EDGAR 10-K Filing

Company CIK: 1623925
Filing Year: 2021
Filename: 1623925_10-K_2021_0001558370-21-001148.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
Overview
Antero Midstream Corporation was originally formed as Antero Resources Midstream Management LLC in 2013 to become the general partner of Antero Midstream Partners. On May 4, 2017, ARMM converted from a limited liability company to a limited partnership under the laws of the State of Delaware and changed its name to Antero Midstream GP LP (“AMGP”) in connection with its initial public offering. On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among AMGP, Antero Midstream Partners and certain of their affiliates (the “Simplification Agreement”), (i) AMGP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation (the “Conversion”), (ii) an indirect, wholly owned subsidiary of Antero Midstream was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream (the “Merger”) and (iii) Antero Midstream exchanged (the “Series B Exchange” and, together with the Conversion, the Merger and the other transactions pursuant to the Simplification Agreement, the “Transactions”) each issued and outstanding Series B Unit (the “Series B Units”) representing a membership interest in Antero IDR Holdings LLC (“IDR Holdings”) for 176.0041 shares of its common stock, par value $0.01 per share.
We are a growth-oriented midstream energy company formed to own, operate and develop midstream energy assets to primarily service Antero Resources’ production and completion activity. We believe that our strategically located assets and our relationship with Antero Resources have allowed us to become a leading midstream energy company serving the Appalachian Basin and present opportunities to expand our midstream services to other operators in such area. Our assets consist of gathering pipelines, compressor stations and interests in processing and fractionation plants that collect and process production from Antero Resources’ wells in the Appalachian Basin located primarily in West Virginia and Ohio. Our assets also include two independent water handling systems that deliver fresh water from the Ohio River and several regional waterways. These water handling systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilities, as well as pumping stations and impoundments to transport the fresh water throughout the pipelines. In addition, we also provide fluid handling services for flowback and produced water, including blending, storage and transportation operations, which services utilize certain of our permanent buried pipelines and surface pipelines. These operations, along with our fresh water delivery systems, support well completion and production operations for Antero Resources. These services are provided by us directly or through third-parties with which we contract.
We utilize our midstream infrastructure assets to provide gathering, compression, processing, fractionation and integrated water services, including fresh water delivery services and other fluid handling services to Antero Resources under long-term, fixed-fee contracts, limiting our direct exposure to commodity price risk. As of December 31, 2020, all of Antero Resources’ approximate 582,000 gross acres (515,000 net acres) are dedicated to us for gathering, compression and water services, except for approximately 135,000 gross acres subject to third-party gathering and compression commitments. We also own a 15% equity interest in the gathering system of Stonewall Gas Gathering LLC (“Stonewall”) and a 50% equity interest in the Joint Venture to develop processing and fractionation assets in Appalachia with MarkWest. In connection with our entry into the Joint Venture with MarkWest, we released to the Joint Venture our right to provide certain processing and fractionation services on 195,000 gross acres held by Antero Resources in the Appalachian Basin. Under its agreements with us and subject to any pre-existing dedications or other third-party commitments, Antero Resources has dedicated to us all of its current and future acreage in the Appalachian Basin for gathering and compression services and all of its acreage within defined service areas in the Appalachian Basin for water services. We also have certain rights of first offer with respect to gathering, compression, processing and fractionation services and water services for acreage located outside of the existing
dedicated areas. The gathering and compression agreement expires in 2038, and the water services agreement expires in 2035. Both agreements are subject to automatic annual renewal with rights by either party to terminate on or before the 180th day prior to the anniversary of such effective date.
In connection with our entrance into the water services agreement, we agreed to pay Antero Resources (a) $125 million in cash if we delivered 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if we delivered 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. As of December 31, 2019, we had delivered 176 million barrels of fresh water, which entitled Antero Resources to $125 million pursuant to clause (a) above. In January 2020, Antero Midstream Partners paid Antero Resources $125 million. In the three-year period ended December 31, 2020, we delivered 163 million of the 219 million barrels of fresh water, and therefore, no such payment is due to Antero Resources’ pursuant to clause (b) above. As of December 31, 2020, no additional contingent acquisition consideration is expected to be earned.
Due to the extensive geographic distribution of our water pipeline systems in both West Virginia and Ohio, we are able to provide, and have in the past provided, water delivery services to other oil and gas producers operating within and adjacent to Antero Resources’ operating area in an effort to further leverage the use of our existing system.
Operating Segments
Our operations are located in the United States and are organized into two reporting segments: (1) gathering and processing and (2) water handling. Financial information for our reporting segments is located under Note 17-Reporting Segments to our consolidated financial statements.
2020 Capital Investments
For the year ended December 31, 2020, our total capital spending was $182 million, which included $141 million of expansion capital and $41 million of maintenance capital. We spent an aggregate of $141 million for gathering and compression infrastructure. The additional gathering and compression infrastructure included 34 miles of pipelines in the Appalachian Basin. Additionally, we invested an aggregate of $41 million in water infrastructure to construct six miles of additional buried water pipelines and surface pipelines in the Appalachian Basin. We also invested $25 million in our unconsolidated affiliates.
2021 Capital Budget
During 2021, we plan to expand our existing Appalachian Basin gathering, processing and water handling infrastructure to accommodate Antero Resources’ development plans. Antero Resources announced that it plans to operate three drilling rigs and complete between 65 and 70 horizontal wells, substantially all of which are expected to be located on acreage dedicated to us. Antero Resources’ announced 2021 drilling and completion capital budget is $590 million. Our 2021 capital budget is a range of $240 million to $260 million, which includes approximately $65 million of additional growth capital supporting the increased volumes expected from Antero Resources’ drilling partnership in addition to its previously disclosed maintenance capital program for 2021.
