Accelerated filer ◻ | Non-accelerated filer ◻ | Smaller reporting company |
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. ◻
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).
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $
The registrant had
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.
TABLE OF CONTENTS
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.
“ASU.” Accounting Standards Update.
“Antero Resources.” Antero Resources Corporation
“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.
“CPI.” Consumer Price Index.
“Credit Facility.” The Prior Credit Facility and New Credit Facility collectively.
“DOT.” Department of Transportation.
“Dry gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
“EPA.” Environmental Protection Agency.
“ESG.” Environmental, social and governance.
“Expansion capital.” Cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.
“FASB.” Financial Accounting Standards Board.
“FERC.” Federal Energy Regulatory Commission.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Fresh water.” Water that is either (i) raw fresh water or (ii) produced or flowback water that has been treated, including through blending operations.
“GHG.” Greenhouse gas.
“High pressure pipelines.” Pipelines gathering or transporting natural gas that has been dehydrated and compressed to the pressure of the downstream pipelines or processing plants.
“Hydrocarbon.” An organic compound containing only carbon and hydrogen.
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“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, a wholly owned subsidiary of MPLX, LP, to develop processing and fractionation assets in Appalachia.
“Low pressure pipelines.” Pipelines gathering natural gas at or near wellhead pressure that has yet to be compressed (other than by well pad gas lift compression or dedicated well pad compressors) and dehydrated.
“Maintenance capital.” Cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue.
“MarkWest.” MarkWest Energy Partners, L.P.
“MBbl.” One thousand Bbls.
“MBbl/d.” One thousand Bbls per day.
“Mcf.” One thousand cubic feet of natural gas.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet of natural gas.
“MMcf/d.” One million cubic feet per day.
“Natural gas.” Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.
“New Credit Facility.” The senior secured revolving credit facility in effect on and after October 26, 2021.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutane, normal butane and natural gasoline.
“NYMEX.” New York Mercantile Exchange.
“Oil.” Crude oil and condensate.
“Other fluid handling services.” Flowback and produced water services, including blending and storage operations, and transportation away from the well site.
“Prior Credit Facility.” The senior secured revolving credit facility in effect for periods before October 26, 2021.
“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.
“Transactions.” On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP (“AMGP”), Antero Midstream Partners LP (“Antero Midstream Partners”) and certain of Antero Midstream Partners’ affiliates (the “Simplification Agreement”) (i) AMGP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation (together with its consolidated subsidiaries, as appropriate, “Antero Midstream”), and (ii) an indirect, wholly owned subsidiary of Antero Midstream was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this Annual Report on Form 10-K may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact, included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
| ● | Antero Resources expected production and development plan; |
| ● | impacts to producer customers of insufficient storage capacity; |
| ● | our ability to execute our business strategy; |
| ● | our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness; |
| ● | our ability to realize the anticipated benefits of our investments in unconsolidated affiliates; |
| ● | natural gas, NGLs and oil prices; |
| ● | impacts of world health events, including the coronavirus (“COVID-19”) pandemic; |
| ● | our ability to complete the construction of or purchase new gathering and compression, processing, water handling or other assets on schedule, at the budgeted cost or at all and the ability of such assets to operate as designed or at expected levels; |
| ● | our ability to execute our share repurchase program; |
| ● | competition and government regulations; |
| ● | actions taken by third-party producers, operators, processors and transporters; |
| ● | pending legal or environmental matters; |
| ● | costs of conducting our operations; |
| ● | general economic conditions; |
| ● | credit markets; |
| ● | operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control; |
| ● | uncertainty regarding our future operating results; and |
| ● | our other plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K. |
We caution investors that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, 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 capital, the timing of development expenditures, impacts of world health events (including the COVID-19 pandemic), cybersecurity risks and the other risks described under the heading “Risk Factors” in this Annual Report on Form 10-K.
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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.
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Summary Risk Factors
Customer Concentration
| ● | Because substantially all of our revenue is currently derived from Antero Resources, any development that materially and adversely affects Antero Resources’ operations, financial condition or market reputation could have a material and adverse impact on us. |
| ● | Because of the natural decline in production from existing wells, our success depends, in part, on Antero Resources’ ability to replace declining production and our ability to secure new sources of natural gas from Antero Resources or third parties. Additionally, our water handling services are directly associated with Antero Resources’ well completion activities and water needs, which are largely driven by the amount of water used in completing each well. Finally, under certain circumstances, Antero Resources may dispose of acreage dedicated to us free from such dedication without our consent. Any decrease in volumes of natural gas that Antero Resources produces, any decrease in the number of wells that Antero Resources completes, or any decrease in the number of acres that are dedicated to us could adversely affect our business and operating results. |
Business Operations
| ● | A material shut-in of production by Antero Resources or any of our other customers could adversely affect our business. |
| ● | The gathering and compression agreement includes minimum volume commitments only under certain circumstances. |
| ● | Our construction or purchase of new gathering and compression, processing, water handling or other assets may not be completed on schedule, at the budgeted cost or at all, may not operate as designed or at the expected levels, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, all of which could adversely affect our financial condition, cash flows and results of operations. |
| ● | Recent action and the possibility of future action on trade by U.S. and foreign governments has increased the costs of certain equipment and materials used in the construction of our assets and has created uncertainty in global markets, which may adversely affect our income from operations and cash flows. |
| ● | If third-party pipelines or other midstream facilities interconnected to our gathering and compression systems become partially or fully unavailable, our operating margin and cash flows could be adversely affected. |
| ● | Our exposure to commodity price risk may change over time. |
| ● | The fees charged to our customers may not escalate sufficiently to cover increases in costs, or the agreements may be amended with less favorable terms, may not be renewed or may be suspended in some circumstances. |
| ● | Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. |
| ● | Increasing attention to ESG matters and conservation measures may adversely impact our business. |
| ● | Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our business, financial condition and results of operations. |
| ● | A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business. |
Capital Structure and Access to Capital
| ● | We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful. |
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| ● | We will be required to make capital expenditures to increase our asset base. If we cannot obtain needed capital or financing on satisfactory terms, we may be unable to expand our business operations and/or our financial leverage could increase. |
| ● | Restrictions in our existing and future debt agreements could adversely affect our business, financial condition and results of operations. |
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. |
| ● | Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders. |
Joint Ventures
| ● | We own a 50% interest in the Joint Venture, which is operated by MarkWest. While we have the ability to influence certain business decisions affecting the Joint Venture, the success of our investment in the Joint Venture will depend on MarkWest’s operation of the Joint Venture. |
| ● | If the Joint Venture is not successful or if the Joint Venture does not perform as expected, our future financial performance may be negatively impacted. |
Compliance with Regulations
| ● | We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities. |
| ● | If our assets become subject to FERC regulation or federal, state or local regulations or policies change, or if we fail to comply with market behavior rules, our financial condition, cash flows and results of operations could be materially and adversely affected. |
| ● | Increased regulation of hydraulic fracturing could result in reductions or delays in production by our customers, which could reduce the throughput on our gathering and processing systems and the number of wells for which we provide water handling services, which could adversely impact our revenues. |
Related Parties
| ● | Antero Resources owns a significant interest in us and, as a result, conflicts of interest will arise from time to time between it and us, and Antero Resources may favor their own interests to the detriment of us and our other stockholders. Additionally, Antero Resources is under no obligation to adopt a business strategy that favors us. |
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PART I
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 LP (“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
We are a growth-oriented midstream energy company formed to own, operate and develop midstream energy assets that primarily service Antero Resources’ production and completion activity in the Appalachian Basin located in West Virginia and Ohio. Our assets consist of gathering systems and compression facilities, water handling and blending facilities and interests in processing and fractionation plants. We conduct our operations and own our operating assets and ownership interests in the Joint Venture and Stonewall Gas Gathering LLC (“Stonewall”) through Antero Midstream Partners and its subsidiaries, all of which are wholly-owned. Additionally, Antero Resources has a 29.1% ownership interest in us as of December 31, 2021.
The map below provides information about our assets. For additional information, see “—Our Assets”.
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Business Strategy and Competitive Strengths
Scalable Business Model
We believe that our strategically located assets and our relationship with Antero Resources have allowed us to become a leading midstream energy company serving the Appalachian Basin. Our significant investment in West Virginia and Ohio infrastructure makes us well positioned to deliver returns on capital and grow the business in a capital efficient manner.
Additionally, we own a 15% equity interest in the Stonewall gas gathering system and a 50% equity interest in the Joint Venture to develop processing and fractionation assets in Appalachia with MarkWest. These investments provide us with greater exposure to the midstream value chain.
Disciplined Capital Investment
We utilize a flexible, just-in-time capital budgeting approach through integrated planning with Antero Resources, which allows us to avoid long lead-times in our capital investments in order to maximize our returns on invested capital. We believe this just-in-time capital budgeting approach is unique to Antero Midstream and will allow us to generate sustainable free cash flow.
Fixed Fee Business with Long-Term Customer Contracts
We provide gathering, compression, processing, fractionation and integrated water services, including fresh water delivery services and other fluid handling services, to Antero Resources under long-term, fixed-fee and cost of service fee contracts, limiting our direct exposure to commodity price risk. Our gathering and compression agreement expires in 2038, and our 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 180th day prior to the effective date of such automatic renewal. Additionally, Antero Resources has (i) dedicated to us all of its current and future acreage in the Appalachian Basin for gathering and compression services and all of its acreage within defined service areas in the Appalachian Basin for water services, subject to any pre-existing dedications or other third-party commitments, and (ii) granted us certain rights of first offer with respect to gathering, compression, processing and fractionation services and water services for acreage located outside of the existing dedicated areas under our existing agreements. See “—Our Relationship with Antero Resources” for further information.
Experienced Management Team
Our management team has worked together for many years and has established a successful track record of developing integrated business models that are capable of delivering consistent returns on capital. We intend to leverage our management team’s significant industry expertise and experience developing natural gas resource plays to continue building a premier midstream energy company to service Antero Resources and the other operators in the Appalachian Basin.
Culture of Continuous Improvement and Responsible Stewardship
We are committed to a culture of continuous improvement, which serves as our foundation to develop and achieve our ESG goals as well as further our goal of environmental stewardship. Innovation, collaboration, technology and establishing meaningful goals have enabled us to improve our safety record, recycle or reuse a substantial majority of Antero Resources’ produced and flowback water and further our commitment to lowering GHG emissions intensity across our operations. We believe natural gas is key to the energy transition because of its ability to provide energy security to developing nations and replace more GHG-intensive sources of fuel. We embrace our role in providing the infrastructure that supports a low-carbon future and seek to build upon past GHG emission reduction efforts. Our 2020 ESG Report, available on our website at www.anteromidstream.com/community-sustainability, includes more information on our ESG goals, as well as specific initiatives we have in place to help achieve these goals. Our 2020 ESG Report and other information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them. Additionally, see “—Regulation of Environmental and Occupational Safety and Health Matters” for more information on GHG emissions and “Item 1A. Risk Factors” for risks and uncertainties related to our business operations.
Operating Segments
Our operations are located in the United States and are organized into two reportable segments: (1) gathering and processing and (2) water handling. Financial information for our reportable segments is located under Note 17—Reportable Segments to our consolidated financial statements.
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Our Assets
Our gathering and compression assets consist of high and low pressure gathering pipelines, compressor stations and processing and fractionation plants that collect and process natural gas and NGLs from Antero Resources’ wells in West Virginia and Ohio. Our water handling assets include two independent systems that deliver water from sources, including the Ohio River, local reservoirs and several regional waterways with portions of these systems also being utilized to transport flowback and produced water. The water handling systems consist of permanent buried pipelines, surface pipelines and water storage facilities, as well as pumping stations, blending facilities and impoundments to transport water throughout the systems used to deliver water to Antero Resources’ well completions. Our assets also include other flowback and produced water treatment facilities that we use to provide water treatment services to Antero Resources.
The following table provides information regarding our gathering and processing systems and water handling systems as of December 31, 2021:
| Gathering and Processing Systems |
| Water Handling Systems | ||||||||
Low-Pressure | High-Pressure | Compression | Buried | Surface | |||||||
Pipeline | Pipeline | Capacity | Water Pipeline | Water Pipeline | |||||||
(miles) | (miles) | (MMcf/d) |
| (miles) |
| (miles) | |||||
Appalachian Basin | 293 | 201 | 3,425 | 216 | 134 | ||||||
During the year ended December 31, 2021, we added 26 miles of gathering and compression pipelines and 12 miles of buried and surface water pipelines in the Appalachian Basin. As of December 31, 2021, we had the ability to store 5.5 million barrels of water in 36 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, wastewater pits and a related landfill used for the disposal of salt therefrom (collectively, the “Clearwater Facility”), which we idled in September 2019. See Note 4—Clearwater Facility Idling to our consolidated financial statements for more information. Since idling the Clearwater Facility, we have satisfied our obligation to handle Antero Resources’ flowback and produced water through our other fluid handling services.
Our Relationship with Antero Resources
Antero Resources is our most significant customer and is one of the largest producers of natural gas and NGLs in North America. As of December 31, 2021, all of Antero Resources’ approximate 557,000 gross acres (502,000 net acres) are dedicated to us for gathering, compression and water services, except for approximately 127,000 gross acres subject to third-party gathering and compression commitments. During the year ended December 31, 2021, Antero Resources produced, on average, 3,271 MMcfe/d net (31% liquids). As of December 31, 2021, Antero Resources’ estimated net proved reserves were 17.7 Tcfe, which were comprised of 58% natural gas, 41% NGLs and 1% oil. As of December 31, 2021, Antero Resources’ drilling inventory consisted of 2,083 identified potential horizontal well locations (approximately 1,371 of which were located on acreage dedicated to us) for gathering and compression and water handling services, which provides us with significant opportunities for growth as Antero Resources’ active drilling program continues. Antero Resources announced its 2022 drilling and completion budget is $675 million to $700 million, and includes plans to complete 60 to 65 net wells in the Appalachian Basin. Antero Resources relies significantly on us to deliver the midstream infrastructure necessary to accommodate its development program. For additional information regarding our contracts with Antero Resources, see “—Operational and Managerial Arrangements with Antero Resources.”
We currently derive substantially all of our revenue from Antero Resources. Any development that materially and adversely affects Antero Resources’ operations, financial condition or market reputation could have a material adverse impact on us. Accordingly, we are indirectly subject to the business risks of Antero Resources. For additional information, see “Item 1A. Risk Factors—Risks Related to Our Business.”
Operational and Managerial Arrangements with Antero Resources
Gathering and Compression
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 through 2023 to the
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extent Antero Resources achieves certain volumetric targets. For a discussion of Antero Resources’ existing third-party commitments and pre-existing dedications, see “—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 annual CPI-based adjustments. If and to the extent Antero Resources requests that we construct new low pressure lines, high pressure lines and/or compressor stations, 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 cost of service fee that allows us to earn a 13% rate of return on such new construction over seven years, which election is made individually for each piece of equipment. Minimum volume commitments for high pressure gathering capacity and compression capacity are aggregated such that there is a single minimum volume commitment for the respective service each month. 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 are intended to support the stability of our cash flows.
Antero Resources earned $12 million in rebates during the year ended December 31, 2021 by achieving the quarterly volumetric target during the fourth quarter of 2021. The following table summarizes the remaining low pressure gathering growth incentive targets for 2022 and 2023. If actual low pressure volumes are below the lowest tier for the respective calendar years, Antero Resources will not receive a fee rebate on low pressure gathering fees.
Low Pressure Gathering | Quarterly Fee | ||||
Volume Growth Incentive | Reduction | ||||
Targets (MMcf/d) | (in millions) | ||||
Calendar Years 2022-2023 | |||||
Threshold 1 | 2,900 and 3,150 | $12.0 | |||
Threshold 2 | 3,150 and 3,400 | $15.5 | |||
Threshold 3 | 3,400 | $19.0 |
Water Handling Services
Pursuant to the water services agreement, we provide certain water handling services to Antero Resources within an area of dedication in defined service areas in Ohio and West Virginia. We also have certain rights of first offer with respect to water services for acreage located outside of the existing dedicated areas. Antero Resources agreed to pay us for all water handling services provided by us in accordance with the terms of the water services agreement, under which Antero Resources has no minimum volume commitments. Under the agreement, Antero Resources will pay a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. Antero Resources also agreed to pay us a fixed fee per barrel for water treatment at the Clearwater Facility, which was idled in the third quarter of 2019 and we expect will remain idled for the foreseeable future. Under the agreement, we receive a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. In addition, we also provide other fluid handling services. These operations, along with our fresh water delivery systems, support well completion and production operations for Antero Resources. These services are provided by us directly or through third-parties with which we contract. For other fluid handling services provided by third-parties, Antero Resources reimburses our third-party out-of-pocket costs plus 3%. For other fluid handling services provided by us, we charge Antero Resources a cost of service fee. The initial term of the water services agreement runs to 2035.
Gas Processing and NGL Fractionation
The Joint Venture was formed in February 2017 to develop processing and fractionation assets in Appalachia. In connection with our entry into the Joint Venture with MarkWest, we released to the Joint Venture our right to provide certain processing and fractionation services on 195,000 gross acres held by Antero Resources in the Appalachian Basin. We have a right-of-first-offer agreement with Antero Resources for the provision of processing and fractionation services pursuant to which Antero Resources, subject to certain exceptions, may not procure any gas processing or NGL fractionation services with respect to its production (other than production subject to a pre-existing dedication) without first offering us the right to provide such services. For additional information, see “—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, 2021, the excluded acreage consisted of approximately 127,000 of Antero Resources’ existing gross leasehold acreage, which included approximately 712 of Antero Resources’ 2,083 potential horizontal well locations. As part of its five-year drilling plan, Antero Resources currently expects to drill all 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 563 MMcf/d on high pressure gathering pipelines and 403 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, cold winters, hot summers or severe weather events can significantly increase demand and price fluctuations, while seasonal anomalies, such as mild winters, mild summers or severe weather events, can sometimes lessen the impact of these fluctuations. In addition, certain natural gas end users, utilities and marketers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall, thereby smoothing demand for natural gas. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for our services during the summer and winter months and decrease demand for our services during the spring and fall months.
Competition
As a result of our relationship with Antero Resources, we do not compete for the portion of Antero Resources’ existing operations for which we currently provide midstream services and will not compete for future portions of Antero Resources’ operations that are dedicated to us pursuant to: (i) our gathering and compression 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, see “—Our Relationship with Antero Resources—Contractual Arrangements with Antero Resources.” However, we face competition in attracting third-party volumes to our gathering and compression and water handling systems. In addition, these third parties may develop their own gathering and compression and water handling systems in lieu of employing our assets.
Regulation of Operations
Regulation of pipeline gathering services may affect certain aspects of our business and the market for our services.
Gathering Pipeline Regulation
Section 1(b) of the Natural Gas Act of 1938 (“NGA”), exempts natural gas gathering facilities from regulation by the FERC, under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of some our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility is not a gathering pipeline and the pipeline provides interstate transmission service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978 (“NGPA”). Such FERC-regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.
Unlike natural gas gathering under the NGA, there is no exemption for the gathering of crude oil or NGLs under the Interstate Commerce Act (“ICA”). Whether a crude oil or NGL shipment is in interstate commerce under the ICA depends on the fixed and persistent intent of the shipper as to the crude oil’s or NGL’s final destination, absent a break in the interstate movement. Antero Midstream believes that the crude oil and NGL pipelines in its gathering system meet the traditional tests the FERC has used to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on Antero Midstream’s crude oil and NGL pipelines depends on the shipper’s intentions and the transportation of the crude oil or NGLs outside of Antero Midstream’s system, and may change over time. If the FERC were to consider the status of an individual facility and the character of a crude oil or NGL shipment, and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by the FERC under the ICA. Such FERC regulation could decrease revenue, increase operating costs and, depending on the facility in question, could adversely affect Antero Midstream’s results of operations and cash 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 2022, FERC issued an order (Order No. 882) 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 $1,388,496 per violation per day.
Pipeline Safety Regulation
Some of our gas pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), with respect to crude oil and NGLs. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020. The NGPSA and HLPSA regulate safety requirements in the design, construction, operation and maintenance of natural gas, crude oil and NGL pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil, NGL and natural gas transmission pipelines in certain high risk areas, such as high-consequence areas (“HCAs”) or moderate consequence areas (“MCAs”).
The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs and MCAs. The regulations require operators, including us, to:
● perform ongoing assessments of pipeline integrity;
● identify and characterize applicable threats to pipeline segments that could impact certain high risk areas;
● improve data collection, integration and analysis;
● repair and remediate pipelines as necessary; and
● implement preventive and mitigating actions.
The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the 2011 Pipeline Safety Act, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. In May 2021, those maximum civil penalties were increased. to $225,134 and $2,251,334, respectively, to account for inflation. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations.
Following legislation enacted by Congress, PHMSA has issued or proposed regulations that either seek to impose new obligations on pipeline operations or expand existing pipeline safety requirements to previously unregulated pipelines. For example, in November 2021, PHMSA issued a final rule that imposes safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities in accordance with the PIPES Act of 2020. PHMSA, together with state regulators, are expected to commence and complete inspection of these plans in 2022. 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.
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PHMSA also continues to work on other rulemakings, though we cannot predict when they will be finalized. For example, 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.
Separately, in the Fiscal Year 2021 Omnibus Appropriations Bill, Congress directed PHMSA to move forward with several regulatory actions, the promulgation of rules related to changes in class location of existing pipelines, pipeline leak detection and repair and the management of idled pipelines, amongst other matters. While we cannot predict the full scope of these regulations at this time, more stringent requirements may require us to incur significant costs to maintain compliance, which may have a negative impact on our business performance and results of operations.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations.
We regularly review all existing and proposed pipeline safety requirements and work to incorporate the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above, consistent with other similarly situated midstream companies. In addition to regulatory changes, costs may be incurred if there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs and corrective action is required.
Regulation of Environmental and Occupational Safety and Health Matters
General
Our natural gas gathering and compression and water handling activities are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment, natural resources and worker safety. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
● requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way we operate resulting in additional costs to our operations;
● limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands, coastal regions or areas inhabited by endangered or threatened species;
● delaying system modification or upgrades during review of permit applications and revisions;
● requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and
● enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or regulatory requirements imposed by such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or solid waste into the environment.
The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our capital costs to
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construct, maintain and operate equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position, results of operations or cash flows, nor do we believe that they will affect our competitive position since the operations of our competitors are generally similarly affected. In addition, we believe that the various activities in which we are presently engaged that are subject to environmental laws and regulations are not expected to materially interrupt or diminish our operational ability to gather natural gas and provide water handling services. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. Our primary customer, Antero Resources, uses the water we deliver to it for hydraulic fracturing as part of its completion operations as does most of the U.S. onshore oil and natural gas industry. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies; however, in recent years the EPA, has asserted limited authority over hydraulic fracturing and has issued or sought to propose rules related to the control of air emissions, disclosure of chemicals used in the process and the disposal of flowback and produced water resulting from the process. Some states, including those in which we operate, have adopted and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. For example, both West Virginia and Ohio have adopted requirements governing well pad construction, as well as requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drilling baseline water quality sampling of certain water wells near a proposed horizontal well. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. We cannot predict whether any such federal, state or local legal restrictions relating to the hydraulic fracturing process will ever be enacted in areas where our customers operate and if so, what the effects of such restrictions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal state or local level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of water and natural gas that move through our systems, which in turn could materially adversely affect our revenues and results of operations.
Hazardous Waste
Antero Midstream and Antero Resources’ operations generate solid wastes, including small quantities of hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many oil and natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development or production of crude oil and natural gas, including residual constituents derived from those exempt wastes. However, these oil and gas exploration and 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 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
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cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.
We currently own or lease, and may have in the past owned or leased, properties that have been used for the gathering and compression of natural gas and the gathering and transportation of oil. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by it or on or under other locations where such substances have been taken for disposal. Such petroleum hydrocarbons or wastes may have migrated to property adjacent to our owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial operations to prevent future contamination. We are not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at or implicating our facilities or operations.
Air Emissions
The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various emission limits, operational limits and monitoring, reporting and recordkeeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations and potentially criminal enforcement actions. These laws are frequently subject to change. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, for ozone from 75 to 70 parts per billion, and completed attainment/non-attainment designations in July 2018. Subsequently, in 2020, the Trump Administration decided to leave this standard in place, but the Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard. These decisions are subject to legal challenge, and any proposed rule will likely be subject to legal challenge as well. Several EPA new source performance standards (“NSPS”), and national emission standards for hazardous air pollutants (“NESHAP”), also apply to our facilities and operations. These NSPS and NESHAP standards impose emission limits and operational limits as well as detailed testing, recordkeeping and reporting requirements on the “affected facilities” covered by these regulations. Several of our facilities are “major” facilities requiring Title V operating permits which impose semi-annual reporting requirements.
Water Discharges
The Federal Water Pollution Control Act (the “FWPCA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. The scope of regulated waters has been subject to substantial controversy. In 2015 and 2020, respectively, the Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over waters of the United States (“WOTUS”). However, both of these rulemakings have been subject to legal challenge, and the Biden administration has announced plans to establish its own definition of WOTUS. Most recently, the EPA and Corps published a proposed rulemaking to revoke the 2020 rule in favor of a pre-2015 definition until a new definition is proposed, which the Biden Administration has announced is underway. Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the FWPCA and the definition of WOTUS. As a result of these developments, the scope of jurisdiction under the FWPCA is uncertain at this time. To the extent any rule expands the scope of the FWPCA’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 FWPCA Section 404 Nationwide Permit (“NWP”) 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court’s order has subsequently been limited to the particular pipeline in that case pending appeal, we cannot predict the ultimate outcome of this case and its impacts to the NWP program. Relatedly, in response to the vacatur, the Corps reissued NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, an October 2021 decision by the District Court for the Northern District of California resulted in a vacatur of a 2020 rule revising the FWPCA Section 401 certification process. Several NWPs, including the revised NWP 12, rely on Section 401 certifications or waivers under the vacated rule. This initially led the Corps to halt the permitting decisions for such NWPs. While the
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Corps has resumed permitting decisions for such NWPs, the Corps has advised that, as part of the permitting decision process, the Corps will coordinate with certifying authorities on Section 401 certifications as needed, which may result in permit delays or otherwise impact our operations. Litigation regarding the use of NWP 12 is ongoing. While the full extent and impact of these vacaturs is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and regulations provide for administrative, civil and criminal penalties for any discharges not authorized by the permit and may impose substantial potential liability for the costs of removal, remediation and damages. We believe that compliance with such permits will not have a material adverse effect on our business operations.
Occupational Safety and Health Act
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We do not believe that any noncompliance with worker health and safety requirements has occurred or will have a material adverse effect on our business or operations.
Endangered Species
The federal Endangered Species Act (“ESA”), provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations and have pipeline construction and maintenance projects in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (the “USFWS”), may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Moreover, as a result of a settlement, the USFWS was required to make a determination as to whether more than 250 species classified as endangered or threatened should be listed under the ESA by the completion of the agency’s 2017 fiscal year. For example, in April 2015, the USFWS listed the northern long-eared bat, whose habitat includes the areas in which we operate, as a threatened species under the ESA; however, 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, and in March 2021, the same court ordered USFWS to make a determination by December 2022 whether a listing as endangered is warranted. 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 GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”), pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources that are already potential major sources of criteria pollutant emissions regulated under the statute. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for their GHG emissions established by the states or, in some cases, by the EPA, for those emissions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years. In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that set emissions standards for methane and volatile organic compounds (“VOC”) from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified and
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existing oil and gas facilities. Subsequently, Congress approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will require approval by the EPA through individual rulemakings that could also be subject to legal challenge. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. These rules (and any additional regulations) could impose new compliance costs and permitting burdens on natural gas operations.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted that addressing climate change is a priority of his administration. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry and increased emphasis on climate-related risks across agencies and economic sectors. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. Internationally, the Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years beginning in 2020. President Biden recommitted the United States to the Paris Agreement in February 2021, and in April 2021, established a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Additionally, in November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” an initiative committing to a collective goal of reducing global methane emissions by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.
Since 2017, we have published an annual ESG Report, which highlights our most significant environmental program improvements and initiatives. As highlighted in our ESG Report, our methane leak loss rate in 2020 was 0.015%, which was calculated in accordance with OneFuture, a voluntary industry partnership focused on reducing methane emissions from the natural gas sector, well below the OneFuture voluntary industry target of 1%.
During 2021, our GHG/methane emission reduction efforts included the following activities:
| 1) | Established an ESG Advisory Council comprised of a cross-disciplinary group of internal subject matter experts to partner with our GHG/Methane Reduction Team to manage ESG (including climate change) risks, opportunities and strategies. |
| 2) | Held quarterly meetings with the GHG/Methane Reduction team to review emerging methane detection and quantification technologies applicable to midstream operations. |
| 3) | Conducted quarterly facility LDAR inspections on 100% of our compressor stations. |
| 4) | Installed pigging blowdown capture systems at three locations including one pipeline interchange and two compressor stations. |
| 5) | Commenced field pilot test with major engine manufacturer to reduce emissions while increasing horsepower. |
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| 6) | Installed continuous monitoring technology over a tank farm at one of our compressor stations to identify and correct leaks that may occur between forward-looking infrared inspections. |
We continue to assess various opportunities for emission reductions. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe or across all operational assets, or their ultimate effectiveness. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2021. However, we cannot guarantee that we will not incur material costs related to compliance with or liability under environmental laws and regulations in the future. For risks and uncertainties related to ESG matters, see “Item 1A. Risk Factors—Compliance with Regulations—Increasing attention to ESG matters and conservation measures may adversely impact our business.”
Increasingly, fossil fuel companies are exposed to litigation risks from climate change. A number of parties have brought suits against fossil fuel companies in state or federal court for alleged contributions to, or failures to disclose the impacts of, climate change. While we are not currently party to any such litigation, we could be named in future actions making similar claims of liability. Moreover, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
Additionally, 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. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, the Federal Reserve has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. 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. In addition, the SEC has announced that it will promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, and we cannot predict what any such rules may require to the extent the rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient.
Moreover, climate change may also result in various physical risks such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our financial condition and operations, as well as those of our suppliers or customers. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our services, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure on which we rely to provide our services. One or more of these developments could have a material adverse effect on our business, financial condition and operations.
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.
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Human Capital
We believe that our employees and contractors are significant contributors to our past and future success, which depends on our ability to attract, retain and motivate qualified personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance.
All of our executive officers and other personnel who provide corporate, general and administrative services to our business are, when providing services to us, concurrently employed by Antero Resources and us pursuant to the terms of a services agreement. In addition, our operational personnel are seconded to us by Antero Resources pursuant to the terms of a secondment agreement and individuals are concurrently employed by Antero Resources and us during such secondment. As of December 31, 2021, approximately 519 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:
| ● | comprehensive health insurance, including vision and dental; we have not increased employee premiums in over 15 years; |
| ● | employee Health Savings Accounts, including contributions to these accounts by us; |
| ● | 401(k) retirement savings plan with discretionary contribution matching opportunities; |
| ● | competitive paid time off and sick leave programs; and |
| ● | wellness support benefits including an employee assistance program and short-term and long-term disability coverage, among others. |
Role Based Support
We support our employees’ professional development. To help our personnel succeed in their roles, we emphasize continuous formal and informal training 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. We
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continue to monitor the COVID-19 environment in order to (i) protect the health and safety of our employees and contract workers and (ii) determine when a return to in-office working arrangements will be appropriate.
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 advancement that considers the value of diversity, and we are also committed to making opportunities for development and progress available to all employees so their talents can be fully developed to maximize our and their success. We believe that creating an environment that cultivates a sense of belonging requires encouraging employees to continue to educate themselves about each other’s experiences, and we strive to promote the respect and dignity of all persons. We also believe it is important that we foster education, communication and understanding about diversity, inclusion and belonging. Finally, in line with our commitments to equal employment opportunity and diversity and inclusion, we expect recruiters operating on our behalf to provide us with a diverse pool of candidates.
Address, Internet Website and Availability of Public Filings
Our principal executive offices are at 1615 Wynkoop Street, Denver, Colorado 80202. Our telephone number is (303) 357-7310. Our website is located at www.anteromidstream.com.
We file or furnish our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.
We also make available free of charge our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. These documents are located www.anteromidstream.com under the “Investors” link.
Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.
Item 1A. Risk Factors
We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks described in this Annual Report on Form 10-K could materially and adversely affect our business, financial condition, cash flows and results of operations. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.
Customer Concentration
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:
| ● | a reduction in or slowing of Antero Resources’ development program, which would directly and adversely impact demand for our gathering and compression services and our water handling services; |
| ● | a reduction in or slowing of Antero Resources’ well completions, which would directly and adversely impact demand for our water handling services; |
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| ● | the volatility of natural gas, NGLs and oil prices, which could have a negative effect on the value of Antero Resources’ properties, its development program and its ability to finance its operations; |
| ● | the availability of capital on an economic basis to fund Antero Resources’ exploration and development activities and to service and/or refinance its debt, as well as to fund its capital expenditure programs; |
| ● | Antero Resources’ ability to replace its oil and gas reserves; |
| ● | Antero Resources’ drilling and operating risks, including potential environmental liabilities; |
| ● | transportation and processing capacity constraints and interruptions; and |
| ● | adverse effects of governmental and environmental regulation. |
Further, we are subject to the risk of non-payment or non-performance by Antero Resources, including with respect to our gathering and compression and water handling services agreements. We cannot predict the extent to which Antero Resources’ business would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on Antero Resources’ ability to execute its drilling and development program or perform under our gathering and compression and water handling services agreements. Low commodity price environments can negatively impact natural gas producers and cause the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts, as experienced during the year ended December 31, 2020. To the extent that any customer, including Antero Resources, is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by Antero Resources could adversely affect our business and operating results.
Also, due to our relationship with Antero Resources, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to Antero Resources’ financial condition or adverse changes in its credit ratings.
Any material limitation of our ability to access capital could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Antero Resources could negatively impact our share price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
See Item 1A, “Risk Factors” in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, 2021 (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
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delivery services, which make up a substantial portion of our water handling services revenues, is dependent on water used in Antero Resources’ completion activities. To the extent that Antero Resources or other fresh water delivery customers reduce the number of completion stages per well or use less water in their completions, the demand for our fresh water delivery services would be reduced.
We have no control over Antero Resources’ or other producers’ levels of development and completion activity in our areas of operation, the amount of oil and gas reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, our water handling business is dependent upon active development in our areas of operation. To maintain or increase throughput levels on our water handling systems, we must service new wells. We have no control over Antero Resources or other producers or their development plan decisions, which are affected by, among other things:
| ● | the availability and cost of capital; |
| ● | prevailing and projected natural gas, NGLs and oil prices; |
| ● | demand for natural gas, NGLs and oil; |
| ● | quantities of reserves; |
| ● | geologic considerations; |
| ● | environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and |
| ● | the costs of producing the gas and the availability and costs of drilling rigs and other equipment. |
The daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu in 2021, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $85.64 per barrel to a low of $47.47 per barrel during the same period. While oil and natural gas prices were generally higher in 2021 than they were in 2020, the markets for these commodities have historically been volatile, and these markets will likely continue to be volatile in the future. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Appalachian region in recent years. Because Antero Resources’ production and reserves predominantly consist of natural gas (approximately 58% of equivalent proved reserves), changes in natural gas prices have significantly greater impact on Antero Resources’ financial results than oil prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, oil and NGLs at Antero Resources’ ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.
The lower prices experienced during 2020 together with an industry shift towards maintenance capital development programs compelled most natural gas and oil producers, including Antero Resources, to reduce the level of exploration, drilling and production activity and capital budgets compared to previous years. For example, Antero Resources’ 2022 capital budget is $740 million to $775 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 decrease from current levels, our revenues, cash flows and results of operations could continue to be adversely affected. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services and cash flows.
Due to these and other factors, even if reserves are known to exist in areas served by our assets, producers have chosen and may choose in the future, not to develop those reserves. Reductions in development activity, including Antero Resources’ reduction in lateral lengths or use of water in its completions, could result in our inability to maintain the current levels of throughput on our systems or reduce the demand for our water handling services on a per well basis, which could in turn reduce our revenue and cash flows and adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of our common stock.
Finally, 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
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effective dates of the agreements, does not exceed the aggregate number of net acres of dedicated properties acquired by Antero Resources since such effective dates. Accordingly, under certain circumstances, Antero Resources may dispose of a significant number of net acres of dedicated properties free from dedication without our consent, and we have no control over the timing or extent of such dispositions. Any such dispositions could adversely affect our business and operating results. Even if the disposed property remains dedicated to us, the goals and intention of the acquiror with respect to such property may differ significantly from those of Antero Resources. For example, a subsequent owner of a property could choose to invest less capital in the development of such property or to otherwise drill fewer wells than Antero Resources. There can be no assurance that a subsequent owner of dedicated properties would choose to, or be able to, grow or maintain current rates of production from the properties, which could adversely impact us.
Business Operations
A material shut-in of production by Antero Resources or any of our other customers could adversely affect our business.
The marketing of the natural gas, NGLs and oil of our producer customers is substantially dependent upon the existence of adequate markets for their products. In response to the COVID-19 pandemic, governments tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which caused a significant decrease in the demand for oil, natural gas and NGLs. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, caused extreme market volatility and a substantial adverse effect on commodity prices. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs, and related commodity pricing, has improved. The extent to which the pandemic will impact our business results and operations remains uncertain in light of the rapidly evolving environment, duration and severity of the spread of the virus, and emerging variants, effectiveness of the vaccine and booster shots, public acceptance of safety protocols, and government measures, including vaccine mandates, designed to slow and contain the spread of COVID-19, among others. Also as a result of this imbalance, the industry has experienced and may experience in the future storage capacity constraints with respect to oil and certain NGL products. If Antero Resources or any of our other customers are unable to sell their production or enter into additional storage arrangements on commercially reasonable terms or at all, they may be forced to temporarily shut-in a portion of their production or delay or discontinue drilling and completion plans and commercial production. Although Antero Resources has not been required to temporarily shut-in a portion of its production, it may do so in the future. Production curtailments or shut-ins by our producer customers will reduce volumes flowing through our gathering and processing system. In addition, if our customers delay or discontinue drilling or completion activities, it will reduce the volumes of water that we handle. A material reduction in volumes on our systems could adversely affect our business, revenue and cash flows and could adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of AM common stock.
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 water distribution pipelines. Any decrease in the current levels of throughput on our gathering, compression and 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,
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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 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,
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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.
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.
As the rate of inflation has increased in the U.S., the cost of the goods and services and labor we use in our operations has also increased, increasing our operating costs. Our costs may increase at a rate greater than the fees we charge to our customers. Furthermore, Antero Resources and our other customers may not renew their contracts with us, or may from time to time seek to renegotiate with us the amount and/or the structure of fees we charge. Additionally, some of our customers’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are curtailed or cut-off due to events beyond our control, and in some cases, certain of those agreements may be terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of fees is insufficient to cover increased costs, our customers do not renew or extend their contracts with us, or our customers suspend or terminate their contracts with us, our financial results would suffer.
Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water.
Our business includes fresh water delivery for use in our customers’ natural gas, NGL and oil exploration and production activities. Water is an essential component of natural gas, NGL and oil production during the drilling, and in particular, the hydraulic fracturing process. We derive a significant portion of our revenues from providing fresh water to Antero Resources. Antero Resources implemented efficiency improvements and water initiatives during 2020, which reduced the amount of fresh water needed to complete their operations. Furthermore, the availability of water supply for our operations may be limited due to, among other things, prolonged drought or state and local governmental authorities restricting the use of water for hydraulic fracturing. The availability of water may also change over time in ways that we cannot control, including as a result of climate change-related effects such as shifting meteorological and hydrological patterns. Any decrease in the demand for water handling services, or the water supply we need to provide such services, would adversely affect our business and results of operations.
Increasing attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy, may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our customers, including Antero Resources. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long
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timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets, including our goals to achieve a 100% reduction in pipeline emissions by 2025 and to achieve net zero Scope 1 (direct) and Scope 2 (indirect from the purchase of energy) emissions by 2050, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, given uncertainties related to the use of emerging technologies, the state of markets for and the availability of verified carbon offsets, we cannot predict whether or not we will be able to timely meet these goals, if at all. Also, despite these aspirational goals, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us, Antero Resources and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may decide not to provide funding for 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. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact Antero Resources and our customers, which may adversely impact our business, financial condition or results of operations.
Our 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 processing, gathering and compression of natural gas, NGLs and oil and water handling services, including:
| ● | unintended breach of impoundment and downstream flooding, release of invasive species or aquatic pathogens, hazardous spills near intake points, trucking collision, vandalism, excessive road damage or bridge collapse and unauthorized access or use of automation controls; |
| ● | damage to pipelines, compressor stations, pumping stations, blending facilities, impoundments, related equipment and surrounding properties caused by natural disasters, acts of terrorism and acts of third parties; |
| ● | damage from construction, farm and utility equipment as well as other subsurface activity (for example, mine subsidence); |
| ● | leaks of natural gas, NGLs or oil or losses of natural gas, NGLs or oil as a result of the malfunction of equipment or facilities; |
| ● | fires, ruptures and explosions; |
| ● | other hazards that could also result in personal injury and loss of life, pollution of the environment, including natural resources and suspension of operations; and |
| ● | hazards experienced by other operators that may affect our operations by instigating increased regulations and oversight. |
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
| ● | injury or loss of life; |
| ● | damage to and destruction of property, natural resources and equipment; |
| ● | pollution and other environmental damage; |
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| ● | regulatory investigations and penalties; |
| ● | suspension of our operations; and |
| ● | repair and remediation costs. |
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable under policies we are covered under, and we have obtained pollution insurance. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
Because we do not own all of the land on which our pipelines and facilities have been constructed, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations.
A pandemic, epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.
The global or national outbreak of an infectious disease, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, to address the COVID-19 pandemic and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. While it is not possible to predict their extent or durations, these disruptions may have a material adverse effect on our business, financial condition and results of operations and could adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of AM common stock.
Further, adverse impacts on Antero Resources’ business resulting from any such outbreak may also adversely affect our business and results of operations. For example, the effects of COVID-19 and concerns regarding its global spread have negatively impacted global demand for crude oil and natural gas, which could continue to contribute to price volatility impacting the price Antero Resources receives for its natural gas, NGLs and oil. In addition, COVID-19 could continue to materially and adversely affect the demand for and marketability of natural gas, NGLs and oil production and production levels. Although Antero Resources has not been required to curtail or shut-in a portion of its production, it may do so in the future. For further discussion of the business risks of Antero Resources that may impact us, see “—Customer Concentration—Because substantially all of our revenue is currently derived from Antero Resources, any development that materially and adversely affects Antero Resources’ operations, financial condition or market reputation could have a material and adverse impact on us,” the effects of which may be heightened to the extent the COVID-19 pandemic adversely affects our business and financial results.
Terrorist attacks, cyberattacks and threats could have a material adverse effect on our business, financial condition and results of operations.
Terrorist attacks or cyberattacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. We depend on digital technology in many areas of our business and operations, including, but not limited to, performing many of our gathering and compression and water handling services, recording financial and operating data, oversight and analysis of our operations and communications with the employees supporting our operations and our customers or service providers. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. The secure processing, maintenance and transmission of information is critical to our operations, and we monitor our key information technology systems in an effort to detect and prevent cyberattacks, security breaches or unauthorized access. Despite our security measures, our information technology systems may undergo cyberattacks or security breaches including as a result of employee error, malfeasance or other threat vectors, which could lead to the corruption or loss of our proprietary and potentially sensitive data, delays in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records,
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environmental damage, communication interruptions or other operational disruptions and third-party liabilities. Moreover, we may not be able to anticipate, detect or prevent all cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until such attack is underway, and because attackers are increasingly using technologies specifically designed to circumvent cybersecurity measures and avoid detection. Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.
As cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. A cyberattack or security breach could result in liability under data privacy laws, regulatory penalties, damage to our reputation or a loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations. To date, we have not experienced any material losses relating to cyberattacks; however, there can be no assurance that we will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Capital Structure and Access to Capital
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 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.
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We may be unable to access the equity or debt capital markets to meet our obligations.
Declines in commodity prices or the financial condition or prospects of Antero Resources may cause the financial markets to exert downward pressure on our stock price and credit capacity. For example, for portions of 2020, the market for senior unsecured notes was unfavorable for high-yield issuers such as us. Our plans for growth may require access to the capital and credit markets. Although the market for high-yield debt securities improved in 2021 as compared to 2020, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms or at all, we may be unable to carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
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:
| ● | incur or guarantee additional debt; |
| ● | redeem or repurchase units or make distributions under certain circumstances; |
| ● | make certain investments; |
| ● | enter into mergers; |
| ● | incur certain liens or permit them to exist; |
| ● | enter into certain types of transactions with affiliates; |
| ● | merge or consolidate with another company; and |
| ● | transfer, sell or otherwise dispose of assets. |
The indentures governing our senior notes contains similar restrictive covenants. In addition, our revolving credit facility contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratio or test. Additionally, we may not be able to borrow the full amount of commitments under our revolving credit facility if doing so would cause us to breach a financial covenant.