Our Assets
Our gathering and compression assets consist of high and low pressure gathering pipelines, compressor stations and processing and fractionation plants that collect and process natural gas and NGLs from Antero Resources’ wells in West Virginia and Ohio. Our water handling assets include two independent systems that deliver fresh water from sources, including the Ohio River, local reservoirs and several regional waterways, which portions of these systems are also utilized to transport flowback and produced water. The water handling systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilities, as well as pumping stations and impoundments to transport fresh water throughout the systems used to deliver water to Antero Resources’ well completions. Our assets also include other flowback and produced water treatment facilities that we use to provide water treatment services to Antero Resources.
The following table provides information regarding our gathering and processing systems and water handling systems as of December 31, 2020:
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
3,185
As of December 31, 2020, we had the ability to store 5.7 million barrels of fresh water in 37 impoundments. Additionally, we own water blending and storage assets to support other fluid handling services that we provide to Antero Resources for well completion and production activities. We also own water treatment assets, including the Antero Clearwater Facility, waste water pits and a related landfill used for the disposal of salt therefrom (collectively, the “Clearwater Facility”), which we idled in September 2019.
Idling of the Clearwater Facility
On September 18, 2019, we commenced a strategic evaluation of the Clearwater Facility. Based on the preliminary results of our evaluation and ongoing discussions with the Clearwater Facility’s contractor, the Clearwater Facility was idled. We expect the Clearwater Facility to continue to be idled for the foreseeable future. The decision to idle the Clearwater Facility was driven by its inability to operate at its intended specifications. Accordingly, we recorded impairment charges related to the Clearwater Facility of $409 million for property and equipment, $42 million of goodwill and $12 million in customer relationships during the year ended December 31, 2019. Additionally, during the year ended December 31, 2020, we determined that the carrying value of the landfill was no longer recoverable resulting in an impairment charge to property and equipment of $7 million. See Note 4-Clearwater Facility Idling to our consolidated financial statements. During the year ended December 31, 2019 and 2020, we incurred $11 million and $15 million, respectively, in facility idling costs for the care and maintenance of the Clearwater Facility. Since idling the Clearwater Facility, we have satisfied our obligation to handle Antero Resources’ flowback and produced water through our blending operations and third parties.
Our Relationship with Antero Resources
Antero Resources has a 29.2% ownership interest in us as of December 31, 2020. Antero Resources is our most significant customer and is one of the largest producers of natural gas and NGLs in the Appalachian Basin, where it produced, on average, 3.6 Bcfe/d net (33% liquids) during 2020, an increase of 11% as compared to 2019. As of December 31, 2020, Antero Resources’ estimated net proved reserves were 17.6 Tcfe, which were comprised of 57% natural gas, 42% NGLs and 1% oil. As of December 31, 2020, Antero Resources’ drilling inventory consisted of 2,133 identified potential horizontal well locations (approximately 1,531 of which were located on acreage dedicated to us) for gathering and compression and water handling services, which provides us with significant opportunities for growth as Antero Resources’ active drilling program continues and its production increases. Antero Resources announced its 2021 drilling and completion budget is $590 million, and includes plans to operate three drilling rigs, in the Appalachian Basin. Antero Resources relies significantly on us to deliver the midstream infrastructure necessary to accommodate its production growth. For additional information regarding our contracts with Antero Resources, please read “-Operational and Managerial Arrangements with Antero Resources.”
We currently derive substantially all of our revenue from Antero Resources. Any development that materially and adversely affects Antero Resources’ operations, financial condition or market reputation could have a material adverse impact on us. Accordingly, we are indirectly subject to the business risks of Antero Resources. For additional information, please read “Item 1A. Risk Factors-Risks Related to Our Business.”
Operational and Managerial Arrangements with Antero Resources
Gathering and Compression
Pursuant to the gathering and compression agreement with Antero Resources, Antero Resources has dedicated all of its current and future acreage in West Virginia, Ohio and Pennsylvania to Antero Midstream Partners for gathering and compression except for acreage attributable to third-party commitments in effect prior to the agreement, or acreage Antero Resources acquires that is subject to pre-existing dedications. In December 2019, we and Antero Resources agreed to extend the initial term of the agreement to 2038 and established a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent Antero Resources achieves certain volumetric targets. For a discussion of Antero Resources’ existing third-party commitments
and pre-existing dedications, please read “-Antero Resources’ Existing Third-Party Commitments.” We also have an option to gather and compress natural gas produced by Antero Resources on any acreage it acquires in the future outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. Under the gathering and compression agreement, we receive a low pressure gathering fee per Mcf, a high-pressure gathering fee per Mcf and a compression fee per Mcf, in each case subject to CPI-based adjustments. If and to the extent Antero Resources requests that we construct new high pressure lines and compressor stations, the gathering and compression agreement contain options at our election for either (i) minimum volume commitments that require Antero Resources to utilize or pay for 75% and 70%, respectively, of the capacity of such new construction for 10 years or (ii) a service fee that allows us to earn a 13% rate of return on such new construction over seven years. Additional high pressure lines and compressor stations installed on our own initiative are not subject to these options. These minimum volume commitments and rate of return options on new infrastructure are intended to support the stability of our cash flows.
Antero Resources achieved all of its low pressure gathering growth incentive targets for 2020 and earned $48 million in fee reductions during the year. The following table summarizes the remaining low pressure gathering growth incentive targets for 2021 through 2023. If actual low pressure volumes are below the lowest tier for the respective calendar years, Antero Resources will not receive a reduction in low pressure gathering fees.
Low Pressure Gathering
Quarterly Fee
Volume Growth Incentive
Reduction
Targets (MMcf/d)
(in millions)
Calendar Years 2021-2023
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 per barrel in West Virginia and Ohio and all other locations for fresh water deliveries by pipeline directly to the well site. Antero Resources also agreed to pay us a fixed fee per barrel for wastewater treatment at the Clearwater Facility, which was idled in the third quarter of 2019 and we expect will remain idled for the foreseeable future. Additionally, we provide or manage other fluid handling services for well completion and production operations in Antero Resources’ operating areas. The fees for such services are all subject to CPI adjustments. In addition, we also provide fluid handling services for flowback and produced water, including blending, storage and transportation operations. These operations, along with our fresh water delivery systems, support well completion and production operations for Antero Resources. These services are provided by us directly or through third-parties with which we contract. For flowback and produced water services provided by third-parties, Antero Resources reimburses our third-party out-of-pocket costs plus 3%. For flowback and produced water services provided by us, we charge Antero Resources a cost of service fee. The initial term of the water services agreement runs to 2035.