The provisions of our revolving credit facility and the indentures governing our senior notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility or the indentures governing our senior notes could result in a default or an event of default that could enable our lenders or noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If our obligations to repay our debt are accelerated, our assets may be insufficient to repay such debt in full, and you could experience a partial or total loss of your investment. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
| ● | our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to our gathering and compression agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms; |
| ● | our funds available for operations and future business opportunities will be reduced by that portion of our cash flows required to make interest payments on our debt; |
| ● | we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
| ● | our flexibility in responding to changing business and economic conditions may be limited. |
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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 2021, we had average outstanding borrowings under our revolving credit facility of approximately $560 million, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of approximately $6 million and a corresponding decrease in our cash flows and net income before the effects of income taxes. Disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to carry out our business plan.
Geographic Concentration
Our gathering and compression and water handling systems are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.
We rely primarily on revenues generated from our gathering and compression and water handling systems, which are all located in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by, and associated with, governmental regulation, state and local political activities, market limitations, availability of equipment and personnel or interruption of the compression, processing or transportation of natural gas, NGLs or oil.
A shortage of equipment and skilled labor in the Appalachian Basin could reduce equipment availability and labor productivity and increase labor costs, which could have a material adverse effect on our business and results of operations.
Gathering and compression and water handling services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If Antero Resources experiences shortages of skilled labor or there is a lack of necessary equipment in the Appalachian Basin in the future, our allocation of labor costs and overall productivity could be materially and adversely affected. If our allocation of labor prices increase or if Antero Resources experiences materially increased health and benefit costs for employees, our business and results of operations could be materially and adversely affected.
Acquisitions and Takeovers
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future, we may acquire businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to successfully integrate the acquired businesses and assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, financial condition and results of operations.
In addition, our agreements governing our debt impose certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility and the indentures governing our senior notes also limit our ability to incur certain
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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:
| ● | provide advance notice procedures with regard to stockholder nominations of candidates for election as directors or other stockholder proposals to be brought before meetings of our stockholders, which may preclude our stockholders from bringing certain matters before our stockholders at an annual or special meeting; |
| ● | provide our Board of Directors (the “Board”) the ability to authorize issuance of preferred stock in one or more classes or series, which makes it possible for our Board to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us and which may have the effect of deterring hostile takeovers or delaying changes in control or management of us; |
| ● | provide that the authorized number of directors may be changed only by resolution of our Board; |
| ● | provide that, subject to the rights of holders of any series of preferred stock to elect directors or fill vacancies in respect of such directors as specified in the related preferred stock designation and the terms of that certain Stockholders’ Agreement, dated October 9, 2018, by and among Antero Midstream Corporation and certain of its stockholders named thereto (the “Stockholders’ Agreement”), all vacancies, including newly created directorships be filled by the affirmative vote of holders of a majority of directors then in office, even if less than a quorum, or by the sole remaining director, and will not be filled by our stockholders; |
| ● | provide that, subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, if any, and the terms of the Stockholders’ Agreement, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of our stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders; |
| ● | provide for our Board to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms; |
| ● | provide that, subject to the rights of the holders of shares of any series of preferred stock, if any, to remove directors elected by such series of preferred stock pursuant to our certificate of incorporation (including any preferred stock designation thereunder) and the terms of the Stockholders’ Agreement, directors may be removed from office at any time, only for cause and by the holders of a majority of the voting power of all outstanding voting shares entitled to vote generally in the election of directors; |
| ● | provide that special meetings of our stockholders may only be called by the Chief Executive Officer, the Chairman of our Board or our Board pursuant to a resolution adopted by a majority of the total number of directors that we would have if there were no vacancies; |
| ● | provide that (i) Yorktown Partners LLC (“Yorktown”) and their affiliates are permitted to participate (directly or indirectly) in venture capital and other direct investments in corporations, joint ventures, limited liability companies and other entities conducting business of any kind, nature or description, (ii) Yorktown and their affiliates are permitted to have interests in, participate with, aid and maintain seats on the boards of directors or similar governing bodies of any such investments, in each case that may, are or will be competitive with our business and the business of our subsidiaries or in the same or similar lines of business as us and our subsidiaries, or that could be suitable for us or our subsidiaries and (iii) we have, subject to limited exceptions, renounced, to the fullest extent permitted by law, any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities; |
| ● | provide that the provisions of our certificate of incorporation can only be amended or repealed by the affirmative vote of the holders of at least 66 2/3% in voting power of the outstanding shares of our common stock entitled to vote thereon, voting together as a single class; provided, however, that so long as the Stockholders' Agreement remains in effect, no provision of our certificate of incorporation may be amended, altered or repealed in any manner that would be contrary |
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| to or inconsistent with the terms of the Stockholders’ Agreement, and no amendment to the Stockholders’ Agreement (regardless of whether such amendment modifies any provision of the Stockholders’ Agreement to which our certificate of incorporation is subject) will be deemed an amendment of our certificate of incorporation; and |
| ● | provide that our bylaws can be altered or repealed by (a) our Board or (b) our stockholders upon the affirmative vote of holders of at least 66 2/3% of the voting power of our common stock outstanding and entitled to vote thereon, voting together as a single class. However, so long as the Stockholders’ Agreement remains in effect, our Board may not approve any amendment, alteration or repeal of any provision of our bylaws or the adoption of any new bylaw, that (a) would be contrary to or inconsistent with the terms of the Stockholders’ Agreement or (b) would amend, alter or repeal certain portions of our certificate of incorporation; provided, however, that so long as the Stockholders’ Agreement remains in effect, the parties to the Stockholders' Agreement may amend any provision of the Stockholders’ Agreement, and no amendment to the Stockholders’ Agreement (regardless of whether such amendment modifies any provision of the Stockholders’ Agreement to which the bylaws are subject) will be deemed an amendment of the bylaws for purposes of the amendment provisions of our bylaws. |
We have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”), regulating corporate takeovers.
In general, the provisions of Section 203 of the DGCL prohibit a Delaware corporation, including those whose securities are listed for trading on the New York Stock Exchange, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:
| ● | prior to such time, the business combination or the transaction which resulted in the stockholder becoming an interested stockholder is approved by our Board; |
| ● | upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding certain specified shares); or |
| ● | on or after such time the business combination is approved by our Board and authorized at a meeting of stockholders by the holders of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder. |
Section 203 of the DGCL permits a Delaware corporation to elect not to be governed by the provisions of Section 203. Pursuant to our certificate of incorporation, we expressly elected not to be governed by Section 203. Accordingly, we are not subject to any anti-takeover effects or protections of Section 203 of the DGCL, although no assurance can be given that we will not elect to be governed by Section 203 of the DGCL pursuant to an amendment to our certificate of incorporation in the future.
Joint Ventures
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.
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In addition, the Joint Venture may result in other difficulties including, among other things:
| ● | diversion of our management’s attention from other business concerns; |
| ● | managing regulatory compliance and corporate governance matters; |
| ● | an increase in our indebtedness; and |
| ● | potential environmental or other regulatory compliance matters or liabilities and/or title issues, including certain liabilities arising from the operation of the Joint Venture assets prior to the closing of the Joint Venture. |
Interruptions in operations at any of the Joint Venture’s facilities may adversely affect its operations and our gathering and processing and water handling operations.
The Joint Venture assets consist of processing plants in West Virginia and a one-third interest in two fractionators in Ohio (the “MarkWest fractionators”). Any significant interruption at these facilities would adversely affect the Joint Venture’s operations. Because a significant portion of Antero Resources’ production is processed by the Joint Venture, any significant interruption at these facilities would also adversely affect our other midstream operations.
We do not operate the MarkWest fractionators, and the operations of the MarkWest’s and Joint Venture’s processing facilities and the MarkWest fractionators could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within its control, such as:
| ● | unscheduled turnarounds or catastrophic events, including damages to facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters; |
| ● | restrictions imposed by governmental authorities or court proceedings; |
| ● | labor difficulties that result in a work stoppage or slowdown; |
| ● | a disruption in the supply of gas to MarkWest’s or the Joint Venture’s processing and fractionation plants and associated facilities; |
| ● | disruption in the supply of power, water and other resources necessary to operate MarkWest’s or the Joint Venture’s facilities; |
| ● | damage to MarkWest’s or the Joint Venture’s facilities resulting from gas that does not comply with applicable specifications; and |
| ● | inadequate fractionation capacity or market access to support production volumes, including lack of availability of rail cars, barges, pipeline capacity or market constraints, including reduced demand or limited markets for certain NGL products. |
In addition, MarkWest’s fractionation operations in the Appalachian Basin are integrated, and as a result, it is possible that an interruption of these operations in other regions may impact operations in the regions in which the Joint Venture’s facilities are located.
Compliance with Regulations
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
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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 (“CWA”) Section 404 NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court’s order has subsequently been limited to the particular pipeline in that case pending appeal, we cannot predict the ultimate outcome of this case and its impacts to the NWP program. Relatedly, in response to the vacatur, the Corps reissued NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, an October 2021 decision by the District Court for the Northern District of California resulted in a vacatur of a 2020 rule revising the CWA Section 401 certification process. Several NWPs, including the revised NWP 12, rely on Section 401 certifications or waivers under the vacated rule. This initially led the Corps to halt the permitting decisions for such NWPs. While the Corps has resumed permitting decisions for such NWPs, the Corps has advised that, as part of the permitting decision process, the Corps will coordinate with certifying authorities on Section 401 certifications as needed, which may result in permit delays or otherwise impact our operations. While the full extent and impact of these vacaturs is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. This in turn could have an adverse effect on our business, financial condition and results of operation. Separately, the definition of WOTUS has been subject to substantial controversy. In 2015 and 2020, respectively, the Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over WOTUS. However, both of these rulemakings have been subject to legal challenge, and the Biden administration has announced plans to establish its own definition of WOTUS. Most recently, the EPA and Corps published a proposed rulemaking to revoke the 2020 rule in favor of a pre-2015 definition until a new definition is proposed, which the Biden Administration has announced is underway. Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the CWA and the definition of WOTUS. As a result, the scope of the CWA’s jurisdiction is uncertain at this time. To the extent any 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 effect on our business, financial condition and results of operations. Further, any discharges of natural gas, NGLs, oil and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See “Item 1. Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.
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
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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 $1,388,496 per day for each violation and disgorgement of profits associated with any violation.
For more information regarding federal and state regulation of our operations, see “Business—Regulation of Operations.”
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 over certain hydraulic fracturing activities. For example, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. New legislation regulating hydraulic fracturing may be considered again in future, though we cannot predict when or the scope of any such legislation at this time. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, both West Virginia and Ohio have adopted requirements governing well pad construction, as well as requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drilling baseline water quality sampling of certain water wells near a proposed horizontal well. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.
We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal, state or local level, that could lead to delays, increased operating costs and process prohibitions that could reduce the amount of natural gas that moves through our gathering and processing systems or reduce the number of wells drilled and completed that require fresh water for hydraulic fracturing activities, which in turn could materially and adversely affect our revenues and results of operations.
We or any third-party customers may incur significant liability under, or costs and expenditures to comply with, environmental and occupational health and workplace safety regulations, which are complex and subject to frequent change.
As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state, provincial and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose various obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for
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personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability. For example, President Biden has made action on environmental matters, and climate change in particular, a focus of his administration, and our operations and those of our clients, may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and GHG emissions.
Our operations also pose risks of environmental liability due to potential leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations is expected to continue, which may result in increased costs of doing business and consequently affecting profitability. See “Business—Regulation of Environmental and Occupational Safety and Health Matters” for more information.
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 EPA has adopted regulations under existing provisions of the federal CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.
The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years. In June 2016, the EPA finalized NSPS, known as Subpart OOOOa, that established emission standards for methane and VOCs from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified and existing oil and gas facilities. Subsequently, the U.S. Congress approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will require approval by the EPA through individual rulemakings that could also be subject to legal challenge. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry
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remain a possibility, and several states, including West Virginia and Ohio, have separately imposed their own regulations on methane emissions from oil and gas production activities.
Internationally, the Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years beginning 2020. President Biden recommitted the United States to the Paris Agreement in February 2021 and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Additionally, in November 2021, the international community gathered again in Glasgow COP26, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” an initiative committing to a collective goal of reducing global methane pollution by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.
Concern over the threat of climate change has also resulted in increasing political risks in the United States, including climate-change related pledges made by President Biden and other public office representatives. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry and increased emphasis on climate-related risks across agencies and economic sectors. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide. Other actions that could be pursued by the Biden administration include more restrictive requirements for the development of pipeline infrastructure or LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities.
Increasingly, fossil fuel companies are also exposed to litigation risks from climate change. A number of parties have brought suits against fossil fuel companies in state or federal court for alleged contributions to, or failures to disclose the impacts of, climate change. While we are not currently party to any such litigation, we could be named in future actions making similar claims of liability. Moreover, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
Additionally, in response to concerns related to climate change, companies in the 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. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. In addition, at COP26, GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. The Federal Reserve has joined the NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. 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. In addition, the SEC has announced that it will promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, and we cannot predict what any such rules may require to the extent the rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also announced that is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for the services we provide. One or more of these developments could
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have a material adverse effect on our business, financial condition and results of operation.
Moreover, climate change may also result in various physical risks such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our financial condition and operations, as well as those of our suppliers or customers. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our services, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure on which we rely to provide our services. One or more of these developments could have a material adverse effect on our business, financial condition and operations. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in HCAs or MCAs. The regulations require operators to:
| ● | perform ongoing assessments of pipeline integrity; |
| ● | identify and characterize applicable threats to pipeline segments that could impact certain high risk areas; |
| ● | improve data collection, integration and analysis; |
| ● | repair and remediate the pipeline as necessary; and |
| ● | implement preventive and mitigating actions. |
The 2011 Pipeline Safety Act among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the 2011 Pipeline Safety Act, the PHMSA, finalized rules that increased the maximum administrative civil penalties for violations of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. In May 2021, those maximum civil penalties were increased to $225,134 and $2,251,334, respectively, to account for inflation. Should our operations fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.
Following legislation enacted by Congress, PHMSA has issued or proposed regulations that either seek to impose new obligations on pipeline operations or expand existing pipeline safety requirements to previously unregulated pipelines. For example, in November 2021, PHMSA issued a final rule that imposes safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities, in accordance with the PIPES Act of 2020. PHMSA, together with state regulators, are expected to commence and complete inspection of these plans in 2022. 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 also continues to work on other rulemakings, though we cannot predict when they will be finalized. For example, 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. Separately, in the Fiscal Year 2021 Omnibus Appropriations Bill, Congress directed PHMSA to move forward with several regulatory actions, the promulgation of rules related to changes in class location of existing pipelines, pipeline leak detection and repair and the management of idled pipelines, amongst other matters. While we cannot predict the full scope of these regulations at this time, more stringent requirements may require us to incur significant costs to maintain compliance, which may have a negative impact on our business
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performance and results of operations.
The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant, consistent with other similarly situated midstream companies. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow. See “Business—Pipeline Safety Regulation” for more information.
Regulations related to the protection of wildlife could adversely affect our ability to conduct oil and gas operations in some of the areas where we operate.
Oil and gas operations in our operating areas can be adversely affected by regulations designed to protect various wildlife. For example, 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 operate could cause us to incur increased costs arising from species protection measures, result in constraints on our customer’s exploration and production activities and on our pipeline construction and operation activities. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations or the operations of our customers and materially increase our operating and capital costs.
Human Capital
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of a relatively small group of senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including Paul M. Rady, Chairman, President and Chief Executive Officer, could have a material adverse effect on our business, financial condition and results of operations.
Our officers and employees provide services to both Antero Resources and us.
All of our executive officers and certain other personnel who provide corporate, general and administrative services to our business are, when providing services to us, concurrently employed by Antero Resources and us pursuant to the terms of a services agreement. In addition, our operational personnel are seconded to us by Antero Resources pursuant to the terms of a secondment agreement and are concurrently employed by Antero Resources and us during such secondment. As a result, there could be material competition for the time and effort of the officers and employees who provide services to Antero Resources and us. If such officers and employees do not devote sufficient attention to the management and operation of our business, our financial results may suffer.
Related Parties
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, 2021, Antero Resources beneficially owned 29.1% of our outstanding common stock. Conflicts of interest will arise between Antero Resources and us. Our directors and officers who are also directors and officers of Antero Resources have a fiduciary duty to manage Antero Resources in a manner that is beneficial to Antero Resources. In resolving these actual or apparent conflicts of interest, these directors and officers may choose strategies that favor Antero Resources over our interests and the interests of our stockholders. These actual and apparent conflicts may in certain cases include, for example, the decision to declare and pay dividends or the decision to repurchase shares of our common stock owned by Antero Resources. The resolution of any conflicts of interest between Antero Resources and its subsidiaries, on one hand, and us and our subsidiaries, on the other, to the extent we can resolve them, may be costly and reduce the amount of time and attention that our directors and officers may spend in operating our business, which, in each case, may adversely affect our business.
Furthermore, Antero Resources is under no obligation to adopt a business strategy that favors us. For example, Antero Resources has dedicated acreage to, and entered into long-term contracts for gathering and compression services on, our gathering and compression systems, as well as long-term contracts for receiving water services. However, while we have a right of first offer that
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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 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.
Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders.
Paul M. Rady and an individual affiliated with Yorktown serve as members of our Board and the Board of Directors of Antero Resources. Mr. Rady and Yorktown also own a significant portion of the shares of common stock of Antero Resources. As a result of their investments in Antero Resources, Mr. Rady and Yorktown may have conflicting interests with other stockholders. Conflicts of interest could arise in the future between us, on the one hand, and Mr. Rady and Yorktown, on the other hand, regarding, among other things, decisions related to our financing, capital expenditures and growth plans, the terms of our agreements with Antero Resources and its subsidiaries and the pursuit of potentially competitive business activities or business opportunities.
Income Taxes
Our future tax liability may be greater than expected if we do not generate deductions or net operating loss (“NOL”) carryforwards sufficient to offset taxable income or if tax authorities challenge certain of our tax positions.
We expect to generate deductions and NOL carryforwards that we can use to offset our taxable income. As a result, we do not expect to pay material U.S. federal and state income taxes through 2026. This expectation is based upon assumptions our management has made regarding, among other things, income, capital expenditures and net working capital. Further, the IRS or other tax authorities could challenge one or more tax positions we take, such as the classification of assets under the income tax depreciation rules, the characterization of expenses for income tax purposes and the tax characterization of the Transactions. Further, any change in law may affect our tax position. While we expect that our deductions and NOL carryforwards will be available to us as a future benefit, in the event that they are not generated as expected, are successfully challenged by the IRS (in a tax audit or otherwise), or are subject to future limitations, our ability to realize these benefits may be limited.
Changes to applicable tax laws and regulations or exposure to additional income tax liabilities could affect our business and
future profitability.
We are subject to various and evolving U.S. federal, state and local taxes. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect, and may have an adverse effect on our business and future profitability. For example, several tax proposals have been set forth that would, if enacted, make significant changes to U.S. tax laws. Such proposals include an increase in the U.S. income tax rate applicable to corporations (such as us) from 21%, the imposition of a minimum tax on book income for certain corporations and the imposition of an excise tax on certain corporate stock repurchases that would be borne by the corporation repurchasing such stock. The U.S. Congress may consider, and could include, some or all of these proposals in connection with tax reform that may be undertaken. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws could adversely affect our business and future profitability.
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Taxable gain or loss on the sale of our common stock could be more or less than expected.
If a holder sells our common stock, the holder will recognize gain or loss equal to the difference between the amount realized and the holder’s tax basis in the shares of common stock sold. To the extent that the amount of distributions on our common stock exceeds our current and accumulated earnings and profits, such distributions will be treated as a tax free return of capital and will reduce a holder’s tax basis in its common stock. We expect the majority of our distributions to be in excess of our earnings and profits through 2026. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in our common stock, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of our common stock.
The IRS Forms 1099-DIV that our stockholders receive from their brokers may over-report dividend income with respect to our common stock for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a stockholder’s U.S. federal income tax return. For non-U.S. holders of our common stock, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund to claim a refund of the overwithheld taxes.
Distributions we pay with respect to our common stock will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a stockholder’s tax basis in their common stock and then as capital gain realized on the sale or exchange of such stock. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax with respect to distribution amounts that should have been classified as a tax-free return of capital. In such a case, a stockholder generally would have to timely file an amended U.S. tax return or an appropriate claim for refund to obtain a refund of the overpaid tax.
For a U.S. holder of our common stock, the IRS Forms 1099-DIV received from brokers may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a stockholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended U.S. federal, state or local income tax return). We will attempt to timely notify our stockholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our stockholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a stockholder’s tax return.
For a non-U.S. holder of our common stock, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with the conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that constitute a “dividend” for U.S. federal income tax purposes, or a stockholder’s broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a stockholder’s broker or other withholding agent may overwithhold taxes from distributions paid. In such a case, a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
General Risks
We expect to use a significant portion of our cash flows to pay dividends to our stockholders and/or repurchase shares of our common stock, which could limit our ability to grow and make acquisitions.
We have previously announced that we plan to return capital to our stockholders through dividends to our stockholders and repurchasing shares of our common stock, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional shares of common stock in connection with any acquisitions or expansion capital expenditures, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the cash that we have available to return capital to our stockholders through dividends and/or repurchases of shares of our common stock.
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We may reduce or cease paying dividends on our common stock.
We are not obligated to pay dividends on shares of our common stock. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of our common stock are only entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our Board out of funds legally available for dividend payments. Our Board makes a determination each quarter as to the actual amount, if any, of dividends to pay on our common stock, based on various factors, some of which are beyond our control, including our operating cash flows, our working capital needs, our ability to access capital markets for debt and equity financing on reasonable terms, the restrictions contained in our debt instruments, our debt service requirements, credit metrics and the cost of acquisitions, if any. We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. Accordingly, we cannot guarantee that we will declare any future dividends at levels consistent with our historic practice or at all.
The price of our common stock may be volatile, and you could lose a significant portion of your investment.
The market price of our common stock could be volatile, and holders of common stock may not be able to resell their common stock at or above the price at which they acquired such securities due to fluctuations in the market price of our common stock.
Specific factors that may have a significant effect on the market price for our common stock include:
| ● | our operating and financial performance and prospects and the trading price of our common stock; |
| ● | the level of our dividends; |
| ● | quarterly variations in the rate of growth of our financial indicators, such as dividends per share of our common stock, net income and revenues; |
| ● | levels of indebtedness; |
| ● | changes in revenue or earnings estimates or publication of research reports by analysts; |
| ● | speculation by the press or investment community; |
| ● | sales of our common stock by other stockholders; |
| ● | announcements by us or our competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments; |
| ● | general market conditions; |
| ● | changes in accounting standards, policies, guidance, interpretations or principles; |
| ● | adverse changes in tax laws or regulations; |
| ● | domestic and international economic, legal and regulatory factors related to our performance; and |
| ● | Antero Resources’ operating and financial performance and prospects, and the trading price of its common stock. |
There may be future dilution of our common stock, which could adversely affect the market price of shares of our common stock.
We are not restricted from issuing additional shares of our common stock out of our authorized capital. In the future, we may issue shares of our common stock to raise cash for future activities, acquisitions or other purposes. We may also acquire interests in other companies by using a combination of cash and shares of our common stock or only shares. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, shares of our common stock. Any of these events may dilute the ownership interests of our stockholders, reduce our earnings per share or have an adverse effect on the price of shares of our common stock.
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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 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.
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Veolia
The Company is currently involved in a consolidated lawsuit with Veolia Water Technologies, Inc. (“Veolia”) relating to the Clearwater Facility.
On March 13, 2020, Antero Treatment LLC (“Antero Treatment”), a wholly owned subsidiary of the Company, filed suit against Veolia in the district court of Denver County, Colorado, asserting claims of fraud, breach of contract and other related claims. Antero Treatment alleges that Veolia failed to meet its contractual obligations to design and build a “turnkey” wastewater disposal facility under a Design/Build Agreement dated August 18, 2015 (the “DBA”), and that Veolia fraudulently concealed certain miscalculations and design flaws during contract negotiations and continued to conceal and fraudulently misrepresent the impact of certain design changes post-execution of the DBA. On March 13, 2020, Veolia filed a separate suit against the Company, Antero Resources, and certain of the Company’s wholly owned subsidiaries (collectively, the “Antero Defendants”) in Denver County, Colorado. In its lawsuit, Veolia asserted breach of contract and equitable claims against the Antero Defendants for alleged failures under the DBA. Veolia’s suit was consolidated into the action filed by Antero Treatment.
Veolia and the Antero Defendants each filed partial motions to dismiss and motions for summary judgment directed at certain claims asserted by the opposing party. A bench trial on the remaining claims is occurring from January 24 through February 10, 2022 and on February 24, 2022. At trial, Antero Treatment sought damages from Veolia of approximately $450 million, which represents the Company’s out-of-pocket costs associated with the Clearwater Facility project. In the alternative, Antero Treatment sought damages related to multiple breaches of the DBA, totaling approximately $370 million. Also at trial, Veolia sought monetary damages of approximately $118 million, including alleged delay and extra-contractual costs and a contract balance relating to an allegation that Antero Defendants improperly terminated the DBA. The Antero Defendants vigorously deny Veolia’s claims. A final judgment on the claims has not yet been rendered.
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 11, 2022, shares of our common stock were held by 42 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 11, 2022, Antero Resources and its subsidiaries owned 139,042,345 shares of our common stock, which represented a 29.1% interest in us.
Issuer Purchases of Equity Securities
The following table sets forth our common stock repurchase activity for each period presented:
Approximate | |||||||||||
Total Number of | Dollar Value of | ||||||||||
Total Number | Average Price | Shares Purchased | Shares that May | ||||||||
of Shares | Paid per | as Part of Publicly | Yet be Purchased | ||||||||
Period |
| Purchased (1) | Share | Announced Plans (2) | Under the Plan |
| |||||
October 1, 2021 – October 31, 2021 |
| 11,214 | $ | 11.35 | — | N/A | |||||
November 1, 2021 – November 30, 2021 |
| — | — | — | N/A | ||||||
December 1, 2021 – December 31, 2021 |
| — | — | — | N/A | ||||||
Total | 11,214 | $ | 11.35 | — | $ | 149,767,409 | |||||
| (1) | The total number of shares purchased represents shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of equity awards held by our employees. |
| (2) | In August 2019, the Board authorized a $300 million share repurchase program, which was extended through June 30, 2023 during the first quarter of 2021. During the three months ended December 31, 2021, we did not make any repurchases under this program. |
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Dividends
On January 12, 2022, the Board declared an aggregate cash dividend on the shares of our common stock of $0.225 per share for the quarter ended December 31, 2021. The dividend was paid on February 9, 2022 to stockholders of record as of January 26, 2022.
The Board also declared a cash dividend of $138 thousand on shares of our Series A Non-Voting Perpetual Preferred Stock, par value $0.01 (the “Series A Preferred Stock”), that was paid on February 14, 2022 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, 2021, 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, AMGP, common shares through March 12, 2019 and our common stock thereafter, the Standard Poor’s 500 (“SP 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.
The information in this Form 10-K appearing under the heading “Stock Performance Graph” is being “furnished” pursuant to Item 2.01(e) of Regulation S-K under the Securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of the Exchange Act except to the extent that we specifically request that it be treated as such.
ITEM 6. Reserved
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. The information provided below supplements, but does not form part of, our consolidated financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, see “Item 1A. Risk Factors.” and the section entitled “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. In this section, references to “Antero Midstream,” “AM,” the “Company,” “we,” “us,” and “our” refer to Antero Midstream Corporation and its consolidated subsidiaries, unless otherwise indicated or the context otherwise requires.
Overview
We are a growth-oriented midstream energy company formed to own, operate and develop midstream energy assets to primarily service Antero Resources’ production and completion activity. We believe that our strategically located assets and our relationship with Antero Resources have allowed us to become a leading midstream energy company serving the Appalachian Basin and present opportunities to expand our midstream services to other operators in the Appalachian Basin. Our assets consist of gathering pipelines, compressor stations and interests in processing and fractionation plants that collect and process production from Antero Resources’ wells in the Appalachian Basin in West Virginia and Ohio. Our assets also include two independent water handling systems that deliver water from the Ohio River and several regional waterways, which portions of these systems are also utilized to transport flowback and produced water. These water handling systems consist of permanent buried pipelines, surface pipelines and water storage facilities, as well as pumping stations, blending facilities and impoundments to transport the water throughout the pipelines. These services are provided by us directly or through third-parties with which we contract. Our assets also include other flowback and produced water treatment facilities that we use to provide water treatment services to Antero Resources and third-parties.
COVID-19 Pandemic
Since the start of 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, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for oil, natural gas and NGLs, and related commodity pricing, has improved. However, new variants of the virus could cause further commodity market volatility and resulting financial market instability, and these are variables beyond our control that may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates and our ability to access the capital markets.
As a midstream energy company, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. As such, we have continued to operate throughout the pandemic as permitted under these regulations while taking steps to protect the health and safety of our workers. We have implemented protocols to reduce the risk of an outbreak within our field operations and corporate offices, and these protocols have not reduced Antero Resources’ production and our throughput in a significant manner. A substantial portion of our non-field level employees currently operate in remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting. We continue to monitor the COVID-19 environment in order to (i) protect the health and safety of our employees and contract workers and (ii) determine when a return to in-office working arrangements will be appropriate.
Neither our nor Antero Resources’ supply chain has experienced any significant interruptions due to the COVID-19 pandemic. Prior to the COVID-19 pandemic, Antero Resources had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for its condensate volumes, and as a result of the pandemic, Antero Resources has expanded its customer base and its condensate storage capacity within the Appalachian Basin. However, if Antero Resources or our other customers were to experience any production curtailments or shut-ins it would reduce throughput for our gathering and processing systems. In addition, if our customers were to delay or discontinue drilling or completion activities, it would reduce the volumes of water that we handle and therefore revenues for our water distribution and handling business.
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As the global economy continues to recover from the effects of the COVID-19 pandemic, economic indicators have continued to strengthen. However, the economy has begun to experience elevated inflation levels as a result of global supply and demand imbalances resulting from the COVID-19 pandemic. For example, the United States Bureau of Labor and Statistics (“BLS”) CPI for all urban consumers increased 7% from December 31, 2020 to December 31, 2021 as compared to the average historical 10-year rate of 2%. Additionally, employment activity has also begun to strengthen as demonstrated by the United States BLS unemployment rate declining from a high of 15% in April 2020 to 4% in December 2021. Inflationary pressures and labor shortages could result in increases to our operating and capital costs that are not fixed, renegotiation of contracts and/or supply agreements and higher labor costs, among others. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
Recent Developments and Highlights
Credit Facility
On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility with lender commitments of $1.25 billion, which matures on October 26, 2026; provided that if on November 17, 2025 any of the 7.875% senior unsecured notes due May 15, 2026 (the “2026 Notes”) are outstanding, the New Credit Facility will mature on such date. We reduced our commitments from $2.13 billion under the Prior Credit Facility to $1.25 billion to better align with our expected future liquidity needs. See Note 10—Long-Term Debt to the consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements—Credit Facility” for more information.
Issuance of Senior Notes
On June 8, 2021, we issued $750 million in aggregate principal amount of 5.375% senior notes due June 15, 2029 (the “2029 Notes”) at par. The 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2029 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners LP’s (“Antero Midstream Partners”) wholly owned subsidiaries (other than Antero Midstream Finance Corporation) and certain of its future restricted subsidiaries. See Note 10—Long-Term Debt to the consolidated financial statements for more information.
Redemption of Senior Notes
On June 8, 2021, we redeemed all of our outstanding 5.375% Senior Notes Due September 15, 2024 (the “2024 Notes”) at a redemption price of 102.688% of the principal amount therefore, plus accrued and unpaid interest. See Note 10—Long-Term Debt to the consolidated financial statements for more information.
Return of Capital Program
On August 12, 2019, our Board authorized a share repurchase program to opportunistically repurchase up to $300 million of shares of our outstanding common stock. On February 10, 2021, our Board extended this program through June 30, 2023. During the year ended December 31, 2021, we did not repurchase any shares under this program. We currently have approximately $150 million of share repurchase capacity remaining under this program.
On January 12, 2022, the Board declared a cash dividend on the shares of our common stock of $0.225 per share for the quarter ended December 31, 2021. The dividend was paid on February 9, 2022 to stockholders of record as of January 26, 2022. The Board also declared a cash dividend of $138 thousand on the Series A Preferred Stock that was paid on February 14, 2022 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.
Sources of Our Revenues
Our gathering and compression revenues are driven by the volumes of natural gas we gather and compress, and our water handling revenues are driven by quantities of fresh water delivered to our customers to support their well completion operations and produced water treated. Pursuant to our long-term contracts with Antero Resources, we have secured long-term dedications covering a significant portion of Antero Resources’ current and future acreage for gathering and compression services. We have also entered into a long-term water services agreement covering Antero Resources’ 502,000 net acres in West Virginia and Ohio, with a right of first offer on all future areas of operation. Under the agreement, we receive a fixed fee for all fresh water deliveries by pipeline directly to the well site, subject to annual CPI-based adjustments. In addition, we also provide other fluid handling services. Our fresh water delivery systems and other fluid handling services support well completion and production operations for Antero
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Resources. These services are provided by us directly or through third-parties with which we contract. For other fluid handling services provided by third-parties, Antero Resources reimburses our third-party out-of-pocket costs plus 3%. For other fluid handling services provided by us, we charge Antero Resources a cost of service fee. The initial term of the water services agreement runs to 2035. All of Antero Resources’ existing acreage is dedicated to us for gathering and compression services except for existing third-party commitments. Approximately 127,000 gross leasehold acres characterized by dry gas and liquids-rich production have been previously dedicated to third-party gatherers.
Our gathering and compression operations are substantially dependent upon natural gas and oil production from Antero Resources’ upstream activity in its areas of operation. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. Although we expect that Antero Resources will continue to devote substantial resources to the development of oil and gas reserves, we have no control over this activity and Antero Resources has the ability to reduce or curtail such development at its discretion.
Our water handling operations are substantially dependent upon the number of wells drilled and completed by Antero Resources, as well as Antero Resources’ production. As of December 31, 2021, Antero Resources had disclosed estimated net proved reserves 17.7 Tcfe, of which 58% was natural gas, 41% were NGLs and 1% was oil. As of December 31, 2021, Antero Resources’ drilling inventory consisted of 2,083 identified potential horizontal well locations, approximately 1,371 of which were located on acreage dedicated to us, providing us with significant opportunity for growth as Antero Resources’ drilling program continues.
Principal Components of Our Cost Structure
The following items are the primary components of our operating expenses.
| ● | Direct Operating. We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. We schedule and conduct maintenance over time to avoid significant variability in our direct operating expense and minimize the impact on our cash flow. Gathering and compression operating costs consist primarily of labor, water disposal, pigging, fuel, monitoring, repair and maintenance, utilities and contract services. Gathering and compression operating costs vary with the miles of pipeline and number of compressor stations in our gathering and compression system. Fresh water operating expenses consist primarily of labor, pigging, monitoring, repair and maintenance and contract services. Fresh water operating costs vary with the miles of pipeline, number of pumping stations and to a lesser extent the number of well completions in the Appalachian Basin for which we deliver fresh water and number of impoundments in our water system. Other fluid handling costs, relate to contract services performed by us and third parties. Our other fluid handling costs consist of labor, monitoring and repair and maintenance costs. The other primary drivers of our direct operating expense include maintenance and contract services, regulatory and compliance expense and ad valorem taxes. |
| ● | General and Administrative. Our general and administrative expenses include direct charges and costs charged by Antero Resources. These costs relate to: (i) various business services, including payroll processing, accounts payable processing and facilities management, (ii) various corporate services, including legal, accounting, treasury, information technology and human resources and (iii) compensation, including certain equity-based compensation. These expenses are charged to the Company based on the nature of the expenses and are apportioned based on a combination of the Company’s proportionate share of gross property and equipment, capital expenditures and labor costs, as applicable. Management believes these allocation methodologies are reasonable. |
| ● | Equity-based compensation includes (i) costs allocated to Antero Midstream by Antero Resources for grants made prior to March 12, 2019 pursuant to the Antero Resources Corporation Long-Term Incentive Plan and (ii) costs related to the Antero Midstream Corporation Long-Term Incentive Plan. |
| ● | Depreciation. Depreciation consists of our estimate of the decrease in value of the assets capitalized in property and equipment as a result of using the assets throughout the applicable year. Depreciation is computed over the asset’s estimated useful life using the straight-line basis. See Note 8—Property and Equipment to our consolidated financial statements for additional information on our asset classes and estimated lives of our assets. |
| ● | Impairment. We evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to their estimated fair value. |
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| ● | Interest. We have typically financed a portion of our cash requirements with borrowings under our revolving credit facility and with senior unsecured notes. Our interest expense also includes amortization of deferred financing costs incurred in connection with our revolving credit facility and senior notes, amortization of senior notes premiums and finance leases. See Note 10—Long-Term Debt to our consolidated financial statements and “—Capital Resources and Liquidity—Debt Agreements” for additional information on our debt agreements. |
| ● | Income tax expense. We are subject to state and federal income taxes but are currently not in a cash tax paying position with respect to state and federal income taxes. The difference between our financial statement income tax expense and our federal income tax liability is primarily due to the differences in the tax and financial statement treatment of our investment in Antero Midstream Partners. We have recorded deferred income tax expense to the extent our deferred tax liabilities exceed our deferred tax assets. Our deferred tax assets result primarily from net operating loss carryforwards. As of December 31, 2021, we had approximately $342 million of U.S. federal net operating loss carryforwards (“NOLs”), and approximately $412 million of state NOLs. The Company currently considers all of its deferred tax assets realizable. The amount of deferred tax assets considered realizable, however, could change as we generate taxable income or as estimates of future taxable income are reduced. See Note 9—Income Taxes to our consolidated financial statements for a discussion of our deferred tax position and income tax expense. |
How We Evaluate Our Operations
We use a variety of financial and operational metrics to evaluate our performance. These metrics help us identify factors and trends that impact our operating results, profitability and financial condition. The key metrics we use to evaluate our business are provided below.
Adjusted EBITDA
We use Adjusted EBITDA as a performance measure to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and return capital to stockholders. Adjusted EBITDA is a non-GAAP financial measure. See “—Non-GAAP Financial Measures” below for more information regarding this financial measure, including a reconciliation to its most directly comparable GAAP measure.
Gathering and Compression Throughput
We must continually obtain additional supplies of natural gas to maintain or increase throughput on our systems. Our ability to maintain existing supplies of natural gas and obtain additional supplies is primarily impacted by (i) our acreage dedication and the level of successful drilling activity by Antero Resources and (ii) the potential for acreage dedications with and successful drilling by third-party producers. Any increase in our throughput volumes over the near term will likely be driven by Antero Resources continuing its drilling and development activities on its Appalachian Basin acreage.
Water Handling Volumes
Our fresh water volumes are primarily driven by hydraulic fracturing activities conducted as part of well completions. Our other fluid handling volumes are driven by hydraulic fracturing activities and produced water volumes, which are primarily a function of Antero Resources’ completion activities and production. Antero Resources’ consolidated acreage position allows us to provide fresh water and other fluid handling services for Antero Resources’ completion activities in a more efficient manner. However, to the extent that Antero Resources’ drilling and completion schedule is not met, or Antero Resources uses less fresh water and other fluid handling services in its well completion operations than expected (for example, due to a reduction in completions), and production declines, our water volumes may decline.
Results of Operations
We have two operating segments: (i) gathering and processing and (ii) water handling. The gathering and processing segment includes a network of gathering pipelines and compressor stations that collect and process gross production from Antero Resources’ wells in the Appalachian Basin, as well as equity in earnings from the Joint Venture and Stonewall Gas Gathering LLC. The water handling segment includes (i) two independent systems that deliver water from sources including the Ohio River, local reservoirs and several regional waterways, (ii) the wastewater treatment facility and related landfill (collectively, the “Clearwater Facility”) that was idled in September 2019 and (iii) other fluid handling services.
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Year Ended December 31, 2020 Compared to Year Ended December 31, 2021
The operating results of our reportable segments were as follows for the years ended December 31, 2020 and 2021:
Year Ended December 31, 2020 | |||||||||||||
| Gathering and |
| Water |
|
| Consolidated | |||||||
(in thousands) |
| Processing |
| Handling |
| Unallocated (1) |
| Total | |||||
Revenues: | |||||||||||||
Revenue–Antero Resources | $ | 759,459 | 259,932 | — | 1,019,391 | ||||||||
Gathering—low pressure rebate | (48,000) | — | — | (48,000) | |||||||||
Amortization of customer relationships | (37,086) | (33,586) | — | (70,672) | |||||||||
Total revenues | 674,373 | 226,346 | — | 900,719 | |||||||||
Operating expenses: | |||||||||||||
Direct operating | 56,508 | 108,878 | — | 165,386 | |||||||||
General and administrative (excluding equity-based compensation) | 20,410 | 11,796 | 7,229 | 39,435 | |||||||||
Equity-based compensation | 9,489 | 2,388 | 901 | 12,778 | |||||||||
Facility idling | — | 15,219 | — | 15,219 | |||||||||
Depreciation | 57,300 | 51,490 | — | 108,790 | |||||||||
Impairment of property and equipment | 947 | 97,232 | — | 98,179 | |||||||||
Impairment of goodwill | 575,461 | — | — | 575,461 | |||||||||
Accretion of asset retirement obligations | — | 180 | — | 180 | |||||||||
Loss on asset sale | 2,689 | 240 | — | 2,929 | |||||||||
Total operating expenses | 722,804 | 287,423 | 8,130 | 1,018,357 | |||||||||
Operating loss | (48,431) | (61,077) | (8,130) | (117,638) | |||||||||
Other income (expense): | |||||||||||||
Interest expense, net | — | — | (147,007) | (147,007) | |||||||||
Equity in earnings of unconsolidated affiliates | 86,430 | — | — | 86,430 | |||||||||
Total other income (expense) | 86,430 | — | (147,007) | (60,577) | |||||||||
Income (loss) before income taxes | 37,999 | (61,077) | (155,137) | (178,215) | |||||||||
Income tax benefit | — | — | 55,688 | 55,688 | |||||||||
Net income (loss) and comprehensive income (loss) | $ | 37,999 | (61,077) | (99,449) | (122,527) | ||||||||
Adjusted EBITDA (2) | $ | 850,209 | |||||||||||
| (1) | Corporate expenses that are not directly attributable to either the gathering and processing or water handling segments. |
| (2) | Adjusted EBITDA is a non-GAAP financial measure. For a discussion of this measure, including a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, see “—Non-GAAP Financial Measures”. |
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Year Ended December 31, 2021 | |||||||||||||
Gathering and |
| Water |
|
| Consolidated | ||||||||
(in thousands) |
| Processing |
| Handling |
| Unallocated (1) |
| Total | |||||
Revenues: | |||||||||||||
Revenue–Antero Resources | $ | 761,737 | 218,621 | — | 980,358 | ||||||||
Revenue–third-party | — | 516 | — | 516 | |||||||||
Gathering—low pressure rebate | (12,000) | — | — | (12,000) | |||||||||
Amortization of customer relationships | (37,086) | (33,586) | — | (70,672) | |||||||||
Total revenues | 712,651 | 185,551 | — | 898,202 | |||||||||
Operating expenses: | |||||||||||||
Direct operating | 65,983 | 91,137 | — | 157,120 | |||||||||
General and administrative (excluding equity-based compensation) | 26,261 | 20,317 | 3,731 | 50,309 | |||||||||
Equity-based compensation | 10,119 | 2,500 | 910 | 13,529 | |||||||||
Facility idling | — | 3,997 | — | 3,997 | |||||||||
Depreciation | 59,692 | 49,098 | — | 108,790 | |||||||||
Impairment of property and equipment | 4,608 | 434 | — | 5,042 | |||||||||
Accretion of asset retirement obligations | — | 460 | — | 460 | |||||||||
Loss on asset sale | 3,628 | — | — | 3,628 | |||||||||
Total operating expenses | 170,291 | 167,943 | 4,641 | 342,875 | |||||||||
Operating income | 542,360 | 17,608 | (4,641) | 555,327 | |||||||||
Other income (expense): | |||||||||||||
Interest expense, net | — | — | (175,281) | (175,281) | |||||||||
Equity in earnings of unconsolidated affiliates | 90,451 | — | — | 90,451 | |||||||||
Loss on early extinguishment of debt | — | — | (21,757) | (21,757) | |||||||||
Total other income (expense) | 90,451 | — | (197,038) | (106,587) | |||||||||
Income before income taxes | 632,811 | 17,608 | (201,679) | 448,740 | |||||||||
Income tax expense | — | — | (117,123) | (117,123) | |||||||||
Net income and comprehensive income | $ | 632,811 | 17,608 | (318,802) | 331,617 | ||||||||
Adjusted EBITDA (2) | $ | 876,438 | |||||||||||
| (1) | Corporate expenses that are not directly attributable to either the gathering and processing or water handling segments. |
| (2) | Adjusted EBITDA is a non-GAAP financial measure. For a discussion of this measure, including a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, see “—Non-GAAP Financial Measures”. |
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The following table sets forth the operating data for Antero Midstream:
Year Ended | Amount of | ||||||||||||
December 31, | Increase | Percentage | |||||||||||
| 2020 |
| 2021 |
| or Decrease |
| Change | ||||||
Operating Data: | |||||||||||||
Gathering—low pressure (MMcf) | 1,069,822 | 1,060,444 | (9,378) | (1) | % | ||||||||
Compression (MMcf) | 991,726 | 1,006,366 | 14,640 | 1 | % | ||||||||
Gathering—high pressure (MMcf) | 1,058,119 | 1,037,094 | (21,025) | (2) | % | ||||||||
Fresh water delivery (MBbl) | 40,076 | 34,572 | (5,504) | (14) | % | ||||||||
Other fluid handling (MBbl) | 20,945 | 16,930 | (4,015) | (19) | % | ||||||||
Wells serviced by fresh water delivery | 91 | 75 | (16) | (18) | % | ||||||||
Gathering—low pressure (MMcf/d) | 2,923 | 2,905 | (18) | (1) | % | ||||||||
Compression (MMcf/d) | 2,710 | 2,757 | 47 | 2 | % | ||||||||
Gathering—high pressure (MMcf/d) | 2,891 | 2,841 | (50) | (2) | % | ||||||||
Fresh water delivery (MBbl/d) | 109 | 95 | (14) | (13) | % | ||||||||
Other fluid handling (MBbl/d) | 57 | 46 | (11) | (19) | % | ||||||||
Average Realized Fees: | |||||||||||||
Average gathering—low pressure fee ($/Mcf) (1) | $ | 0.33 | 0.33 | — | * | ||||||||
Average compression fee ($/Mcf) | $ | 0.20 | 0.20 | — | * | ||||||||
Average gathering—high pressure fee ($/Mcf) | $ | 0.20 | 0.20 | — | * | ||||||||
Average fresh water delivery fee ($/Bbl) | $ | 3.96 | 3.97 | 0.01 | * | ||||||||
Joint Venture Operating Data: | |||||||||||||
Processing—Joint Venture (MMcf) | 523,739 | 543,649 | 19,910 | 4 | % | ||||||||
Fractionation—Joint Venture (MBbl) | 13,200 | 13,644 | 444 | 3 | % | ||||||||
Processing—Joint Venture (MMcf/d) | 1,431 | 1,489 | 58 | 4 | % | ||||||||
Fractionation—Joint Venture (MBbl/d) | 36 | 37 | 1 | 3 | % | ||||||||
*Not meaningful or applicable.