Gas Processing and NGL Fractionation
The Joint Venture was formed in February 2017 to develop processing and fractionation assets in Appalachia. We have a right-of-first-offer agreement with Antero Resources for the provision of processing and fractionation services pursuant to which Antero Resources, subject to certain exceptions, may not procure any gas processing or NGL fractionation services with respect to its production (other than production subject to a pre-existing dedication) without first offering us the right to provide such services. For additional information, please read “-Antero Resources’ Existing Third-Party Commitments.”
Secondment and Services Agreements
Pursuant to a secondment agreement and a services agreement, Antero Resources seconds employees to us to provide operational services with respect to our assets and certain corporate, general and administrative services in exchange for
reimbursement of any direct expenses and an allocation of any indirect expenses attributable to its provision of such services. These agreements extend through 2039.
Antero Resources’ Existing Third-Party Commitments
Excluded Acreage
Antero Resources previously dedicated a portion of its acreage in the Appalachian Basin to certain third parties’ gathering and compression services. We refer to this acreage dedication as the “excluded acreage.” As of December 31, 2020, the excluded acreage consisted of approximately 135,000 of Antero Resources’ existing gross leasehold acreage, which included approximately 602 of Antero Resources’ 2,133 potential horizontal well locations. As part of its five year drilling plan, Antero Resources expects to drill most of its wells on acreage dedicated to us.
Other Commitments
In addition to the excluded acreage, Antero Resources has entered into contracts with certain third-parties that include minimum volume commitments for high pressure gathering and/or compression services. Specifically, those volume commitments consist of up to an aggregate of 450 MMcf/d on high pressure gathering pipelines and approximately 560 MMcf/d for compression services.
Acreage Dispositions
In addition to the excluded acreage and Antero Resources’ other commitments with third parties, each of the gathering and compression agreement, water services agreement and right of first offer agreement between Antero Resources and us permit Antero Resources to sell, transfer, convey, assign, grant or otherwise dispose of dedicated properties free of the dedication under such agreements, provided that the number of net acres of dedicated properties so disposed of, when added to the number of net acres of dedicated properties previously disposed of free of the dedication since the respective effective dates of the agreements, does not exceed the aggregate number of net acres of dedicated properties acquired by Antero Resources since such effective dates. Accordingly, under certain circumstances, Antero Resources may dispose of a significant number of net acres of dedicated properties free from dedication without our consent, and we have no control over the timing or extent of such dispositions.
Title to Properties
Our real property is classified into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned these lands without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses.
Seasonality
Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas end users, utilities and marketers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall, thereby smoothing demand for natural gas. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase demand for our services during the summer and winter months and decrease demand for our services during the spring and fall months.
Competition
As a result of our relationship with Antero Resources, we do not compete for the portion of Antero Resources’ existing operations for which we currently provide midstream services and will not compete for future portions of Antero Resources’ operations that are dedicated to us pursuant to: (i) our gathering and compression agreement; (ii) our water handling services agreement; and (iii) our right-of-first-offer agreement with Antero Resources for the provision of processing and fractionation
services. For a description of this contract, please read “-Our Relationship with Antero Resources-Contractual Arrangements with Antero Resources.” However, we face competition in attracting third-party volumes to our gathering and compression and water handling systems. In addition, these third parties may develop their own gathering and compression and water handling systems in lieu of employing our assets.
Regulation of Operations
Regulation of pipeline gathering services may affect certain aspects of our business and the market for our services.
Gathering Pipeline Regulation
Section 1(b) of the Natural Gas Act of 1938 (“NGA”), exempts natural gas gathering facilities from regulation by the FERC, under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of some our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility is not a gathering pipeline and the pipeline provides interstate transmission service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978 (“NGPA”). Such FERC-regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.
Unlike natural gas gathering under the NGA, there is no exemption for the gathering of crude oil or NGLs under the Interstate Commerce Act (“ICA”). Whether a crude oil or NGL shipment is in interstate commerce under the ICA depends on the fixed and persistent intent of the shipper as to the crude oil’s or NGL’s final destination, absent a break in the interstate movement. Antero Midstream believes that the crude oil and NGL pipelines in its gathering system meet the traditional tests the FERC has used to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on Antero Midstream’s crude oil and NGL pipelines depends on the shipper’s intentions and the transportation of the crude oil or NGLs outside of Antero Midstream’s system, and may change over time. If the FERC were to consider the status of an individual facility and the character of a crude oil or NGL shipment, and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by the FERC under the ICA. Such FERC regulation could decrease revenue, increase operating costs and, depending on the facility in question, could adversely affect Antero Midstream’s results of operations and cash flows. In addition, if any of Antero Midstream’s facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and civil remedies and criminal penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. States in which we operate may adopt ratable take and common purchaser statutes, which would require our gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. The regulations under these statutes may have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate may also adopt a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such regulation will be adopted and whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to state regulations.
Our gathering operations could be adversely affected should they be subject in the future to more stringent application of state regulation of rates and services. Our gathering operations also may be, or become, subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
The Energy Policy Act of 2005 (“EPAct 2005”), amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets. The FERC subsequently issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. The FERC’s anti-manipulation rules apply to intrastate sales and gathering activities only to the extent that there is a “nexus” to FERC-jurisdictional transactions. EPAct 2005 also provided the FERC with the authority to impose civil penalties of up to approximately $1 million (adjusted annually for inflation) per day per violation. In January 2021, FERC issued an order (Order No. 865) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of up to $1,307,164 per violation per day.