| (1) | The year ended December 31, 2021 average realized fee does not include $2.4 million of low pressure gathering fee revenues which volumes relate to prior periods. |
Revenues. Total revenues decreased by $3 million, from $901 million, including amortization of customer relationships of $71 million, for the year ended December 31, 2020, to $898 million, including amortization of customer relationships of $71 million, for the year ended December 31, 2021. Gathering and processing revenues increased by 6%, from $675 million for the year ended December 31, 2020 to $713 million for the year ended December 31, 2021. Water handling revenues decreased by 18%, from $226 million for the year ended December 31, 2020 to $185 million for the year ended December 31, 2021. These fluctuations primarily resulted from the following:
Gathering and Processing
| ● | Low pressure gathering revenue increased $37 million period over period primarily due to $36 million in lower rebates to Antero Resources during the year ended December 31, 2021, partially offset by decreased throughput volumes of 9 Bcf, or 18 MMcf/d. Low pressure gathering volumes decreased between periods primarily due to downtime at certain processing and fractionation facilities during the third quarter of 2021, partially offset by 69 additional wells connected to our system since December 31, 2020. |
| ● | Compression revenue increased $4 million period over period due to increased throughput volumes of 15 Bcf, or 47 MMcf/d, primarily due to additional wells connected to our system since December 31, 2020, and one new compressor that came online during the summer of 2020, partially offset by downtime at certain processing and fractionation facilities during the third quarter of 2021. |
| ● | High pressure gathering revenue decreased $3 million period over period due to decreased throughput volumes of 21 Bcf, or 50 MMcf/d. The high pressure gathering volumes decreased period over period primarily as a result of downtime at certain processing and fractionation facilities during the third quarter of 2021, partially offset by 69 new wells connected to our system since December 31, 2020. |
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Water Handling
| ● | Fresh water delivery revenue decreased $21 million period over period due to decreased fresh water delivery volumes of 6 MMBbl, or 14 MBbl/d, as a result of 16 fewer wells completed during the year ended December 31, 2021. |
| ● | Other fluid handling services revenue decreased $19 million period over period primarily due to a $25 million decrease in services that are billed at cost plus 3% as a result of increased use of our water blending services and cost reductions, partially offset by a $6 million increase in water blending services. |
Direct operating expenses. Total direct operating expenses decreased by 5%, from $165 million for the year ended December 31, 2020 to $157 million for the year ended December 31, 2021. Gathering and processing direct operating expenses increased 17% from $56 million for the year ended December 31, 2020 to $66 million for the year ended December 31, 2021 primarily due to higher maintenance expense and ad valorem taxes between periods, as well as increased expense from one new compressor station that came online in the summer of 2020. Water handling direct operating expenses decreased by 16%, from $109 million for the year ended December 31, 2020 to $91 million for the year ended December 31, 2021. The decrease was primarily due to lower costs associated with third-party other fluid handling services of $25 million, partially offset by higher blending costs as a result of increased blending volumes between periods.
General and administrative (excluding equity-based compensation) expenses. General and administrative expenses (excluding equity-based compensation expense) increased 28%, from $39 million for the year ended December 31, 2020 to $50 million for the year ended December 31, 2021 primarily due to (i) legal costs associated with the Clearwater Facility, (ii) higher salary and wage expense, which includes our annual incentive program that was temporarily and significantly reduced during 2020 and (iii) higher costs allocated to us from Antero Resources during 2021, partially offset by cost reduction efforts between periods.
Equity-based compensation expenses. Equity-based compensation expenses remained relatively consistent at $13 million and $14 million for the years ended December 31, 2020 and 2021, respectively.
Facility idling expenses. Facility idling expenses decreased 74%, from $15 million for the year ended December 31, 2020 to $4 million for the year ended December 31, 2021 primarily due to reduced Clearwater Facility decommissioning costs between periods.
Depreciation expense. Total depreciation expense remained consistent at $109 million for each of the years ended December 31, 2020 and 2021.
Impairment of property and equipment expense. Impairment of property and equipment expense of $98 million for the year ended December 31, 2020 was primarily for the impairment of fresh water delivery assets in the Utica Shale region. Impairment of property and equipment expense of $5 million for the year ended December 31, 2021 was primarily due to canceled project write-downs as well as a lower of cost or market adjustment for pipe inventory.
Impairment of goodwill expense. Impairment of goodwill expense of $575 million for the year ended December 31, 2020 reflects an impairment of the goodwill that was associated with our gathering system due to declines in commodity prices and the industry environment. All of our goodwill was fully impaired during the year ended December 31, 2020.
Loss on asset sale. Loss on asset sale remained relatively consistent at $3 million and $4 million for the years ended December 31, 2020 and 2021, respectively, and primarily relate to sales of excess pipe inventory.
Interest expense. Interest expense increased by 19%, from $147 million for the year ended December 31, 2020 to $175 million for the year ended December 31, 2021 primarily due to the issuance of (i) $550 million of 2026 Notes on November 10, 2020 and (ii) $750 million of 2029 Notes on June 8, 2021, partially offset by lower borrowings under the Credit Facility during the year ended December 31, 2021 and the redemption of all $650 million of the 2024 Notes on June 8, 2021.
Equity in earnings of unconsolidated affiliates. Equity in earnings in unconsolidated affiliates increased by 5%, from $86 million for the year ended December 31, 2020 to $90 million for the year ended December 31, 2021 primarily due to an increase in the level of volume throughput at the Joint Venture between periods, including one new Joint Venture processing plant with nameplate capacity of 200 MMcf/d being placed in service during July 2021, partially offset by the effects of the processing plant and fractionation facility downtime during the third quarter of 2021.
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Loss on early extinguishment of debt. Loss on early extinguishment of debt for the year ended December 31, 2021 of $22 million primarily relates to the redemption of all $650 million of the 2024 Notes at a premium to par of $17 million as well as the write-off of $6 million of unamortized deferred financing costs, partially offset by $2 million of unamortized premium.
Income tax benefit (expense). Income tax benefit for the year ended December 31, 2020 was $56 million or an effective tax rate of 31.2% primarily due to the loss before taxes for the period coupled with an $11 million rate benefit related to the carryback of net operating losses to prior tax years. Income tax expense for the year ended December 31, 2021 was $117 million primarily due to income before taxes for the period which reflects an effective tax rate of 26.1% primarily due to the effects of state income taxes.
Net income (loss). Net loss was $123 million for the year ended December 31, 2020 primarily due to a $575 million impairment of goodwill for our gathering system and an $89 million impairment of our freshwater delivery assets. Net income was $332 million for the year ended December 31, 2021, primarily due to higher gathering and processing revenues and lower (i) impairment of property and equipment, (ii) direct operating expense and (iii) facility idling expense between periods, offset by lower water handling revenues and higher (i) interest expense, (ii) loss on early extinguishment of debt and (iii) general and administrative expense between periods.
Adjusted EBITDA. Adjusted EBITDA increased by 3%, from $850 million for the year ended December 31, 2020 to $876 million for the year ended December 31, 2021. The increase was primarily due to increased gathering and compression revenues and decreased direct operating expense and facility idling costs between periods, partially offset by lower water handling revenues and higher general and administrative expense between periods. For a discussion of the non-GAAP financial measure Adjusted EBITDA, including a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, read “—Non-GAAP Financial Measures” below.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” in our 2020 Annual Report on Form 10-K for a discussion of the results of operations for the year ended December 31, 2019 compared to the year ended December 31, 2020.
Capital Resources and Liquidity
Sources and Uses of Cash
Capital resources and liquidity are provided by operating cash flows, borrowings under our New Credit Facility and capital market transactions. We expect that the combination of these capital resources will be adequate to meet our working capital requirements, capital expenditures program, expected quarterly cash dividends and share repurchases under our share repurchases program for at least the next 12 months.
During the year ended December 31, 2021, we paid dividends of $0.98 per share, or a total of $471 million, to holders of our common stock, as applicable, and we paid $550 thousand of dividends on our Series A Preferred Stock. On January 12, 2022, the Board declared a cash dividend on the shares of our common stock of $0.225 per share for the quarter ended December 31, 2021 to be paid on February 9, 2022 to stockholders of record as of January 26, 2022. The Board also declared an aggregate cash dividend of $138 thousand on our Series A Preferred Stock that was paid on February 14, 2022. As of December 31, 2021, there were dividends in the amount of $69 thousand accumulated in arrears on our Series A Preferred Stock.
As of December 31, 2021, we did not have any off-balance sheet arrangements.
Cash Flows
The following table and discussion presents a summary of our net cash provided by operating activities, investing activities and financing activities for the periods indicated:
Year Ended December 31, | |||||||
(in thousands) |
| 2020 |
| 2021 | |||
Net cash provided by operating activities | $ | 753,382 | 709,752 | ||||
Net cash used in investing activities | (219,231) | (233,242) | |||||
Net cash used in financing activities | (534,746) | (477,150) | |||||
Net decrease in cash and cash equivalents | $ | (595) | (640) | ||||
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Year Ended December 31, 2020 Compared to Year Ended December 31, 2021
Operating Activities. Net cash provided by operating activities was $753 million and $710 million for the years ended December 31, 2020 and 2021, respectively. The decrease in net cash provided by operating activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily the result of lower water handling revenues, higher interest expense and general and administrative expense and increased cash used for working capital, excluding income tax receivable, between periods, partially offset by (i) higher gathering and processing revenues, (ii) lower direct operating expense and facility idling costs and (iii) decreased income tax refunds between periods.
Investing Activities. Net cash flows used in investing activities was $219 million and $233 million for the years ended December 31, 2020 and 2021, respectively. The increase in cash flows used in investing activities was primarily due to (i) a $29 million increase in additions to our gathering system, (ii) a $7 million increase in additions to our water handling system and (iii) $1 million increase in proceeds from excess pipe inventory sales, partially offset by a $23 million decrease in investments made in unconsolidated affiliates between periods.
Financing Activities. Net cash used in financing activities was $535 million and $477 million for the years ended December 31, 2020 and 2021, respectively. Net cash used in financing activities for the year ended December 31, 2021 included: (i) issuance of the 2029 Notes of $750 million; (ii) repayment of the 2024 Notes of $667 million, which includes the redemption premium at 102.688% of par, (iii) total dividends to our common stockholders and preferred stockholders of $472 million; (iv) $66 million in net payments on the Credit Facility; and (v) $17 million in deferred financing costs payments associated with the issuance of the 2029 Notes and the senior secured revolving credit facility amendment. Net cash used in financing activities for the year ended December 31, 2020 included: (i) issuance of the 2026 Notes of $550 million; (ii) total dividends to our common stockholders and preferred stockholders of $590 million; (iii) $346 million in net payments on the Credit Facility; (iv) $125 million (net of $8 million reflected in the cash flows provided by operating activities related to the accretion of fair value) paid to Antero Resources for the fair value of contingent acquisition consideration at the date of acquisition; (v) $25 million of common stock repurchases; and (vi) $6 million in deferred financing costs payments associated with the issuance of the 2026 Notes.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2020 for a discussion of the cash flows for the year ended December 31, 2019 compared to the year ended December 31, 2020.
Capital Investments
Our capital expenditures for the year ended December 31, 2021 were $262 million, including $217 million for gathering and compression infrastructure, $43 million for water infrastructure and $2 million for the Joint Venture.
The Board approved a 2022 capital budget with a range of $275 million to $300 million, which includes growth capital supporting the increased volumes expected from Antero Resources’ drilling partnership in addition to its maintenance capital program for 2022. Our capital budgets may be adjusted as business conditions warrant. If natural gas, NGLs and oil prices decline to levels below acceptable levels or costs increase to levels above acceptable levels, Antero Resources could choose to defer a significant portion of its budgeted capital expenditures until later periods. As a result, we may also defer a significant portion of our budgeted capital expenditures to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in Antero Resources’ development plans, changes in prices, availability of financing, acquisition costs, industry conditions, the timing of regulatory approvals, success or lack of success in Antero Resources’ drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.
Debt Agreements
Credit Facility
Antero Midstream Partners, as borrower (the “Borrower”), an indirect, wholly owned subsidiary of Antero Midstream Corporation, has a senior secured revolving credit facility with a consortium of banks. On October 26, 2021, we entered into an amended and restated senior secured revolving credit facility, the New Credit Facility. The New Credit Facility provides for borrowing under either Adjusted Term Secured Overnight Financing Rate (“SOFR”) or the Base Rate (as each term is defined in the New Credit Facility).
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The New Credit Facility has lender commitments of $1.25 billion and matures on October 26, 2026; provided that if on November 17, 2025 any of the 2026 Notes are outstanding, the New Credit Facility will mature on such date. As of December 31, 2021, we had $547 million of borrowings and no letters of credit outstanding under the New Credit Facility.
We have a choice of borrowing at Adjusted Term SOFR or at the base rate. Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable (i) with respect to base rate loans, quarterly and (ii) with respect to SOFR Loans, the last day of each Interest Period (as defined below); provided that if any Interest Period for a SOFR Loan exceeds three months, interest will be payable on the respective dates that fall every three months after the beginning of such Interest Period. SORF Loans bear interest at a rate per annum equal to the rate for SOFR rate loans for three or six months (the “Interest Period”) plus an applicable margin ranging from 150 to 250 basis points (subject to certain exceptions), depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month SOFR Rate loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points (subject to certain exceptions) depending on the leverage ratio then in effect.
The Credit Facility is guaranteed by our subsidiaries and is secured by mortgages on substantially all of Antero Midstream Partners’ and its subsidiaries’ properties. The New Credit Facility contains restrictive covenants that may limit our ability to, among other things:
| ● | incur additional indebtedness; |
| ● | sell assets; |
| ● | make loans to others; |
| ● | make investments and acquisitions; |
| ● | enter into mergers; |
| ● | make certain restricted payments; |
| ● | incur liens; and |
| ● | engage in certain other transactions without the prior consent of the lenders. |
The Credit Facility also requires us to maintain the following financial ratios (subject to certain exceptions):
| ● | a consolidated interest coverage ratio, which is the ratio of our consolidated EBITDA to its consolidated current interest charges of at least 2.5 to 1.0 at the end of each fiscal quarter; |
| ● | a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 5.00 to 1.00 at the end of each fiscal quarter; provided that, at our election (the “Financial Covenant Election”), the consolidated total leverage ratio shall be no more than 5.25 to 1.0; and |
| ● | after a Financial Covenant Election, a consolidated senior secured leverage ratio covenant rather than the consolidated total leverage ratio covenant, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.75 to 1.0. |
We were in compliance with the applicable covenants and ratios as of December 31, 2021.
See Note 10—Long-Term Debt to the unaudited condensed consolidated financial statements for more information on our Credit Facility.
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Senior Notes
The following table summarizes the material terms of our senior unsecured notes as of December 31, 2021:
| 2026 Notes | 2027 Notes | 2028 Notes | 2029 Notes | |||||||||
Outstanding principal (in thousands) | $ | 550,000 | $ | 650,000 | $ | 650,000 | $ | 750,000 | |||||
Interest rate | 7.875 | % | 5.75 | % | 5.75 | % | 5.375 | % | |||||
Maturity date | May 15, 2026 | March 1, 2027 | January 15, 2028 | June 15, 2029 | |||||||||
Interest payment dates | May 15, Nov. 15 | Mar. 1, Sept. 1 | Jan. 15, July 15 | Jun. 15, Dec. 15 | |||||||||
Make-whole redemption date (1) | May 15, 2025 | March 1, 2025 | January 15, 2026 | June 15, 2026 | |||||||||
| (1) | On or after these dates, we may redeem the applicable series of senior notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. Prior to such date, we may, in certain circumstances, redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes. |
See Note 10—Long-Term Debt to the consolidated financial statements for more information on our senior notes.
Non-GAAP Financial Measures
We use Adjusted EBITDA as an important indicator of our performance. We define Adjusted EBITDA as net income before net interest expense, income tax expense, depreciation, impairment, accretion of asset retirement obligations, equity-based compensation, excluding equity in earnings of unconsolidated affiliates, amortization of customer relationships, loss on early extinguishment of debt and loss on asset sale 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.
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.
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The following table represents a reconciliation of our Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods presented:
Year Ended December 31, | |||||||
(in thousands) |
| 2020 |
| 2021 | |||
Reconciliation of Net Income (Loss) to Adjusted EBITDA: |
| ||||||
Net income (loss) | $ | (122,527) | 331,617 | ||||
Interest expense, net | 147,007 | 175,281 | |||||
Income tax expense (benefit) | (55,688) | 117,123 | |||||
Depreciation expense | 108,790 | 108,790 | |||||
Amortization of customer relationships | 70,672 | 70,672 | |||||
Equity-based compensation | 12,778 | 13,529 | |||||
Impairment | 673,640 | 5,042 | |||||
Accretion of asset retirement obligations | 180 | 460 | |||||
Equity in earnings of unconsolidated affiliates | (86,430) | (90,451) | |||||
Distributions from unconsolidated affiliates | 98,858 | 118,990 | |||||
Loss on early extinguishment of debt | — | 21,757 | |||||
Loss on asset sale | 2,929 | 3,628 | |||||
Adjusted EBITDA | $ | 850,209 | 876,438 | ||||
Critical Accounting Policies and Estimates
The following discussion relates to the critical accounting policies and estimates for both the Company and our predecessor, AMGP. The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2—Summary of Significant Accounting Policies to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Fair Value Measurement
The FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and sets forth disclosure requirements about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that we estimate would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.
Business Combination
We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill. For acquisitions, management engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than
53
one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the acquisition date. An adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment. Acquisition-related costs are expensed as incurred in connection with each business combination.
We accounted for the Transactions under the acquisition method of accounting and estimated the fair value of assets acquired and liabilities assumed at March 12, 2019. In connection with the Transactions, the Company, among other things, issued shares of common stock valued at the closing market price of the common shares at the effective time of the Transactions, which was a Level 1 measurement.
We used the discounted cash flow approach, which is an income statement technique, to estimate the fair value of the customer relationships and investments in unconsolidated affiliates using a weighted-average cost of capital of 14.1%, which is based on significant inputs not observable in the market, and thus represents a Level 3 measurement within the fair value hierarchy. We also used this approach in combination with the cost approach to estimate the fair value of property and equipment whereby certain property and equipment was adjusted for recent purchases of similar items, economic and functional obsolescence, location, normal useful lives and capacity (if applicable). To estimate the fair value of the long-term debt, we used Level 2 market data inputs.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. We test goodwill for impairment annually in the fourth quarter and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. The fair value is calculated using the expected present value of future cash flows method. Significant assumptions used in the cash flow forecasts include future net operating margins, future volumes, discount rates and future capital requirements. If the fair value of the reporting unit is less than the carrying value, including goodwill, the excess of the book value over the fair value of goodwill is charged to net income as an impairment expense.
We utilized a combination of approaches to estimate the fair value of our assets including the discounted cash flow approach, comparable company method and the cost approach, whereby certain property and equipment was adjusted for recent purchases of similar items, economic and functional obsolescence, location, normal useful lives and capacity (if applicable). We performed our fourth quarter of 2019 and first quarter of 2020 quantitative analysis using a weighted-average cost of capital of 10.0% and 18.0%, respectively, which is based on significant inputs not observable in the market, and thus represents a Level 3 measurement within the fair value hierarchy.
Property and Equipment
Property and equipment primarily consists of gathering pipelines, compressor stations and the Clearwater Facility. We evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are calculated using the expected present value of future cash flows method. Significant assumptions used in the cash flow forecasts include future net operating margins, future volumes, discount rates and future capital requirements.
We utilized a discounted cash flow approach to estimate the fair value of our assets. We performed our first quarter of 2020 quantitative analysis using a weighted-average cost of capital of 19.0%, which is based on significant inputs not observable in the market, and thus represents a Level 3 measurement within the fair value hierarchy.
Contingent Acquisition Consideration
In connection with our September 2015 acquisition of certain water treatment assets, we agreed to pay Antero Resources (a) $125 million in cash if we delivered 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if we delivered 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. This contingent consideration liability was valued based on Level 3 inputs related to the expected average volumes and weighted average cost of capital and was recorded at the time of such acquisition in accordance with accounting guidance for business combinations. In January 2020, Antero Midstream Partners paid Antero Resources $125 million and, as of December 31, 2020, no additional contingent acquisition consideration was earned.
54
General and Administrative and Equity-Based Compensation Costs
General and administrative costs are charged or allocated to us based on the nature of the expenses and are allocated based on our proportionate share of Antero Resources’ gross property and equipment, capital expenditures and labor costs, as applicable. These allocations are based on estimates and assumptions that management believes are reasonable.
Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Estimating the fair value of each award requires management to apply judgment.
Equity-based compensation expenses that are subject to allocation as described in “—Principal Components of our Cost Structure,” are allocated to us based on our proportionate share of Antero Resources’ labor costs. These allocations are based on estimates and assumptions that management believes are reasonable.