Pipeline Safety Regulation
Some of our gas pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), with respect to crude oil and NGLs. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). The NGPSA and HLPSA regulate safety requirements in the design, construction, operation and maintenance of natural gas, crude oil and NGL pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil, NGL and natural gas transmission pipelines in high-consequence areas or high consequence areas (“HCAs”).
The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:
● perform ongoing assessments of pipeline integrity;
● identify and characterize applicable threats to pipeline segments that could impact an HCA;
● improve data collection, integration and analysis;
● repair and remediate pipelines as necessary; and
● implement preventive and mitigating actions.
The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the act, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a series of violations. Those maximum civil penalties have increased to $218,647 per violation per day, with a maximum of $2,186,465 for a series of violations, to account for inflation. The PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations.
Following legislation enacted by Congress, PHMSA has issued or proposed regulations that either seek to impose new obligations on pipeline operations or expand existing pipeline safety requirements to previously unregulated pipelines. For example, in October 2019, PHMSA published three final rules on pipeline safety. The Enhanced Emergency Order Procedures rule (effective December 2, 2019) implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if unsafe conditions or practices, or a combination thereof, constitutes or causes an imminent hazard. The Safety of Hazardous Liquid Pipelines rule (effective July 1, 2020) expands PHMSA’s regulation of the safety of hazardous liquid pipelines by extending reporting requirements to certain hazardous liquid gravity flow and rural gathering pipelines, establishing new requirements for integrity management programs for hazardous liquid pipelines in HCAs and certain other hazardous liquid pipelines and expanding various inspection and leak detection requirements. The Safety of Gas Transmission Pipelines rule (effective July 1, 2020) requires operators of certain gas transmission pipelines to reconfirm the Maximum Allowable Operating Pressure (MAOP) of their lines and establishes a new “Moderate Consequence Area” for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting baseline assessments and incorporates industry standards and
guidelines as well as new requirements for integrity management programs. We are in the process of assessing the impact of these rules on our future costs of operations and revenue from operations, but we do not expect our operations to be affected by these new rules any differently than other similarly situated midstream companies.
PHMSA has also been working on two additional rules related to gas pipeline safety, though we cannot predict when they will be finalized. The rule entitled “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change and Other Related Amendments” is expected to adjust the repair criteria for pipelines in HCAs, create new criteria for pipelines in non-HCAs and strengthen integrity management assessment requirements. The rule entitled “Safety of Gas Gathering Pipelines” is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas.
Separately, in the Fiscal Year 2021 Omnibus Appropriations Bill, Congress directed PHMSA to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations to require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. While we cannot predict the full scope of these regulations at this time, more stringent requirements may require us to incur significant costs to maintain compliance, which may have a negative impact on our business performance and results of operations.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations.
We regularly review all existing and proposed pipeline safety requirements and work to incorporate the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above, consistent with other similarly situated midstream companies. In addition to regulatory changes, costs may be incurred if there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs and corrective action is required.
Regulation of Environmental and Occupational Safety and Health Matters
General
Our natural gas gathering and compression and water handling activities are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment, natural resources and worker safety. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
● requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way we operate resulting in additional costs to our operations;
● limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands, coastal regions or areas inhabited by endangered or threatened species;
● delaying system modification or upgrades during review of permit applications and revisions;
● requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and
● enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or regulatory requirements imposed by such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes
have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or solid waste into the environment.
The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our capital costs to construct, maintain and operate equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position, results of operations or cash flows, nor do we believe that they will affect our competitive position since the operations of our competitors are generally similarly affected. In addition, we believe that the various activities in which we are presently engaged that are subject to environmental laws and regulations are not expected to materially interrupt or diminish our operational ability to gather natural gas and provide water handling services. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. Our primary customer, Antero Resources, uses the water we deliver to it for hydraulic fracturing as part of its completion operations as does most of the U.S. onshore oil and natural gas industry. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies; however, in recent years the EPA, has asserted limited authority over hydraulic fracturing and has issued or sought to propose rules related to the control of air emissions, disclosure of chemicals used in the process and the disposal of flowback and produced water resulting from the process. Some states, including those in which we operate, have adopted and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. For example, in July 2015, the Ohio Department of Natural Resources issued final rules for horizontal drilling well-pad construction. The Ohio legislature has also adopted laws requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drilling baseline water quality sampling of certain water wells near a proposed horizontal well. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. We cannot predict whether any such federal, state or local legal restrictions relating to the hydraulic fracturing process will ever be enacted in areas where our customers operate and if so, what the effects of such restrictions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal state or local level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of water and natural gas that move through our systems, which in turn could materially adversely affect our revenues and results of operations.
Hazardous Waste
Antero Midstream and Antero Resources’ operations generate solid wastes, including small quantities of hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many oil and natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development or production of crude oil and natural gas, including residual constituents derived from those exempt wastes. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations and it is possible that certain oil and natural gas exploration and production wastes now classified as exploration and production-exempt non-hazardous waste could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customer’s operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services, increase our waste disposal costs and adversely affect our business.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of
persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Although petroleum as well as natural gas is excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations, our operations generate wastes that may be designated as hazardous substances. CERCLA authorizes the EPA, states, and, in some cases, third parties to take actions in response to releases or threatened releases of hazardous substances into the environment and to seek to recover from the classes of responsible persons the costs they incur to address the release. Under CERCLA, we could be subject to strict joint and several liabilities for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.
We currently own or lease, and may have in the past owned or leased, properties that have been used for the gathering and compression of natural gas and the gathering and transportation of oil. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by it or on or under other locations where such substances have been taken for disposal. Such petroleum hydrocarbons or wastes may have migrated to property adjacent to our owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial operations to prevent future contamination. We are not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at or implicating our facilities or operations.