New Accounting Pronouncements
Income Taxes
In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes. This ASU removes certain exceptions to the general principles in ASC 740, Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods after December 15, 2020. We adopted this ASU on January 1, 2021, and it did not have a material impact on our consolidated financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Risk
Our gathering and compression and water services agreements with Antero Resources provide for fixed-fee and cost of service fee structures, and we intend to continue to pursue additional fixed-fee or cost of service fee opportunities with Antero Resources and third parties in order to avoid direct commodity price exposure. However, to the extent that our future contractual arrangements with Antero Resources or third parties do not provide for fixed-fee or cost of service fee structures, we may become subject to commodity price risk. We are subject to commodity price risks to the extent that they impact Antero Resources’ development program and production and therefore our gathering, compression and water handling volumes. We cannot predict to what extent our business would be impacted by lower commodity prices and any resulting impact on Antero Resources’ operations.
Interest Rate Risk
Our primary exposure to interest rate risk results from outstanding borrowings under the Credit Facility, which has a floating interest rate. We do not currently, but may in the future, hedge the interest on portions of our borrowings under the Credit Facility from time-to-time in order to manage risks associated with floating interest rates. As of December 31, 2021, we had $547 million of borrowings and no letters of credit outstanding under the Credit Facility. A 1.0% increase in the Credit Facility interest rate would have resulted in an estimated $6 million increase in interest expense for the year ended December 31, 2021.
Credit Risk
We are dependent on Antero Resources as our primary customer, and we expect to derive substantially all of our revenues from Antero Resources for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Antero Resources’ production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and operating results.
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’
55
business would be impacted if conditions in the energy industry were to continue to deteriorate, nor can we estimate the impact such conditions would have on Antero Resources’ ability to execute its drilling and development program or to perform under our agreements. Any material non-payment or non-performance by Antero Resources could adversely affect our revenues and operating results and our ability to return capital to stockholders.
Item 8. Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page F-2 of this Annual Report on Form 10-K and are incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2021 at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Our internal control over financial reporting includes those policies and procedures that:
(i) | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets; |
(ii) | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and |
(iii) | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements. |
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect all misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
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Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control—Integrated Framework in 2013, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2021.
The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 in this Annual Report on Form 10-K.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers, and Corporate Governance
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Stockholders.
Code of Ethics
We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of our Corporate Code of Business Conduct and Ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and other persons performing similar functions by posting such information in the “Governance” subsection of our website at www.anteromidstream.com.
Item 11. Executive Compensation
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related STOCKHOLDER Matters
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Stockholders.
Item 13. Certain Relationships and Related Transactions and Director Independence
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Stockholders.
Item 14. Principal Accountant Fees and Services
Our independent registered accounting firm is
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Stockholders.
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PART IV
Item 15. Exhibit and Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
The consolidated financial statements are listed on the Index to Financial Statements to this Annual Report on Form 10-K beginning on page F-1.
(a)(3) Exhibits.
Exhibit | Description of Exhibit |
2.1 | |
3.1 | |
3.2 | |
3.3 | |
3.4 | |
4.1 | |
4.2 | |
4.3 | |
4.4 | |
4.5 | |
4.6 |
58
4.7 | |
4.8 | |
4.9 | |
4.10 | |
4.11 | |
10.1 | |
10.2 | |
10.3 | |
10.4** | |
10.5 | |
10.6 | |
10.7 | |
10.8 | |
10.9 | |
10.10 |
59
10.11 | |
10.12† | |
10.13† | |
10.14† | |
10.15† | |
10.16† | |
10.17† | |
10.18† | |
10.19† | |
10.20† | |
10.21 | |
21.1* | |
23.1* | |
31.1* | |
31.2* | |
32.1* | |
32.2* |
60
101* | The following financial information from this Form 10-K of Antero Midstream Corporation for the year ended December 31, 2021, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text. |
104* | Cover Page Interactive Data File (embedded within the Inline XBRL document). |
The exhibits marked with the asterisk symbol (*) are filed or furnished with this Annual Report on Form 10-K.
** | Portions of this exhibit have been omitted pursuant to a request for confidential treatment. |
† | Management contract or compensatory plan or arrangement |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ANTERO MIDSTREAM CORPORATION | |
By: | /s/ BRENDAN E. KRUEGER |
Brendan E. Krueger | |
Chief Financial Officer, Vice President – Finance and Treasurer | |
Date: | February 16, 2022 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Signature |
| Title |
| Date | ||||
Chairman of the Board, Director, | ||||||||
/s/ PAUL M. RADY | President and Chief Executive Officer | February 16, 2022 | ||||||
Paul M. Rady | (principal executive officer) | |||||||
Chief Financial Officer, | ||||||||
/s/ BRENDAN E. KRUEGER | Vice President – Finance and Treasurer | February 16, 2022 | ||||||
Brendan E. Krueger | (principal financial officer) | |||||||
/s/ SHERI L. PEARCE | Vice President – Accounting and Chief Accounting Officer | February 16, 2022 | ||||||
Sheri L. Pearce | (principal accounting officer) | |||||||
/s/ MICHAEL N. KENNEDY | Director and Senior Vice President – Finance | February 16, 2022 | ||||||
Michael N. Kennedy | ||||||||
/s/ PETER A. DEA | Director | February 16, 2022 | ||||||
Peter A. Dea | ||||||||
/s/ W. HOWARD KEENAN, JR. | Director | February 16, 2022 | ||||||
W. Howard Keenan, Jr. | ||||||||
/s/ DAVID H. KEYTE | Director | February 16, 2022 | ||||||
David H. Keyte | ||||||||
/s/ BROOKS J. KLIMLEY | Director | February 16, 2022 | ||||||
Brooks J. Klimley | ||||||||
/s/ JANINE J. MCARDLE | Director | February 16, 2022 | ||||||
Janine J. McArdle | ||||||||
/s/ JOHN C. MOLLENKOPF | Director | February 16, 2022 | ||||||
John C. Mollenkopf | ||||||||
/s/ ROSE M. ROBESON | Director | February 16, 2022 | ||||||
Rose M. Robeson |
62
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |
Audited Historical Consolidated Financial Statements as of December 31, 2020 and 2021 and for the Years Ended December 31, 2019, 2020 and 2021 | |
F-2 | |
F-4 | |
Consolidated Statements of Operations and Comprehensive Income (Loss) | F-5 |
Consolidated Statements of Partners’ Capital and Stockholders’ Equity | F-6 |
F-7 | |
F-8 |
F-1
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors
Antero Midstream Corporation:
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying consolidated balance sheets of Antero Midstream Corporation and subsidiaries (the Company) as of December 31, 2020 and 2021, the related consolidated statements of operations and comprehensive income (loss), partners’ capital and stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control –Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021 based on criteria established in Internal Control –Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
F-2
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Lease classification for ongoing modifications to the gathering and compression assets
As discussed in Note 7 to the consolidated financial statements, the Company determined that the gathering and compression agreement with Antero Resources Corporation is an operating lease. The Company continues to expand its gathering and compression system to serve its customer and, as a result, the minimum volume commitments and the lease payments increase for the expanded system. The increases in volume commitments and lease payments are modifications of the agreement that require evaluation of the lease classification.
We identified the evaluation of lease classification for ongoing modifications to the gathering and compression assets as a critical audit matter. The evaluation of lease classification for these modified leases, including evaluating the economic life as a key estimate, requires significant judgment.
The primary procedures we performed to address this critical audit matter included the following. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s process for identifying lease modifications and evaluating lease classification for those modifications, including controls related to the review and approval of the Company’s lease modifications and the Company’s evaluation of the lease classification. We evaluated the Company’s accounting memoranda and documentation underlying the accounting conclusions reached, including application of relevant accounting guidance in regard to the modification accounting and subsequent lease classification. We evaluated the economic life used in the determination of lease classification by comparing it to relevant industry publications. We evaluated fixed assets that are placed in service for new minimum volume commitments which would require reassessment of the lease.
/s/ KPMG LLP
We have served as the Company’s auditor since 2016.
Denver, Colorado
February 16, 2022
F-3
ANTERO MIDSTREAM CORPORATION
Consolidated Balance Sheets
(In thousands, except per share amounts)
December 31, | |||||||
| 2020 |
| 2021 |
| |||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | | — | ||||
Accounts receivable–Antero Resources | | | |||||
Accounts receivable–third party | | | |||||
Income tax receivable | | | |||||
Other current assets | | | |||||
Total current assets | | | |||||
Property and equipment, net | | | |||||
Investments in unconsolidated affiliates | | | |||||
Deferred income tax asset | | — | |||||
Customer relationships | | | |||||
Other assets, net | | | |||||
Total assets | $ | | | ||||
Liabilities and Stockholders' Equity | |||||||
Current liabilities: | |||||||
Accounts payable–Antero Resources | $ | | | ||||
Accounts payable–third party | | | |||||
Accrued liabilities | | | |||||
Other current liabilities | | | |||||
Total current liabilities | | | |||||
Long-term liabilities: | |||||||
Long-term debt | | | |||||
Deferred income tax liability | — | | |||||
Other | | | |||||
Total liabilities | | | |||||
Stockholders' Equity: | |||||||
Preferred stock, $ | |||||||
Series A non-voting perpetual preferred stock; | |||||||
Common stock, $ | | | |||||
Additional paid-in capital | | | |||||
Accumulated deficit | ( | ( | |||||
Total stockholders' equity | | | |||||
Total liabilities and stockholders' equity | $ | | | ||||
See accompanying notes to consolidated financial statements.
F-4
ANTERO MIDSTREAM CORPORATION
Consolidated Statements of Operations and Comprehensive Income (Loss)
(In thousands, except per share amounts)
Year Ended December 31, | ||||||||||
| 2019 |
| 2020 |
| 2021 |
| ||||
Revenue: |
|
|
| |||||||
Gathering and compression–Antero Resources | $ | | | | ||||||
Water handling–Antero Resources | | | | |||||||
Water handling–third party | | — | | |||||||
Amortization of customer relationships | ( | ( | ( | |||||||
Total revenue | | | | |||||||
Operating expenses: | ||||||||||
Direct operating | | | | |||||||
General and administrative (including $ | | | | |||||||
Facility idling | | | | |||||||
Depreciation | | | | |||||||
Impairment of property and equipment | | | | |||||||
Impairment of goodwill | | | — | |||||||
Impairment of customer relationships | | — | — | |||||||
Accretion of asset retirement obligations | | | | |||||||
Accretion and change in fair value of contingent acquisition consideration | | — | — | |||||||
Loss on asset sale | — | | | |||||||
Total operating expenses | | | | |||||||
Operating income (loss) | ( | ( | | |||||||
Other income (expense): | ||||||||||
Interest expense, net | ( | ( | ( | |||||||
Equity in earnings of unconsolidated affiliates | | | | |||||||
Loss on early extinguishment of debt | — | — | ( | |||||||
Total other expense | ( | ( | ( | |||||||
Income (loss) before income taxes | ( | ( | | |||||||
Income tax benefit (expense) | | | ( | |||||||
Net income (loss) and comprehensive income (loss) | $ | ( | ( | | ||||||
Net income (loss) per share–basic | $ | ( | ( | | ||||||
Net income (loss) per share–diluted | $ | ( | ( | | ||||||
Weighted average common shares outstanding: | ||||||||||
Basic | | | | |||||||
Diluted | | | | |||||||
See accompanying notes to consolidated financial statements.
F-5
ANTERO MIDSTREAM CORPORATION
Consolidated Statements of Partners’ Capital and Stockholders’ Equity
(In thousands)
Common | |||||||||||||||||||||||||
| Shares |
|
|
|
|
|
|
|
| ||||||||||||||||
Representing | |||||||||||||||||||||||||
Limited | Additional | ||||||||||||||||||||||||
Partner | Series B | Preferred | Common Stock | Paid-In | Accumulated | Total | |||||||||||||||||||
Interests | Unitholders | Stock | Shares | Amount | Capital | Deficit | Equity | ||||||||||||||||||
Balance at December 31, 2018 | $ | ( | | — | — | — | — | — | | ||||||||||||||||
Distributions to unitholders | ( | ( | — | — | — | — | — | ( | |||||||||||||||||
Net loss and comprehensive loss pre-acquisition | ( | — | — | — | — | — | — | ( | |||||||||||||||||
Equity-based compensation pre-acquisition | | — | — | — | — | — | — | | |||||||||||||||||
Exchange of common shares for shares of common stock and cash consideration paid | | ( | — | | | | — | | |||||||||||||||||
Issuance of Series A non-voting perpetual preferred stock | — | — | — | — | — | — | — | — | |||||||||||||||||
Dividends to stockholders | — | — | — | — | — | ( | — | ( | |||||||||||||||||
Equity-based compensation post-acquisition | — | — | — | — | — | | — | | |||||||||||||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes | — | — | — | | | ( | — | ( | |||||||||||||||||
Repurchases and retirement of common stock | — | — | — | ( | ( | ( | — | ( | |||||||||||||||||
Net loss and comprehensive loss post-acquisition | — | — | — | — | — | — | ( | ( | |||||||||||||||||
Balance at December 31, 2019 | — | — | — | | | | ( | | |||||||||||||||||
Dividends to stockholders | — | — | — | — | — | ( | — | ( | |||||||||||||||||
Equity-based compensation | — | — | — | — | — | | — | | |||||||||||||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes | — | — | — | | | ( | — | ( | |||||||||||||||||
Repurchases and retirement of common stock | — | — | — | ( | ( | ( | — | ( | |||||||||||||||||
Net loss and comprehensive loss | — | — | — | — | — | — | ( | ( | |||||||||||||||||
Balance at December 31, 2020 | — | — | — | | $ | | | ( | | ||||||||||||||||
Dividends to stockholders | — | — | — | — | — | ( | — | ( | |||||||||||||||||
Equity-based compensation | — | — | — | — | — | | — | | |||||||||||||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes | — | — | — | | | ( | — | ( | |||||||||||||||||
Net income and comprehensive income | — | — | — | — | — | — | | | |||||||||||||||||
Balance at December 31, 2021 | $ | — | — | — | | $ | | | ( | | |||||||||||||||
See accompanying notes to consolidated financial statements.
F-6
ANTERO MIDSTREAM CORPORATION
Consolidated Statements of Cash Flows
(In thousands)
Year Ended December 31, | ||||||||||
| 2019 |
| 2020 |
| 2021 |
| ||||
Cash flows provided by (used in) operating activities: |
|
|
|
| ||||||
Net income (loss) | $ | ( | ( | | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||
Depreciation | | | | |||||||
Accretion and change in fair value of contingent acquisition consideration | | | | |||||||
Payment of contingent consideration in excess of acquisition date fair value | — | ( | — | |||||||
Impairment | | | | |||||||
Deferred income tax expense (benefit) | ( | ( | | |||||||
Equity-based compensation | | | | |||||||
Equity in earnings of unconsolidated affiliates | ( | ( | ( | |||||||
Distributions from unconsolidated affiliates | | | | |||||||
Distributions from Antero Midstream Partners LP, prior to the Transactions | | — | — | |||||||
Amortization of customer relationships | | | | |||||||
Amortization of deferred financing costs | | | | |||||||
Settlement of asset retirement obligations | — | ( | ( | |||||||
Loss on asset sale | — | | | |||||||
Loss on early extinguishment of debt | — | — | | |||||||
Changes in assets and liabilities: | ||||||||||
Accounts receivable–Antero Resources | | | ( | |||||||
Accounts receivable–third party | | | | |||||||
Income tax receivable | — | ( | | |||||||
Other current assets | ( | | | |||||||
Accounts payable–Antero Resources | ( | | | |||||||
Accounts payable–third party | ( | | | |||||||
Income taxes payable | ( | — | — | |||||||
Accrued liabilities | | ( | ( | |||||||
Net cash provided by operating activities | | | | |||||||
Cash flows provided by (used in) investing activities: | ||||||||||
Additions to gathering systems and facilities | ( | ( | ( | |||||||
Additions to water handling systems | ( | ( | ( | |||||||
Investments in unconsolidated affiliates | ( | ( | ( | |||||||
Cash received on acquisition of Antero Midstream Partners LP | | — | — | |||||||
Cash consideration paid to Antero Midstream Partners LP unitholders | ( | — | — | |||||||
Cash received in asset sale | — | | | |||||||
Change in other assets | | | — | |||||||
Change in other liabilities | ( | — | — | |||||||
Net cash used in investing activities | ( | ( | ( | |||||||
Cash flows provided by (used in) financing activities: | ||||||||||
Dividends to stockholders | ( | ( | ( | |||||||
Dividends to preferred stockholders | ( | ( | ( | |||||||
Distributions to Series B unitholders | ( | — | — | |||||||
Repurchases of common stock | ( | ( | — | |||||||
Issuance of senior notes | | | | |||||||
Redemption of senior notes | — | — | ( | |||||||
Payments of deferred financing costs | ( | ( | ( | |||||||
Repayments on bank credit facilities, net | ( | ( | ( | |||||||
Payment of contingent acquisition consideration | — | ( | — | |||||||
Employee tax withholding for settlement of equity compensation awards | ( | ( | ( | |||||||
Other | ( | ( | ( | |||||||
Net cash used in financing activities | ( | ( | ( | |||||||
Net decrease in cash and cash equivalents | ( | ( | ( | |||||||
Cash and cash equivalents, beginning of period | | | | |||||||
Cash and cash equivalents, end of period | $ | | | — | ||||||
Supplemental disclosure of cash flow information: | ||||||||||
Cash paid during the period for interest | $ | | | | ||||||
Cash received (paid) during the period for income taxes | $ | ( | | | ||||||
Increase (decrease) in accrued capital expenditures and accounts payable for property and equipment | $ | ( | ( | | ||||||
See accompanying notes to consolidated financial statements.
F-7
(1) Organization
Antero Midstream Corporation was originally formed as Antero Resources Midstream Management LLC in 2013 to become the general partner of Antero Midstream Partners LP (“Antero Midstream Partners”). On May 4, 2017, Antero Resources Midstream Management LLC 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 Corporation was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream Corporation (the “Merger”) and (iii) Antero Midstream Corporation exchanged (the “Series B Exchange” and, together with the Conversion, the Merger and the other transactions pursuant to by 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
Antero Midstream is a growth-oriented midstream company formed to own, operate and develop midstream energy infrastructure primarily to service Antero Resources and its production and completion activity in the Appalachian Basin. The Company’s assets consist of gathering pipelines, compressor stations, interests in processing and fractionation plants and water handling assets. Antero Midstream provides midstream services to Antero Resources under long-term contracts.
The Company’s gathering and compression assets comprise of high and low pressure gathering pipelines, compressor stations and processing and fractionation plants that collect and process natural gas and NGLs from Antero Resources’ wells in the Appalachian Basin. The Company’s water handling assets include
Antero Midstream also has a
The Company’s corporate headquarters is located in Denver, Colorado.
(2) Summary of Significant Accounting Policies
(a) | Basis of Presentation |
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, these consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2020 and 2021, and the results of the Company’s operations and its cash flows for the years ended December 31, 2019, 2020 and 2021. The Company has no items of other comprehensive income (loss); therefore, net income (loss) is equal to comprehensive income (loss).
F-8
Certain costs of doing business incurred and charged to the Company by Antero Resources have been reflected in the accompanying consolidated financial statements. These costs include general and administrative expenses provided to the Company by Antero Resources in exchange for:
● business services, such as payroll, accounts payable and facilities management;
● corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy; and
● employee compensation, including equity-based compensation.
Transactions between the Company and Antero Resources have been identified in the consolidated financial statements (see Note 6—Transactions with Affiliates).
(b) | Principles of Consolidation |
The accompanying consolidated financial statements include (i) for the period prior to March 13, 2019, the accounts of AMGP and its consolidated subsidiaries, which did not include Antero Midstream Partners and its subsidiaries, and (ii) for the period beginning on March 13, 2019, the accounts of Antero Midstream Corporation and its consolidated subsidiaries, including Antero Midstream Partners and its subsidiaries, which were acquired in the Transactions. See Note 3—Business Combination. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements.
Prior to the Transactions on March 12, 2019, AMGP had determined that Antero Midstream Partners was a variable interest entity (“VIE”) for which AMGP was not the primary beneficiary and therefore did not consolidate. AMGP concluded that Antero Resources was the primary beneficiary of Antero Midstream Partners and Antero Resources consolidated its financial results. Antero Resources was the primary beneficiary based on its power to direct the activities that most significantly impacted Antero Midstream Partners’ economic performance and its obligations to absorb losses or receive benefits of Antero Midstream Partners that would be significant to Antero Midstream Partners. Antero Resources owned approximately
AMGP’s ownership of the non-economic general partner interest in Antero Midstream Partners prior to the Transactions provided AMGP with significant influence over Antero Midstream Partners, but not control over the decisions that most significantly impacted the economic performance of Antero Midstream Partners. AMGP’s indirect ownership of the IDRs of Antero Midstream Partners prior to the Transactions entitled AMGP to receive cash distributions from Antero Midstream Partners when distributions exceeded certain target amounts. AMGP’s ownership of these interests prior to the Transactions did not require AMGP to provide financial support to Antero Midstream Partners. AMGP obtained these interests upon its formation for no consideration. Therefore, AMGP had no cost basis and classified its investment in Antero Midstream Partners as a long term investment. Prior to the Transactions, AMGP’s share of Antero Midstream Partner’s earnings were a result of AMGP’s ownership of the IDRs was accounted for using the equity method of accounting. AMGP recognized distributions earned from Antero Midstream Partners as “Equity in earnings of unconsolidated affiliates” on its statement of operations in the period in which they were earned and were allocated to AMGP’s capital account. AMGP’s long-term interest in the IDRs on the balance sheet was recorded in “Investment in unconsolidated affiliates.” The ownership of the general partner interests and IDRs did not provide AMGP with any claim to the assets of Antero Midstream Partners other than the balance in its Antero Midstream Partners capital account. Income related to the IDRs was recognized as earned and increased AMGP’s capital account and equity investment. When these distributions were paid to AMGP, they reduced its capital account and its equity investment in Antero Midstream Partners.
Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero Midstream’s ownership interest, representation on the Board of Directors and participation in the policy-making decisions of equity method investees. Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows. When the Company records its proportionate share of net income, it increases equity income in the statements of operations and comprehensive income (loss) and the
F-9
carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the balance sheet.
The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities).
(c) | Revenue Recognition |
The Company provides gathering, compression and water handling services under fee-based contracts primarily based on throughput or at cost plus a margin. Certain of these contracts contain operating leases of the Company’s assets under GAAP. Under these arrangements, the Company receives fees for gathering, compression and water handling services. The revenue the Company earns from these arrangements is directly related to (i) in the case of natural gas gathering and compression, the volumes of metered natural gas that it gathers, compresses and delivers to natural gas compression sites or other transmission delivery points, (ii) in the case of fresh water services, the quantities of fresh water delivered to its customers for use in their well completion operations, (iii) in the case of wastewater treatment services performed by the Company prior to idling of the Clearwater Facility (as defined below) in September 2019, the quantities of wastewater treated for its customers, (iv) in the case of other fluid handling services provided by third parties, the third-party costs the Company incurs plus
(d) | Use of Estimates |
The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent liabilities. Items subject to estimates and assumptions include the useful lives of property and equipment, the valuation of assets and liabilities acquired from Antero Midstream Partners, evaluating impairments of long-lived assets, goodwill and intangible assets, as well as the valuation of accrued liabilities and deferred and current income taxes, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.