Air Emissions
The federal Clean Air Act, and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various emission limits, operational limits and monitoring, reporting and recordkeeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations and potentially criminal enforcement actions. These laws are frequently subject to change. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”), for ozone from 75 to 70 parts per billion, and completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Applicable laws and regulations require pre-construction permits for the construction or modification of certain projects or facilities with the potential to emit air emissions above certain thresholds. These pre-construction permits generally require use of best available control technology (“BACT”), to limit air emissions. Several EPA new source performance standards (“NSPS”), and national emission standards for hazardous air pollutants (“NESHAP”), also apply to our facilities and operations. These NSPS and NESHAP standards impose emission limits and operational limits as well as detailed testing, recordkeeping and reporting requirements on the “affected facilities” covered by these regulations. Several of our facilities are “major” facilities requiring Title V operating permits which impose semi-annual reporting requirements.
Water Discharges
The Federal Water Pollution Control Act (the “Clean Water Act”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. In September 2015, the EPA and the Corps issued a final rule defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the U.S. (the “WOTUS rule”). However, on January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows the definition of “waters of the United States” relative to the prior 2015 rulemaking. Legal challenges to both this and prior revisions to the definition of WOTUS are ongoing, and it is possible that a new presidential administration could propose a broader interpretation of the CWA’s jurisdiction. As a result of these developments, the scope of jurisdiction under the CWA is uncertain at this time. To the extent any rule expands the scope of the CWA’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Separately, in April 2020, the federal district court for the District of Montana determined that the Corps Clean Water Act Section 404 Nationwide Permit 12 (“NWP 12”)
failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court’s order has subsequently been limited pending appeal and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts to the Nationwide Permit program. Relatedly, in response to the vacatur, the Corps reissued NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rulemaking may be subject to litigation or to further revision under the Biden Administration. While the full extent and impact of the vacatur is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and regulations provide for administrative, civil and criminal penalties for any discharges not authorized by the permit and may impose substantial potential liability for the costs of removal, remediation and damages. We believe that compliance with such permits will not have a material adverse effect on our business operations.
Occupational Safety and Health Act
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We do not believe that noncompliance with worker health and safety requirements will have a material adverse effect on our business or operations.
Endangered Species
The federal Endangered Species Act (“ESA”), provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations and have pipeline construction and maintenance projects in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (the “USFWS”), may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Moreover, as a result of a settlement, the USFWS was required to make a determination as to whether more than 250 species classified as endangered or threatened should be listed under the ESA by the completion of the agency’s 2017 fiscal year. For example, in April 2015, the USFWS listed the northern long-eared bat, whose habitat includes the areas in which we operate, as a threatened species under the ESA; however, on January 28, 2020, the U.S. District Court for the District of Columbia ordered the USFWS to reconsider its decision to list the northern long-eared bat as threatened instead of endangered. The designation of previously unprotected species as threatened or endangered, or redesignation of a threatened species as endangered, in areas where we conduct operations could cause us to incur increased costs arising from species protection measures or could result in limitations on our pipeline construction activities or the exploration and production activities of Antero Resources, any of which could have an adverse impact on our results of operations.
Climate Change
In response to findings that emissions of greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act, that, among other things, establish Prevention of Significant Deterioration (“PSD”), pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources that are already potential major sources of criteria pollutant emissions regulated under the statute. Under these regulations, facilities required to obtain PSD permits must meet BACT standards for their GHG emissions established by the states or, in some cases, by the EPA, for those emissions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that set emissions standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision
or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified and existing oil and gas facilities. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. These rules (and any additional regulations) could impose new compliance costs and permitting burdens on natural gas operations.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by President Biden and other public office representatives. These have included promises to pursue actions to limit emissions and curtail the production of oil and gas, such as through banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. Additionally, President Biden has issued executive orders recommitting the United States to the Paris Agreement and directing the federal government to begin formulating the United States’ nationally determined emissions reduction target under the agreement. The impacts of this order, and any legislation or regulation promulgated to fulfill the United States commitments under the Paris Agreement cannot be predicted at this time. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects and therefore are responsible for damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
Additionally, our access to capital may be impacted by climate change policies. Financial institutions may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, the Federal Reserve recently announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. While we cannot predict what policies may result from this, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our midstream services. Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.
Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2020, nor do we anticipate that such expenditures will be material in 2021.
Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. See “Item 3. Legal Proceedings.”
We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Human Capital
We believe that our employees and contractors are significant contributors to our past and future success, which depends on our ability to attract, retain and motivate qualified personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance.
All of our executive officers and other personnel who provide corporate, general and administrative services to our business are, when providing services to us, concurrently employed by Antero Resources and us pursuant to the terms of a services agreement. In addition, our operational personnel are seconded to us by Antero Resources pursuant to the terms of a secondment agreement and individuals are concurrently employed by Antero Resources and us during such secondment. As of December 31, 2020, approximately 522 people were concurrently employed by us and Antero Resources pursuant to these arrangements. We and Antero Resources consider our relations with these employees to be generally good.
Total Rewards
We have demonstrated a history of investing in our workforce by offering competitive salaries, wages and benefits. To foster a stronger sense of ownership and align the interests of our personnel with shareholders, we provide long-term incentive programs that include restricted stock units, performance share units and cash awards. Additionally, we offer short-term cash incentive programs which are discretionary and are based on individual and company performance factors, among others. Furthermore, we offer comprehensive benefits to our full-time employees working 30 hours or more per week. To be an employer of choice and maintain the strength of our workforce, we consistently assess the current business environment and labor market to refine our compensation and benefits programs and other resources available to our personnel. Among other benefits, these include:
● 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.
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.

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ITEM 1A. RISK FACTORS
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;
● 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. The low commodity price environment has negatively impacted natural gas producers causing some producers in the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer, including Antero Resources, is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by Antero Resources could adversely affect our business and operating results.
Also, due to our relationship with Antero Resources, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to Antero Resources’ financial condition or adverse changes in its credit ratings.
Any material limitation of our ability to access capital could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Antero Resources could negatively impact our share price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
Please see Item 1A, “Risk Factors” in Antero Resources’ Annual Report on Form 10-K for the year ended December 31, 2020 (which is not, and shall not be deemed to be, incorporated by reference herein) for a full disclosure of the risks associated with Antero Resources’ business.
Because of the natural decline in production from existing wells, our success depends, in part, on Antero Resources’ ability to replace declining production and our ability to secure new sources of natural gas from Antero Resources or third parties. Additionally, our water handling services are directly associated with Antero Resources’ well completion activities and water needs, which are largely driven by the amount of water used in completing each well. Finally, under certain circumstances, Antero Resources may dispose of acreage dedicated to us free from such dedication without our consent. Any decrease in volumes of natural gas that Antero Resources produces, any decrease in the number of wells that Antero Resources completes, or any decrease in the number of acres that are dedicated to us could adversely affect our business and operating results.
The natural gas volumes that support our gathering business depend on the level of production from wells connected to our systems, which may be less than expected and will naturally decline over time. To the extent Antero Resources reduces its development activity or otherwise ceases to drill and complete new wells, revenues for our gathering and compression and water handling services will be directly and adversely affected. Our ability to maintain water handling services revenues is substantially dependent on continued completion activity by Antero Resources or third parties over time, as well as the volumes of water used in and produced from such activity. In addition, natural gas volumes from completed wells will naturally decline and our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas from Antero Resources or third parties. The primary factors affecting our ability to obtain additional sources of natural gas include (i) the success of Antero Resources’ drilling activity in our areas of operation, (ii) Antero Resources’ ability to replace declining production, (iii) Antero Resources’ acquisition of additional acreage, including acquisitions that offset any dispositions by Antero Resources and (iv) our ability to obtain dedications of acreage from third parties. Demand for our fresh water delivery services, which make up a substantial portion of our water handling services revenues, is dependent on water used in Antero Resources’ completion activities. To the extent that Antero Resources or other fresh water delivery customers reduce the number of completion stages per well or use less water in their completions, the demand for our fresh water delivery services would be reduced.
We have no control over Antero Resources’ or other producers’ levels of development and completion activity in our areas of operation, the amount of oil and gas reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, our water handling business is dependent upon active development in our areas of operation. To maintain or increase throughput levels on our water handling systems, we must service new wells. We have no control over Antero Resources
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 $3.14 per MMBtu to a low of $1.33 per MMBtu in 2020, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $63.27 per barrel to a low of $(36.98) per barrel during the same period. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. Because Antero Resources’ production and reserves predominantly consist of natural gas (approximately 57% of equivalent proved reserves), changes in natural gas prices have significantly greater impact on Antero Resources’ financial results than oil prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, oil and NGLs at Antero Resources’ ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.
These lower prices have compelled most natural gas and oil producers, including Antero Resources, to reduce the level of exploration, drilling and production activity and capital budgets. For example, Antero Resources’ 2021 capital budget is $625 million, compared to 2019 and 2020 capital expenditures of $1.3 billion and $785 million, respectively. This will have a significant effect on our capital resources, liquidity and expected operating results. Natural gas and oil prices directly affect Antero Resources’ production. If prices remain at low levels or decrease further, our revenues, cash flows and results of operations could continue to be adversely affected. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services and cash flows.
Due to these and other factors, even if reserves are known to exist in areas served by our assets, producers have chosen and may choose in the future, not to develop those reserves. Reductions in development activity, including Antero Resources’ reduction in lateral lengths or use of water in its completions, could result in our inability to maintain the current levels of throughput on our systems or reduce the demand for our water handling services on a per well basis, which could in turn reduce our revenue and cash flows and adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of our common stock.
Finally, each of the gathering and compression agreement, water services agreement and right of first offer agreement between us and Antero Resources permits Antero Resources to sell, transfer, convey, assign, grant or otherwise dispose of dedicated properties free of the dedication under such agreements, provided that the number of net acres of dedicated properties so disposed of, when added to the number of net acres of dedicated properties previously disposed of free of the dedication since the respective effective dates of the agreements, does not exceed the aggregate number of net acres of dedicated properties acquired by Antero Resources since such effective dates. Accordingly, under certain circumstances, Antero Resources may dispose of a significant number of net acres of dedicated properties free from dedication without our consent, and we have no control over the timing or extent of such dispositions. Any such dispositions could adversely affect our business and operating results. Even if the disposed property remains dedicated to us, the goals and intention of acquiror with respect to such property may differ significantly from those of Antero Resources. For example, a subsequent owner of a property could choose to invest less capital in the development of such property or to otherwise drill fewer wells than Antero Resources. There can be no assurance that a subsequent owner of dedicated properties would choose to, or be able to, grow or maintain current rates of production from the properties, which could adversely impact us.
Business Operations
A material shut-in of production by Antero Resources or any of our other customers could adversely affect our business.
The marketing of the natural gas, NGLs and oil of our producer customers is substantially dependent upon the existence of adequate markets for their products. In response to the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in the demand for oil, natural gas and NGLs. The imbalance between the supply of and demand for these products, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices. Also as a result of this imbalance, the industry has experienced and may experience in the future storage capacity constraints with respect to oil and certain NGL products. If Antero Resources or any of our other customers are unable to sell their production or enter into additional storage arrangements on commercially reasonable terms or at all, they may be forced to temporarily shut in a portion of their production or delay or discontinue drilling and completion plans and commercial production. Although Antero Resources has not been required to temporarily shut-in a portion of its production, it may do so in the future. Production curtailments or shut-ins by our producer customers will reduce volumes flowing through our gathering and processing system. In addition, if our customers delay or discontinue drilling or completion activities, it will reduce the volumes of water that we handle. A material reduction in volumes on our systems could adversely affect our business, our revenue and cash flows and could adversely affect our ability to return capital to our stockholders through dividends and/or repurchases of shares of AM common stock.
The gathering and compression agreement includes minimum volume commitments only under certain circumstances.