(e) | Cash and Cash Equivalents |
The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
(f) | Property and Equipment |
Property and equipment primarily consists of gathering pipelines, compressor stations and the wastewater treatment facility and related landfill (collectively, the “Clearwater Facility”) previously used for the disposal of salt therefrom, other flowback and produced water facilities; and water handling pipelines and facilities stated at historical cost less accumulated depreciation, amortization and impairment. The Company capitalizes construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred.
Depreciation of property and equipment is computed using the straight-line method over the estimated useful lives and salvage values of assets. The depreciation of fixed assets recorded under operating lease agreements is included in depreciation expense. Uncertainties that may impact these estimates of useful lives include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions and supply and demand for the Company’s services in the areas in which it operates. When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable.
Amortization of landfill airspace consists of the amortization of landfill capital costs, including those that have been incurred and capitalized and estimated future costs for landfill development and construction, and the amortization of asset retirement costs
F-10
arising from landfill final capping, closure and post-closure obligations. Amortization expense is recorded on a units-of-consumption basis, applying cost as a rate per-cubic yard. The rate per-cubic yard is calculated by dividing each component of the amortizable basis of the landfill by the number of cubic yards needed to fill the corresponding asset’s airspace. Landfill capital costs and closure and post-closure asset retirement costs are generally incurred to support the operation of the landfill over its entire operating life and are, therefore, amortized on a per-cubic yard basis using a landfill’s total airspace capacity. Estimates of disposal capacity and future development costs are created using input from independent engineers and internal technical teams and are reviewed at least annually.
The Company evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs and discount rates typical of third-party market participants, which is a Level 3 fair value measurement. The Company recognized an impairment with respect to the Clearwater Facility during the year ended December 31, 2019. See Note 4—Clearwater Facility Idling. The Company recognized a $
(g) | Asset Retirement Obligations |
The Company’s asset retirement obligations include its obligation to close, maintain and monitor landfill cells and support facilities. After the landfill is certified closed, the Company must continue to maintain and monitor the landfill for a post-closure period, which generally extends for
Asset retirement obligations are recorded for water impoundments and wastewater pits when an abandonment date is identified. The Company records the fair value of its water impoundment and wastewater pit retirement obligations as liabilities in the period in which the regulatory obligation to retire a specific asset is triggered. The fair value is based on the total reclamation costs of the assets. Retirement obligations are increased each year to reflect the passage of time by accreting the balance at the weighted average credit-adjusted risk-free rate that is used to calculate the recorded liability, with accretion charged to direct costs. Actual cash expenditures to perform remediation activities reduce the retirement obligation liabilities as incurred. After initial measurement, asset retirement obligations are adjusted at the end of each period to reflect changes, if any, in the estimated future cash flows underlying the obligation. Water impoundments and wastewater pit retirement assets are capitalized as the related retirement obligations are incurred, and are amortized on a straight-line basis until reclamation. As of December 31, 2020 and 2021, the Company has $
The Company is under no legal obligations, neither contractually nor under the doctrine of promissory estoppel, to restore or dismantle its gathering pipelines, compressor stations, water delivery pipelines, flowback and produced water facilities and the Clearwater Facility upon abandonment. See Note 4—Clearwater Facility Idling.
(h) | Litigation and Other Contingencies |
A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of our accruals and related disclosures. The ultimate amount of losses, if any, may differ from these estimates.
F-11
The Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time a remediation feasibility study or an evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.
As of December 31, 2020 and 2021, the Company had not recorded any liabilities for litigation, environmental or other contingencies.
(i) | Equity-Based Compensation |
The Company’s consolidated financial statements include equity-based compensation costs related to awards granted by its own plans, as in place before and after the Transactions, as well as costs allocated by Antero Resources for grants made prior to the Transactions. Costs allocated from Antero Resources are offset to additional paid in capital on the consolidated balance sheet. See Note 6—Transactions with Affiliates for additional information regarding Antero Resources’ allocation of expenses to the Company. For awards granted under its own plan, the Company recognizes compensation cost related to all equity-based awards in the financial statements based on the estimated grant date fair value. The Company is authorized to grant various types of equity-based compensation awards, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit (“RSU”) awards, dividend equivalent awards and other types of awards. The grant date fair values of such awards are determined based on the type of award and may utilize market prices on the date of grant, Black-Scholes option-pricing model, Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of equity-based award. Compensation cost is recognized ratably over the applicable vesting or service period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. See Note 12—Equity-Based Compensation and Cash Awards.
(j) | Income Taxes |
The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss and charitable contribution carryforwards and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. The Company regularly reviews its tax positions in each significant taxing jurisdiction during the process of evaluating its tax provision. The Company makes adjustments to its tax provision when: (i) facts and circumstances regarding a tax position change, causing a change in management’s judgment regarding that tax position; and/or (ii) a tax position is effectively settled with a tax authority at a differing amount.
In March 2020, the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted. The CARES Act allows corporations with net operating losses (“NOLs”) incurred in 2018, 2019 and 2020 to carry back such NOLs to each of the five years preceding the year of the NOLs, beginning with the earliest year in which there was taxable income, and claim an income tax refund in the applicable carryback years. As a result of this NOLs carryback provision in the CARES Act, the Company was able to recognize an income tax refund receivable in March 2020 of $
(k) | Fair Value Measures |
The Financial Accounting Standards Board (the “FASB”) ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given
F-12
to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.
The carrying values on the consolidated balance sheet of the Company’s cash and cash equivalents, accounts receivable—Antero Resources, accounts receivable—third party, other current assets, accounts payable—Antero Resources, accounts payable—third party, accrued liabilities and, other current liabilities approximate fair values due to their short-term maturities. The assets and liabilities of Antero Midstream Partners were recorded at fair value as of the acquisition date, March 12, 2019 (see Note 3—Business Combination). Additionally, the Company uses certain valuation techniques in performing its annual goodwill impairment test described below and in determining the fair value of property and equipment, both of which were subject to impairment write downs during the years ended December 31, 2019 and 2020.
(l) | Investments in Unconsolidated Affiliates |
The Company uses the equity method to account for its investments in companies if the investment provides the Company with the ability to exercise significant influence over, but not control of, the operating and financial policies of the investee. The Company’s consolidated net income includes the Company’s proportionate share of the net income or loss of such companies. The Company’s judgment regarding the level of influence over each equity method investee includes considering key factors such as the Company’s ownership interest, representation on the Board of Directors and participation in policy-making decisions of the investee and material intercompany transactions. See Note 16—Investments in Unconsolidated Affiliates.
(m) | Business Combinations |
The Company recognizes and measures the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill. For acquisitions, management engages an independent valuation specialist, as applicable, to assist with the determination of fair value of the assets acquired, liabilities assumed and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, the Company will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the acquisition date. An adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment. Acquisition-related costs are expensed as incurred in connection with each business combination. See Note 3—Business Combination.
(n) | Goodwill and Intangible Assets |
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment annually in the fourth quarter and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. The fair value is calculated using the expected present value of future cash flows method. Significant assumptions used in the cash flow forecasts include future net operating margins, future volumes, discount rates and future capital requirements. If the fair value of the reporting unit is less than the carrying value, including goodwill, the excess of the book value over the fair value of goodwill is charged to net income as an impairment expense.
Amortization of intangible assets with definite lives is calculated using the straight-line method, which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. Intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible asset may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. As of March 31, 2020, the Company’s goodwill was fully impaired. See Note 4—Clearwater Facility Idling and Note 5—Goodwill and Intangibles.
(o) | Treasury Share Retirement |
The Company periodically retires treasury shares acquired through share repurchases and returns those shares to the status of
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authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated deficit. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares outstanding, to the balance of additional paid-in capital as of retirement.
(p) | Recently Adopted Accounting Standard |
In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes. This ASU removes certain exceptions to the general principles in ASC 740, Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods after December 15, 2020. The Company adopted this ASU on January 1, 2021, and it did not have a material impact on the Company’s consolidated financial statements.
(3) Business Combination
On March 12, 2019, AMGP and Antero Midstream Partners completed the Transactions. The Transactions have been accounted for using the acquisition method of accounting with Antero Midstream Corporation identified as the acquirer of Antero Midstream Partners.
The components of the fair value of consideration transferred are as follows (in thousands):
Fair value of shares of AM common stock issued (1) |
| $ | | |
Cash | | |||
Total fair value of consideration transferred | $ | |
| (1) | The fair value of each share of AM common stock issued in connection with the Transactions was determined to be $ |
The final purchase price allocation of the Transactions are summarized in the table below. The fair value of assets acquired and liabilities assumed at March 12, 2019 were as follows (in thousands):
Cash and cash equivalents |
| $ | | |
Accounts receivable–Antero Resources | | |||
Accounts receivable–third party | | |||
Other current assets | | |||
Property and equipment, net | | |||
Investments in unconsolidated affiliates | | |||
Customer relationships | | |||
Other assets, net | | |||
Total assets acquired | | |||
Accounts payable–Antero Resources | | |||
Accounts payable–third party | | |||
Accrued liabilities | | |||
Other current liabilities | | |||
Long-term debt | | |||
Contingent acquisition consideration | | |||
Other liabilities | | |||
Total liabilities assumed | | |||
Net assets acquired, excluding goodwill | | |||
Goodwill | | |||
Net assets acquired | $ | |
All customer relationships are subject to amortization, which is recognized over a weighted-average period of
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remaining economic life of the relationship as of the acquisition date.
The purchase price allocation resulted in the recognition of $
The Company’s financial statements include $
(4) Clearwater Facility Idling
On September 18, 2019, the Company commenced a strategic evaluation of the Clearwater Facility at which time, such facility was idled. The Company expects the facility to be idled for the foreseeable future. Accordingly, the Company performed an impairment analysis of the facility and determined: (i) to reduce the carrying value of the facility to its estimated salvage value, which included the land associated with the Clearwater Facility; (ii) the fair value of the goodwill assigned to the wastewater treatment reporting unit was less than its carrying value resulting in an impairment charge to goodwill; and (iii) the customer relationships intangible asset was impaired. Additionally, during the year ended December 31, 2020, the Company determined that the carrying value of the landfill was no longer recoverable resulting in an impairment charge to property and equipment.
The following table shows the impairment charges related to the Clearwater Facility, which also reflect the final purchase price allocation of the Transactions:
| Year Ended December 31, | |||||||||
(in thousands) | 2019 | 2020 | 2021 | |||||||
Impairment of property and equipment |
| $ | | |
| — | ||||
Impairment of goodwill | | — | — | |||||||
Impairment of customer relationships | | — | — | |||||||
Total impairment expense | $ | | | — | ||||||
The Company incurred $
(5) Goodwill and Intangibles
(a) | Goodwill |
The Company evaluates goodwill for impairment annually during the fourth quarter and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its carrying amount. Significant assumptions used to estimate the reporting units’ fair value include the discount rate as well as estimates of future cash flows, which are impacted primarily by commodity prices and producer customers’ development plans (which impact volumes and capital requirements).
During the third quarter of 2019, the Company incurred impairment charges of $
During the fourth quarter of 2019, the Company incurred impairment charges of $
During the first quarter of 2020, the Company performed an interim impairment analysis of the goodwill due to changes in Antero Resources’ drilling plans as a result of the decline in commodity prices. As a result of this evaluation, the Company impaired all remaining goodwill of $
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The changes in the carrying amount of goodwill by reportable segment were as follows:
Gathering and | Water |
| ||||||||
(in thousands) | Processing | Handling | Total |
| ||||||
Goodwill as of December 31, 2018 | $ | — | — | — | ||||||
Goodwill acquired(1) | | | | |||||||
Impairment of goodwill | — | ( | ( | |||||||
Goodwill as of December 31, 2019 |
| | — | | ||||||
Impairment of goodwill | ( | — | ( | |||||||
Goodwill as of December 31, 2020 | $ | — | — | — | ||||||
| (1) | See Note 3—Business Combination. |
(b) | Customer Relationships Intangibles |
All customer relationships are subject to amortization and will be amortized over a weighted-average period of
The changes in the carrying amount of customer relationships were as follows (in thousands):
Customer relationships as of December 31, 2018 |
| $ | — | |
Customer relationships acquired(1) | | |||
Amortization of customer relationships | ( | |||
Impairment of customer relationships | ( | |||
Customer relationships as of December 31, 2019 | | |||
Amortization of customer relationships | ( | |||
Customer relationships as of December 31, 2020 | | |||
Amortization of customer relationships | ( | |||
Customer relationships as of December 31, 2021 | $ | |
| (1) | See Note 3—Business Combination. |
Future amortization expense is as follows (in thousands):
Year ending December 31, 2022 | $ | | ||
Year ending December 31, 2023 | | |||
Year ending December 31, 2024 | | |||
Year ending December 31, 2025 | | |||
Year ending December 31, 2026 | | |||
Thereafter | | |||
Total | $ | |
(6) Transactions with Affiliates
(a) | Revenues |
Substantially all revenues earned in the years ended December 31, 2019, 2020 and 2021 were earned from Antero Resources, under various agreements for gathering and compression and water handling services. Revenues earned from gathering and processing services consists of lease income.
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(b) | Accounts receivable–Antero Resources and Accounts payable–Antero Resources |
Accounts receivable—Antero Resources represents amounts due from Antero Resources, primarily related to gathering and compression services and water handling services. Accounts payable—Antero Resources represents amounts due to Antero Resources for general and administrative and other costs.
(c) | Allocation of Costs Charged by Antero Resources |
The employees supporting the Company’s operations are concurrently employed by Antero Resources and the Company. Direct operating expense includes costs charged to the Company of $
(7) Revenue
All of the Company’s gathering and compression revenues are derived from an operating lease agreement, and all of the Company’s water handling revenues are derived from service contracts with customers. The Company currently earns substantially all of its revenues from Antero Resources.
(a) | Gathering and Compression |
Pursuant to the gathering and compression agreement with Antero Resources, Antero Resources has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to the Company for gathering and compression services except for acreage subject to third-party commitments or pre-existing dedications. The Company also has an option to gather and compress natural gas produced by Antero Resources on any additional acreage it acquires during the term of the agreement outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. In December 2019, the Company and Antero Resources agreed to extend the initial term of the gathering and compression 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 at certain points during such time. For years ended December 31, 2020 and 2021, Antero Resources earned $
Under the gathering and compression agreement, the Company receives a low pressure gathering fee, a high pressure gathering fee and a compression fee, in each case subject to annual CPI-based adjustments, or a cost of service fee, at the Company’s election when such assets are placed in-service. In addition, the agreement stipulates that the Company receives a reimbursement for the actual cost of (i) electricity used at its compressor stations where the compression services are provided based on a compression fee and (ii) operating expenses for all services provided for a cost of service fee.
The Company determined that the gathering and compression agreement is an operating lease as Antero Resources obtains substantially all of the economic benefit of the asset and has the right to direct the use of the asset. The gathering system is an identifiable asset within the gathering and compression agreement, and it consists of underground low pressure pipelines that generally connect and deliver gas from specific well pads to compressor stations to compress the gas before delivery to underground high pressure pipelines that transport the gas to a third-party pipeline or plant. The gathering system is considered a single lease due to the interrelated network of the assets. When a modification to the gathering and compression agreement occurs, the Company reassesses the classification of this lease. The Company accounts for its lease and non-lease components as a single lease component as the lease
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component is the predominant component. The non-lease components consist of operating, oversight and maintenance of the gathering system, which are performed on time-elapsed measures.
The gathering and compression agreement includes certain fixed fee provisions. If and to the extent Antero Resources requests that the Company construct new low pressure lines, high pressure lines and/or compressor stations, the gathering and compression agreement contains options at the Company’s election for either (i) minimum volume commitments that require Antero Resources to utilize or pay for
The Company recognizes lease income from its minimum volume commitments and cost of service fees under its gathering and compression agreement on a straight-line basis. Additional variable operating lease income is earned when volumes in excess of the minimum volume commitments are delivered under the contract. The Company recognizes variable lease income when low pressure volumes are delivered to a compressor station, compression volumes are delivered to a high pressure line and high pressure volumes are delivered to a processing plant or transmission pipeline. Minimum volume commitments for high pressure gathering capacity and compression capacity are aggregated such that there is a single minimum volume commitment for the respective service each month. The Company invoices the customer the month after each service is performed, and payment is due in the same month. The Company is not party to any leases that have not commenced.
Minimum future lease cash flows to be received by the Company under the gathering and compression agreement as of December 31, 2021 are as follows (in thousands):
Year ending December 31, 2022 | $ | | ||
Year ending December 31, 2023 | | |||
Year ending December 31, 2024 | | |||
Year ending December 31, 2025 | | |||
Year ending December 31, 2026 | | |||
Thereafter | | |||
Total | $ | |
(b) | Water Handling |
The Company is party to a water services agreement with Antero Resources, whereby the Company provides certain water handling services to Antero Resources within an area of dedication in defined service areas in West Virginia and Ohio. Upon completion of the initial term in 2035, the water services agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either the Company or Antero Resources on or before the
The Company satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the hydration unit of a specified well pad, other fluid handling services have been completed or prior to the idling of the Clearwater Facility in September 2019, when the wastewater volumes were delivered to the Clearwater Facility. The Company invoices the customer the month after water services are performed, and payment is due in the same month. For services contracted through third-party providers, the Company’s performance obligation is satisfied when the service to be performed by the third-party provider has been completed. The Company invoices the customer after the third-party provider billing is received, and payment is
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due in the same month.
Transaction Price Allocated to Remaining Performance Obligations
The Company’s service contract with Antero Resources has a term greater than one year. As such, the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s service contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The remainder of the Company’s service contracts, which relate to contracts with third parties, are short-term in nature with a contract term of one year or less. Accordingly, the Company is exempt from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of
Contract Balances
Under the Company’s service contracts, the Company invoices customers after its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s service contracts do not give rise to contract assets or liabilities.
(c) | Disaggregation of Revenue |
In the following table, revenue is disaggregated by type of service and type of fee and is identified by the reportable segment to which such revenues relate. For more information on reportable segments, see Note 17—Reportable Segments.
Year Ended December 31, | ||||||||||||
(in thousands) | 2019 | 2020 | 2021 |
| Reportable Segment |
| ||||||
Type of service | ||||||||||||
Gathering—low pressure | $ | | | | Gathering and Processing (1) | |||||||
Gathering—low pressure rebate | — | ( | ( | Gathering and Processing (1) | ||||||||
Gathering—high pressure | | | | Gathering and Processing (1) | ||||||||
Compression | | | | Gathering and Processing (1) | ||||||||
Fresh water delivery | | | | Water Handling | ||||||||
Wastewater treatment | | — | — | Water Handling | ||||||||
Other fluid handling | | | | Water Handling | ||||||||
Amortization of customer relationships (2) | ( | ( | ( | Gathering and Processing | ||||||||
Amortization of customer relationships (2) | ( | ( | ( | Water Handling | ||||||||
Total | $ | | | | ||||||||
Type of contract | ||||||||||||
Per Unit Fixed Fee | $ | | | | Gathering and Processing (1) | |||||||
Gathering—low pressure rebate | — | ( | ( | Gathering and Processing (1) | ||||||||
Per Unit Fixed Fee | | | | Water Handling | ||||||||
Cost plus | | | | Water Handling | ||||||||
Cost of service fee | | | | Water Handling | ||||||||
Amortization of customer relationships (2) | ( | ( | ( | Gathering and Processing | ||||||||
Amortization of customer relationships (2) | ( | ( | ( | Water Handling | ||||||||
Total | $ | | | | ||||||||
| (1) | Revenue related to the gathering and processing segment is classified as lease income related to the gathering system. |
| (2) | Fair value of customer contracts acquired as part of the Transactions discussed in Note 3—Business Combination. |
As of December 31, 2020 and 2021, the Company’s receivables from its contracts with customers and operating leases were $
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(8) Property and Equipment
The Company’s investment in property and equipment is as follows:
Estimated | December 31, | ||||||||
(in thousands) |
| Useful Lives |
| 2020 | 2021 |
| |||
Land |
| n/a |
| $ | |
| | ||
Gathering systems and facilities | 40- | | | ||||||
Permanent buried pipelines and equipment | 7- | | | ||||||
Surface pipelines and equipment | 1- | | | ||||||
Heavy trucks and equipment | 3- | | | ||||||
Above ground storage tanks | 5- | | | ||||||
Construction-in-progress | n/a |
| | | |||||
Total property and equipment | | | |||||||
Less accumulated depreciation | ( | ( | |||||||
Property and equipment, net | $ | | | ||||||
| (1) | Gathering systems and facilities are recognized as a single-leased asset with |
During the years ended December 31, 2019 and 2020, the Company recorded impairment expense of $
(9) Income Taxes
Income tax expense (benefit) consisted of the following:
Year Ended December 31, | ||||||||||
(in thousands) |
| 2019 |
| 2020 |
| 2021 |
| |||
Current income tax expense (benefit) | $ | ( | ( | — | ||||||
Deferred income tax expense (benefit) | ( | ( | | |||||||
Total income tax expense (benefit) | $ | ( | ( | | ||||||
Income tax expense differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of
Year Ended December 31, |
| |||||||||
(in thousands) |
| 2019 |
| 2020 |
| 2021 | ||||
Federal income tax expense (benefit) | $ | ( | ( | | ||||||
State income tax expense (benefit), net of federal benefit | ( | ( | | |||||||
Non-deductible equity-based compensation | | | | |||||||
Charitable contributions | ( | — | — | |||||||
Carryback of NOLs | — | ( | — | |||||||
Other | ( | ( | ( | |||||||
Total income tax expense (benefit) | $ | ( | ( | | ||||||
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Deferred income taxes reflect the impact of temporary differences between assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets as follows:
December 31, | |||||||
(in thousands) |
| 2020 |
| 2021 |
| ||
Deferred tax assets: |
|
| |||||
NOL carryforwards | $ | | | ||||
Investment in Antero Midstream Partners | | — | |||||
Equity-based compensation | | | |||||
Charitable contributions | | | |||||
Total deferred tax asset | | | |||||
Deferred tax liabilities: | |||||||
Investment in Antero Midstream Partners | — | | |||||
Total deferred tax liability | — | | |||||
Net deferred tax asset (liability) | $ | | ( | ||||
In assessing the realizability of all of the deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the Company’s temporary differences become deductible. Management considers projected future taxable income and tax planning strategies in making this assessment. Based upon the projections of future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will realize the benefits of these deductible differences and thus has not recorded a valuation allowance.
The calculation of the Company’s tax assets and liabilities involve uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. As of December 31, 2020 and 2021, the Company did not have any uncertain tax positions.