The gathering and compression agreement includes minimum volume commitments only on new high pressure pipelines and compressor stations constructed subsequent to November 2014 at Antero Resources’ request. The high pressure pipelines and compressor stations that existed prior to November 2014 are not supported by minimum volume commitments from Antero Resources. There are no minimum volume commitments on the low pressure pipelines or fresh water distribution pipelines. Any decrease in the current levels of throughput on our gathering, compression and fresh water distribution systems could reduce our revenue and cash flows.
Our construction or purchase of new gathering and compression, processing, water handling or other assets may not be completed on schedule, at the budgeted cost or at all, may not operate as designed or at the expected levels, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, all of which could adversely affect our financial condition, cash flows and results of operations.
The construction of additions or modifications to our existing systems and the construction or purchase of new assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all, or they may not operate as designed or at the expected levels. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For example, the construction of our water treatment facility took longer than planned and the facility ran at operating rates below the designed capacity and did not meet certain completion milestones under the terms of the construction contract. As a result, in September 2019, we decided to idle such facility for the foreseeable future. Following such idling, we recorded aggregate non-cash impairment charges of approximately $463 million and expect to incur additional idling costs going forward. In addition, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new gathering and compression, water handling or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our financial condition and results of operations. In addition, adding to our existing assets may require us to obtain new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new natural gas supplies to our existing gathering pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
Recent action and the possibility of future action on trade by U.S. and foreign governments has increased the costs of certain equipment and materials used in the construction of our assets and has created uncertainty in global markets, which may adversely affect our income from operations and cash flows.
The construction of gathering pipelines, compressor stations, processing and fractionation facilities and water handling assets is subject to construction cost overruns due to costs and availability of equipment and materials such as steel. If third party providers of steel products essential to our capital improvements and additions are unable to obtain raw materials, including steel, at historical prices, they may raise the price we pay for such products. On March 8, 2018, the President of the United States issued two
proclamations directing the imposition of ad valorem tariffs of 25% on certain imported steel products and 10% on certain imported aluminum products from most countries, with limited exceptions. On May 31, 2018, the U.S. announced that it would also impose steel and aluminum tariffs on Canada, Mexico, and the 28 member countries of the European Union. Argentina, Australia, Brazil and South Korea implemented measures to address the impairment to U.S. national security attributable to steel and/or aluminum imports that were deemed satisfactory to the United States. On May 19, 2019, the U.S. announced that Canada and Mexico had also implemented satisfactory measures to address the threatened impairment to U.S. national security caused by steel and aluminum imports from those countries. As a result, imports of steel from Argentina, Australia, Brazil, Canada, Mexico and South Korea and aluminum from Argentina, Australia, Canada and Mexico have been exempted from the imposition of tariff-based remedies, but the United States has implemented quantitative restrictions in the form of absolute quotas for steel article imports from Argentina, Brazil and South Korea and aluminum products from Argentina, meaning that imports in excess of the allotted quota will be disallowed. In addition, effective August 13, 2018, the United States announced that it would impose a 50% ad valorem tariff on steel articles imported from Turkey, which remained in effect until May 21, 2019, at which time a 25% ad valorem tariff on steel articles imported from Turkey was reimposed, consistent with the tariff on imports from most countries. On January 24, 2020, the United States announced that an additional 25% ad valorem tariff would be imposed on certain derivative steel article imports from all countries except Argentina, Australia, Brazil, Canada, Mexico and South Korea, and that an additional 10% ad valorem tariff would be imposed on certain derivative aluminum article imports from all countries except Argentina, Australia, Canada and Mexico. On August 6, 2020, the U.S. re-imposed the 10% ad valorem tariff on imports of non-alloyed unwrought aluminum from Canada due to a surge in imports of those articles, but on October 27, 2020, retroactively reinstated Canada on the list of countries excluded from tariffs for those articles. On August 28, 2020, the U.S. announced that it would lower one of the quantitative limitations on imports of certain steel articles from Brazil for the remainder of 2020. The U.S. provided relief from these limitations in specific circumstances, namely for production activities with contracts for steel imports from Brazil during the fourth quarter of 2020 entered into before August 28, 2020 that met other specified criteria. In 2020, the U.S. and Mexico also engaged in discussions regarding steel imports pursuant to their Joint Statement of May 17, 2019. On August 31, 2020, the Office of the U.S. Trade Representative announced that Mexico would establish a strict monitoring regime of exports of standard pipe, mechanical tubing and semi-finished steel products to the U.S. through June 1, 2021. The U.S. agreed to continue to exempt Mexico from duty on these imports. On November 5, 2020, the Office of the U.S. Trade Representative announced that Mexico agreed to establish a strict monitoring regime for exports of certain grain-oriented electrical steel (“GOES”)-containing products into the U.S., and the U.S. agreed that Mexico would not be subject to any adjustments of imports of electrical transformers or related parts. In addition, the U.S.-Mexico-Canada Free Trade Agreement (“USMCA”) became effective on July 1, 2020. The USMCA includes agreements related to steel and aluminum imports, including changes to rules-of-origin requirements for steel and aluminum materials originating in North America, rules for determining whether goods containing materials from non-USMCA countries are considered “North American” under the Harmonized Tariff Schedule, and tariff exemptions for certain automotive imports. Following these proclamations, domestic prices for steel have risen and are expected to continue to rise. These price increases may result in increased costs associated with the continued build-out of our assets, as well as projects under development. Because we generate substantially all of our revenue under agreements with Antero Resources that provide for fixed fee structures, we will generally be unable to pass these cost increases along to our customers, and our income from operations and cash flows may be adversely affected.
If third-party pipelines or other midstream facilities interconnected to our gathering and compression systems become partially or fully unavailable, our operating margin and cash flows could be adversely affected.
Our gathering and compression assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, compressor stations and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. If any such increase in costs occurs or if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, our operating margin and cash flows could be adversely affected.
Our exposure to commodity price risk may change over time.
We currently generate all of our revenues pursuant to fee-based contracts under which we are paid based on the volumes of natural gas that we gather, process and compress and water that we handle and treat, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to negotiate such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of natural gas, NGL and oil prices, especially in light of the recent declines, could have a material adverse effect on our business, financial condition and results of operations.