As of December 31, 2021, the Company has U.S. federal and state NOL carryforwards before the effect of income taxes of $
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(10) Long-Term Debt
The Company’s long-term debt is as follows:
December 31, | |||||||
(in thousands) | 2020 | 2021 | |||||
Credit Facility (a) |
| $ | |
| | ||
| — | ||||||
| | ||||||
| | ||||||
| | ||||||
— | | ||||||
Total principal | | | |||||
Unamortized debt premiums | | | |||||
Unamortized debt issuance costs | ( | ( | |||||
Total long-term debt | $ | | | ||||
(a) | Credit Facility |
Antero Midstream Partners, an indirect, wholly owned subsidiary of Antero Midstream Corporation, as borrower (the “Borrower”), has a senior secured revolving credit facility with a consortium of banks, the Credit Facility. On October 26, 2021, the Company entered into an amended and restated senior secured revolving credit facility, the New Credit Facility. As of December 31, 2021, lender commitments under the New Credit Facility were $
The Credit Facility contains certain covenants including restrictions on indebtedness, and requirements with respect to leverage and interest coverage ratios. The Credit Facility permits distributions to the holders of the Borrower’s equity interests in accordance with the cash distribution policy, provided that no event of default exists or would be caused thereby, and only to the extent permitted by the Borrower’s organizational documents. The Borrower was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2020 and 2021.
The Prior Credit Facility provides for borrowing under either the Base Rate or the Eurodollar Rate (as each term is defined in the Prior Credit Facility), and the New Credit Facility provides for borrowing under either Adjusted Term Secured Overnight Financing Rate (“SOFR”) or the Base Rate (as each term is defined in the New Credit Facility). Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable with respect to (i) base rate loans, quarterly and (ii) Eurodollar Rate Loans or SOFR Loans at the end of the applicable interest period if three months (or shorter, if applicable), or every three months if the applicable interest period is longer than three months. Interest is payable at a variable rate based on (i) LIBOR or the base rate, determined by election at the time of borrowing, plus an applicable margin rate under the Prior Credit Facility or (ii) SOFR or the base rate, determined by election at the time of borrowing, plus an applicable margin rate under the New Credit Facility. Interest at the time of borrowing is determined with reference to the Borrower’s then-current leverage ratio subject to certain exceptions. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from
As of December 31, 2020, the Borrower had outstanding borrowings under the Prior Credit Facility of $
(b) |
On September 13, 2016, Antero Midstream Partners and its wholly owned subsidiary, Finance Corp (together with Antero Midstream Partners, the “Issuers”), issued $
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The Issuers redeemed all $
(c) |
On November 10, 2020, the Issuers issued $
(d) |
On February 25, 2019, the Issuers issued $
(e)
On June 28, 2019, the Issuers issued $
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decline, the holders of the 2028 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the 2028 Notes at a price equal to
(f) |
On June 8, 2021, the Issuers issued $
(g) | Senior Notes Guarantors |
The Company and each of the Company’s wholly owned subsidiaries (except for the Issuers) has fully and unconditionally guaranteed the 2024 Notes, 2026 Notes, 2027 Notes, 2028 Notes and 2029 Notes (collectively the “Senior Notes”). In the event a guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a Restricted Subsidiary (as defined in the applicable indenture governing the series of Senior Notes) of the Issuer or the sale of all or substantially all of its assets) and whether or not the guarantor is the surviving entity in such transaction to a person that is not an Issuer or a Restricted Subsidiary of an Issuer, such guarantor will be released from its obligations under its guarantee if the sale or other disposition does not violate the covenants set forth in the indentures governing the applicable Senior Notes.
In addition, a guarantor will be released from its obligations under the applicable indenture and its guarantee, upon the release or discharge of the guarantee of other indebtedness under a credit facility that resulted in the creation of such guarantee, except a release or discharge by or as a result of payment under such guarantee; if the Issuers designate such subsidiary as an unrestricted subsidiary and such designation complies with the other applicable provisions of the indenture governing the applicable Senior Notes or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the applicable Senior Notes.
During the years ended December 31, 2019, 2020 and 2021, all of the Company’s assets and operations are attributable to the Issuers and its guarantors.
(11) Accrued Liabilities
Accrued liabilities consisted of the following items:
December 31, | |||||||
(in thousands) |
| 2020 |
| 2021 |
| ||
Capital expenditures | $ | | | ||||
Operating expenses | | | |||||
Interest expense | | | |||||
Ad valorem taxes | | | |||||
Other | | | |||||
Total accrued liabilities | $ | | | ||||
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(12) Equity-Based Compensation and Cash Awards
| (a) | Summary of Equity-Based Compensation |
The Company’s equity-based compensation prior to the Transactions includes costs related to (i) the Antero Midstream GP LP Long-Term Incentive Plan (“AMGP LTIP”) and (ii) the Series B Units. The Company’s equity-based compensation after the Transactions includes (i) costs related to the Exchanged B Units (as defined below), (ii) costs allocated to Antero Midstream by Antero Resources for grants made prior to the Transactions pursuant to the Antero Resources Corporation Long-Term Incentive Plan (the “AR LTIP”) and (iii) costs related to the Antero Midstream Corporation Long-Term Incentive Plan (the “AM LTIP”). Antero Midstream’s equity-based compensation expense is included in general and administrative expenses, and recorded as a credit to the applicable classes of equity.
AMGP LTIP
On April 17, 2017, Antero Midstream GP LP adopted the AMGP LTIP pursuant to which certain non-employee directors of Antero Midstream GP LP’s general partner and certain officers, employees and consultants of Antero Resources were eligible to receive awards representing equity interests in Antero Midstream GP LP. Expenses related to these awards were recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures were accounted for as they occurred by reversing the expense previously recognized for awards that were forfeited during the period. In connection with the Transactions, the AMGP LTIP was terminated on March 12, 2019.
Series B Units and Exchanged B Units
As of December 31, 2018, IDR Holdings had
Upon Closing of the Transactions, each Series B Unit, vested and unvested, was exchanged for
The Company accounted for the Series B Exchange as a share-based payment modification under FASB ASC Topic 718, Stock Compensation. On March 12, 2019, which is the modification date, the Company determined the estimated fair value of the unvested Series B Unit awards using a Monte Carlo simulation using various assumptions including a floor equity value of $
AR LTIP
Equity-based compensation expense allocated to Antero Midstream from Antero Resources was $
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allocated to it for awards issued under the AR LTIP.
AM LTIP
Effective March, 12, 2019, the Board of Directors of Antero Midstream Corporation (the “Board”) adopted the AM LTIP under which awards may be granted to employees, directors and other service providers of the Company and its affiliates. The AM LTIP provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalents, other stock-based awards, cash awards and substitute awards. The terms and conditions of the awards granted are established by the compensation committee of the Board. The Company is authorized to grant up to
The Company’s equity-based compensation expense, by type of award, is as follows:
Year Ended December 31, | ||||||||||
(in thousands) | 2019 | 2020 | 2021 | |||||||
Series B Units and Exchanged B Units | $ | | — | — | ||||||
Stock options (1) | | — | — | |||||||
Restricted stock units (1) | | | | |||||||
Performance share units (1) | | | | |||||||
Equity awards issued to directors | | | | |||||||
Total expense | $ | | | | ||||||
| (1) | Amounts include equity-based compensation expense allocated to the Company by Antero Resources. |
| (b) | Restricted Stock Unit Awards |
As part of the Transactions, each of the unvested outstanding phantom units granted under the Antero Midstream Partners Long Term Incentive Plan was assumed by the Company and converted into
RSU awards vest subject to the satisfaction of service requirements. Expense related to each RSU award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are based on the closing price of the Company’s common stock on the date of the grant.
A summary of the RSU awards activity, which includes the Converted AM RSU Awards, is as follows:
Weighted Average | ||||||
Number | Grant Date | |||||
| of Units |
| Fair Value |
| ||
Total AM LTIP RSUs awarded and unvested—December 31, 2020 | | $ | | |||
Granted | | | ||||
Vested | ( | | ||||
Forfeited | ( | | ||||
Total AM LTIP RSUs awarded and unvested—December 31, 2021 | | $ | | |||
As of December 31, 2021, unamortized expense of $
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| (c) | Performance Share Unit Awards |
In 2019, the Company granted performance share units (“PSUs”) to certain of its employees and executive officers, a portion of which vest based on the Company’s actual return on invested capital (“ROIC”) (as defined in the award agreement) over a
On December 17, 2019, the compensation committee of the Board modified the terms for the ROIC PSU agreement. Accordingly, the Company accounted for the amended agreement as a share-based payment modification under ASC 718, Stock Compensation and revalued the awards as of the modification date.
A summary of PSU activity is as follows:
Weighted Average | ||||||
Number | Grant Date | |||||
| of Units |
| Fair Value | |||
Total AM LTIP PSUs awarded and unvested—December 31, 2020 | | $ | | |||
Granted | — | — | ||||
Vested | — | — | ||||
Forfeited | ( | | ||||
Total AM LTIP PSUs awarded and unvested—December 31, 2021 | | $ | | |||
As of December 31, 2021, there was $
| (d) | Cash Retention Awards |
In January 2020, the Company granted cash awards of $
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(13) Cash Distributions and Dividends
The following table details the amount of distributions and dividends paid with respect to the quarter indicated (in thousands, except per share data):
Distributions/ | |||||||||||
Distribution/ | Distributions/ | Dividends |
| ||||||||
Period |
| Record Date |
| Dividend Date |
| Dividends |
| per Share | |||
Q4 2018 | February 1, 2019 | February 21, 2019 | $ | | $ | ||||||
Q1 2019 | April 26, 2019 | May 8, 2019 | | ||||||||
* | May 15, 2019 | May 15, 2019 | | * | |||||||
Q2 2019 | July 26, 2019 | August 7, 2019 | | ||||||||
* | August 14, 2019 | September 18, 2019 | | * | |||||||
Q3 2019 | November 1, 2019 | November 13, 2019 | | ||||||||
* | November 14, 2019 | November 14, 2019 | | * | |||||||
** | December 31, 2019 | December 31, 2019 | | ** | |||||||
Total 2019 | $ | | |||||||||
Q4 2019 | January 31, 2020 | February 12, 2020 | $ | | $ | ||||||
* | February 14, 2020 | February 14, 2020 | | * | |||||||
Q1 2020 | April 30, 2020 | May 12, 2020 | | ||||||||
* | May 15, 2020 | May 15, 2020 | | * | |||||||
Q2 2020 | July 30, 2020 | August 12, 2020 | | ||||||||
* | August 14, 2020 | August 14, 2020 | | * | |||||||
Q3 2020 | October 29, 2020 | November 12, 2020 | | ||||||||
* | November 16, 2020 | November 16, 2020 | | * | |||||||
Total 2020 | $ | | |||||||||
Q4 2020 | February 3, 2021 | February 11, 2021 | $ | | $ | ||||||
* | February 16, 2021 | February 16, 2021 | | * | |||||||
Q1 2021 | April 28, 2021 | May 12, 2021 | | ||||||||
* | May 17, 2021 | May 17, 2021 | | * | |||||||
Q2 2021 | July 28, 2021 | August 11, 2021 | | ||||||||
* | August 16, 2021 | August 16, 2021 | | * | |||||||
Q3 2021 | October 27, 2021 | November 10, 2021 | | ||||||||
* | November 15, 2021 | November 15, 2021 | | * | |||||||
Total 2021 | $ | | |||||||||
* | Dividends are paid in accordance with the terms of the Series A Preferred Stock as discussed in Note 14—Equity and Earnings Per Common Share. |
** | Distributions declared on unvested Series B Units prior to the closing date of the Transactions that were paid upon the vesting date to the holders of the Exchanged B Units |
On January 12, 2022, the Board announced the declaration of a cash dividend on the shares of AM common stock of $
The Board also declared a cash dividend of $
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(14) Equity and Earnings Per Common Share
(a)Preferred Stock
The Board authorized
(b)Weighted Average Shares Outstanding
The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding:
Year Ended December 31, | ||||||||||
(in thousands) |
| 2019 | 2020 |
| 2021 |
| ||||
Basic weighted average number of shares outstanding | | | | |||||||
Add: Dilutive effect of RSUs | — | — | | |||||||
Add: Dilutive effect of PSUs | — | — | | |||||||
Add: Dilutive effect of Series A Preferred Stock | — | — | | |||||||
Diluted weighted average number of shares outstanding | | | | |||||||
Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1): | ||||||||||
RSUs | | | | |||||||
PSUs | — | | — | |||||||
Series A Preferred Shares | | | — | |||||||
(1) | The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common shares, assuming dilution because the inclusion of these awards would have been anti-dilutive. |
(c)Earnings Per Common Share
Earnings per common share—basic is computed by dividing net income (loss) attributable to Antero Midstream by the basic weighted average number of shares outstanding during the period. Earnings per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is anti-dilutive.
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Year Ended December 31, | ||||||||||
(in thousands, except per share amounts) |
| 2019 | 2020 |
| 2021 |
| ||||
Net income (loss) | $ | ( | ( | | ||||||
Less preferred stock dividends | ( | ( | ( | |||||||
Net income (loss) available to common shareholders | $ | ( | ( | | ||||||
Net income (loss) per share–basic | $ | ( | ( | | ||||||
Net income (loss) per share–diluted | $ | ( | ( | | ||||||
Weighted average common shares outstanding–basic | | | | |||||||
Weighted average common shares outstanding–diluted | | | | |||||||
(15) Fair Value Measurement
Business Combination
As the Transactions were accounted for under the acquisition method of accounting, the Company estimated the fair value of assets acquired and liabilities assumed at March 12, 2019. See Note 3—Business Combination. In connection with the Transactions, the Company, among other things, issued shares of common stock valued at the closing market price of the common shares at the effective time of the Transactions, which was a Level 1 measurement.
The Company used the discounted cash flow approach, which is an income statement technique, to estimate the fair value of the customer relationships and investments in unconsolidated affiliates using a weighted-average cost of capital of
Goodwill
The Company estimated the fair value of its assets in performing its goodwill impairment analysis. The Company utilized a combination of approaches to discounted cash flow approach, comparable company method and the market value approach. The Company used a weighted-average cost of capital of
Property and equipment
The Company estimated the undiscounted future cash flow projections to assess its property and equipment for impairment. The carrying values of certain fresh water permanent buried pipelines and equipment and fresh water surface pipelines and equipment were deemed not recoverable. As a result, the carrying values have been reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs and a discount rate typical of third-party market participants of
Contingent Acquisition Consideration
In connection with Antero Resources’ contribution of Antero Water and certain water handling assets to Antero Midstream Partners in September 2015 (the “Water Acquisition”), Antero Midstream Partners agreed to pay Antero Resources (a) $
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In January 2020, Antero Midstream Partners paid Antero Resources $
Senior Unsecured Notes
As of December 31, 2020 and 2021 the fair value and carrying value of the Company’s senior unsecured notes were as follows:
December 31, 2020 | December 31, 2021 | ||||||||||||
(in thousands) | Fair Value (1) | Carrying Value (2) | Fair Value (1) | Carrying Value (2) | |||||||||
2024 Notes | $ | | — | — | |||||||||
2026 Notes | | | | ||||||||||
2027 Notes | | | | ||||||||||
2028 Notes | | | | ||||||||||
2029 Notes | — | — | | | |||||||||
Total | $ | | | | | ||||||||
| (1) | Fair values are based on Level 2 market data inputs. |
| (2) | Carrying values are presented net of unamortized debt issuance costs and debt premiums. |
Other Assets and Liabilities
The carrying values of accounts receivable and accounts payable as of December 31, 2020 and 2021 approximated fair value because of their short-term nature. The carrying value of the amounts under the Credit Facility as of December 31, 2020 and 2021 approximated fair value because the variable interest rates are reflective of current market conditions.
(16) Investments in Unconsolidated Affiliates
(a) | Summary of Investments in Unconsolidated Affiliates |
Investment in Stonewall and MarkWest Joint Venture
The Company has a
The Company has a
The Company’s net income (loss) includes its proportionate share of the net income of the Joint Venture and Stonewall. When the Company records its proportionate share of net income, it increases equity income in the consolidated statements of operations and comprehensive income and the carrying value of that investment on its balance sheet. When distributions on the Company’s proportionate share of net income are received, they are recorded as reductions to the carrying value of the investment on the balance sheet and are classified as cash inflows from operating activities in accordance with the nature of the approach under FASB ASC Topic 230, Statement of Cash Flows. The Company uses the equity method of accounting to account for its investments in Stonewall and the Joint Venture because it exercises significant influence, but not control, over the entities. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as its ownership interest, representation on the applicable Board of Directors and participation in policy-making decisions of Stonewall and the Joint Venture.
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The following table is a reconciliation of the Company’s investments in these unconsolidated affiliates:
Total Investment | ||||||||||
MarkWest | in Unconsolidated | |||||||||
(in thousands) |
| Stonewall |
| Joint Venture |
| Affiliates | ||||
Balance as of December 31, 2019 | $ | | | | ||||||
Additional investments | — | | | |||||||
Equity in earnings of unconsolidated affiliates (1) | | | | |||||||
Distributions from unconsolidated affiliates | ( | ( | ( | |||||||
Balance as of December 31, 2020 | | | | |||||||
Additional investments | — | | | |||||||
Equity in earnings of unconsolidated affiliates (1) | | | | |||||||
Distributions from unconsolidated affiliates | ( | ( | ( | |||||||
Balance as of December 31, 2021 | $ | | | | ||||||
(1) | As adjusted for the amortization of the difference between the cost of the equity investments in Stonewall and the Joint Venture and the amount of the underlying equity in the net assets of Stonewall and the Joint Venture as of the closing date of the Transaction. |
(b)Summarized Financial Information of Unconsolidated Affiliates
The following tables present summarized financial information for the Company’s investments in unconsolidated affiliates:
Combined Balance Sheets
December 31, | |||||||
(in thousands) |
| 2020 |
| 2021 | |||
Current assets | $ | | |
| |||
Noncurrent assets | | | |||||
Total assets | $ | | | ||||
Current liabilities | $ | | | ||||
Noncurrent liabilities | | | |||||
Noncontrolling interest | | | |||||
Partners' capital | | | |||||
Total liabilities and partners' capital | $ | | | ||||
Statements of Combined Operations
Year Ended December 31, | ||||||||||
(in thousands) |
| 2019 |
| 2020 |
| 2021 | ||||
Revenues |
| $ | |
| |
| |
| ||
Operating expenses | | | | |||||||
Income from operations | | | | |||||||
Net income attributable to unconsolidated affiliates, including noncontrolling interest | | | | |||||||
Net income attributable to unconsolidated affiliates | | | | |||||||
(17) Reportable Segments
Prior to the closing of the Transactions, the Company had
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Gathering and Processing
The gathering and processing segment includes a network of gathering pipelines and compressor stations that collect and process production from Antero Resources’ wells in West Virginia and Ohio. The gathering and processing segment also includes equity in earnings from the Company’s investments in the Joint Venture and Stonewall.
Water Handling
The Company’s water handling segment includes
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Management evaluates the performance of the Company’s business segments based on operating income. Interest expense is primarily managed and evaluated on a consolidated basis.
The summarized operating results and assets of the Company’s reportable segments are as follows:
Year Ended December 31, 2019 | |||||||||||||
Gathering and | Water | Consolidated | |||||||||||
(in thousands) |
| Processing |
| Handling |
| Unallocated (1) | Total |
| |||||
Revenues: | |||||||||||||
Revenue–Antero Resources | $ | | | — | | ||||||||
Revenue–third-party | — | | — | | |||||||||
Amortization of customer relationships | ( | ( | — | ( | |||||||||
Total revenues | | | — | | |||||||||
Operating expenses: | |||||||||||||
Direct operating | | | — | | |||||||||
General and administrative | | | | | |||||||||
Facility idling | — | | — | | |||||||||
Depreciation | | | — | | |||||||||
Impairment of property and equipment | | | — | | |||||||||
Impairment of goodwill | — | | — | | |||||||||
Impairment of customer relationships | — | | — | | |||||||||
Accretion and change in fair value of contingent acquisition consideration | — | | — | | |||||||||
Accretion of asset retirement obligations | — | | — | | |||||||||
Total operating expenses | | | | | |||||||||
Operating income (loss) | $ | | ( | ( | ( | ||||||||
Equity in earnings of unconsolidated affiliates | $ | | — | — | | ||||||||
Total assets | $ | | | | | ||||||||
Additions to property and equipment | $ | | | — | | ||||||||
(1) | Certain expenses that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis. |
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Year Ended December 31, 2020 | |||||||||||||
Gathering and | Water | Consolidated | |||||||||||
(in thousands) |
| Processing |
| Handling |
| Unallocated (1) | Total |
| |||||
Revenues: | |||||||||||||
Revenue–Antero Resources | $ | | | — | | ||||||||
Amortization of customer relationships | ( | ( | — | ( | |||||||||
Total revenues | | | — | | |||||||||
Operating expenses: | |||||||||||||
Direct operating | | | — | | |||||||||
General and administrative | | | | | |||||||||
Facility idling | — | | — | | |||||||||
Depreciation | | | — | | |||||||||
Impairment of property and equipment | | | — | | |||||||||
Impairment of goodwill | | — | — | | |||||||||
Accretion of asset retirement obligations | — | | — | | |||||||||
Loss on asset sale | | | — | | |||||||||
Total operating expenses | | | | | |||||||||
Operating loss | $ | ( | ( | ( | ( | ||||||||
Equity in earnings of unconsolidated affiliates | $ | | — | — | | ||||||||
Total assets | $ | | | | | ||||||||
Additions to property and equipment | $ | | | — | | ||||||||
(1) | Certain expenses that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis. |
Year Ended December 31, 2021 | |||||||||||||
Gathering and | Water | Consolidated | |||||||||||
(in thousands) |
| Processing |
| Handling |
| Unallocated (1) | Total |
| |||||
Revenues: | |||||||||||||
Revenue–Antero Resources | $ | | | — | | ||||||||
Revenue–third-party | — | | — | | |||||||||
Amortization of customer relationships | ( | ( | — | ( | |||||||||
Total revenues | | | — | | |||||||||
Operating expenses: | |||||||||||||
Direct operating | | | — | | |||||||||
General and administrative | | | | | |||||||||
Facility idling | — | | — | | |||||||||
Depreciation | | | — | | |||||||||
Impairment of property and equipment | | | — | | |||||||||
Accretion of asset retirement obligations | — | | — | | |||||||||
Loss on asset sale | | — | — | | |||||||||
Total operating expenses | | | | | |||||||||
Operating income | $ | | | ( | | ||||||||
Equity in earnings of unconsolidated affiliates | $ | | — | | |||||||||
Total assets | $ | | | | | ||||||||
Additions to property and equipment, net | $ | | | — | | ||||||||
(1) | Certain expenses that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis. |
F-34