The fees charged to our customers may not escalate sufficiently to cover increases in costs, or the agreements may be amended with less favorable terms, may not be renewed or may be suspended in some circumstances.
Our costs may increase at a rate greater than the fees we charge to our customers. Furthermore, Antero Resources and our other customers may not renew their contracts with us, or may from time to time seek to renegotiate with us the amount and/or the structure of fees we charge. Additionally, some of our customers’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are curtailed or cut-off due to events beyond our control, and in some cases, certain of those agreements may be terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of fees is insufficient to cover increased costs, or if our customers do not renew or extend their contracts with us, or if our customers suspend or terminate their contracts with us, our financial results would suffer.
Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may incentivize water recycling efforts by oil and natural gas producers, which would decrease the demand for our fresh water delivery services.
Our business includes fresh water delivery for use in our customers’ natural gas, NGL and oil exploration and production activities. Water is an essential component of natural gas, NGL and oil production during the drilling, and in particular, the hydraulic fracturing process. We derive a significant portion of our revenues from providing fresh water to Antero Resources. Antero Resources implemented efficiency improvements and water initiatives during 2020, which reduced the amount of fresh water needed to complete their operations. These improvements allowed Antero Resources to reuse a portion of its produced water through our blending operations. Furthermore, the availability of water supply for our operations may be limited due to, among other things, prolonged drought or state and local governmental authorities restricting the use of water for hydraulic fracturing. Any decrease in the demand for water handling services, or the water supply we need to provide such services, would adversely affect our business and results of operations.
Increasing attention to ESG matters and conservation measures may adversely impact our business.
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.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us, Antero Resources, and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies or the corresponding infrastructure projects based on climate change related concerns, which could affect our access to capital for potential growth projects.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our business, financial condition and results of operations.
Our operations are subject to all of the hazards associated with the provision, gathering and compression of natural gas, NGLs and oil and water handling services, including:
● 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, pump stations, impoundments, related equipment and surrounding properties caused by natural disasters, acts of terrorism and acts of third parties;
● damage from construction, farm and utility equipment as well as other subsurface activity (for example, mine subsidence);
● leaks of natural gas, NGLs or oil or losses of natural gas, NGLs or oil as a result of the malfunction of equipment or facilities;
● fires, ruptures and explosions;
● other hazards that could also result in personal injury and loss of life, pollution of the environment, including natural resources and suspension of operations; and
● hazards experienced by other operators that may affect our operations by instigating increased regulations and oversight.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
● injury or loss of life;
● damage to and destruction of property, natural resources and equipment;
● pollution and other environmental damage;
● regulatory investigations and penalties;
● 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 or cyber-attacks and threats could have a material adverse effect on our business, financial condition and results of operations.
Terrorist or cyber-attacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. We depend on digital technology in many areas of our business and operations, including, but not limited to, performing many of our gathering and compression and water handling services, recording financial and operating data, oversight and analysis of our operations and communications with the employees supporting our operations and our customers or service providers. Deliberate attacks on our assets or our Joint Venture’s assets, security breaches in our systems or infrastructure, or the systems or infrastructure of third-parties or the cloud, could lead to the corruption or loss of our proprietary and potentially sensitive data, delays in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions or other operational disruptions and third-party liabilities. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.
As cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date, we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Capital Structure and Access to Capital
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.
Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our revolving credit facility and our senior notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the senior notes.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness, including the senior notes. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior unsecured notes, and our financial condition at such time. Any refinancing of our indebtedness, including using borrowings under our revolving credit facility to redeem our senior notes, could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including the indentures governing our senior notes, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result
in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.
We will be required to make capital expenditures to increase our asset base. If we cannot obtain needed capital or financing on satisfactory terms, we may be unable to expand our business operations and/or our financial leverage could increase.
To increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we may be unable to expand our business operations, which could adversely affect our business and operating results. To fund our expansion capital expenditures and investment capital expenditures, we expect to use cash from our operations or incur borrowings. Alternatively, we may sell additional shares of common stock or other securities to fund our capital expenditures. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our or Antero Resources’ financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing shares of common stock may result in significant stockholder dilution. Neither Antero Resources or any of its affiliates is committed to providing any direct or indirect support to fund our growth.
We may be unable to access the equity or debt capital markets to meet our obligations.
Declines in commodity prices or the financial condition or prospects of Antero Resources may cause the financial markets to exert downward pressure on our stock price and credit capacity. For example, for portions of 2020, the market for senior unsecured notes was unfavorable for high-yield issuers such as us. Our plans for growth may require access to the capital and credit markets. Although the market for high-yield debt securities experienced periods of improvement in 2020, if the high-yield market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms or at all, we may be unable to carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Restrictions in our existing and future debt agreements could adversely affect our business, financial condition and results of operations.
Our revolving credit facility limits our ability to, among other things:
● incur or guarantee additional debt;
● redeem or repurchase units or make distributions under certain circumstances;
● make certain investments and acquisitions;
● 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. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
● our ability to 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.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing or not paying dividends, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue growth opportunities, reduce cash flow used for our services and place us at a competitive disadvantage. For example, during 2020, we had average outstanding borrowings under our revolving credit facility of approximately $1.1 billion, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of approximately $11 million and a corresponding decrease in our cash flows and net income before the effects of income taxes. Disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to carry out our business plan.
Geographic Concentration
Our gathering and compression and water handling systems are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.
We rely primarily on revenues generated from our gathering and compression and water handling systems, which are all located in the Appalachian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by, and associated with, governmental regulation, state and local political activities, market limitations, availability of equipment and personnel or interruption of the compression, processing or transportation of natural gas, NGLs or oil.
A shortage of equipment and skilled labor in the Appalachian Basin could reduce equipment availability and labor productivity and increase labor costs, which could have a material adverse effect on our business and results of operations.
Gathering and compression and water handling services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If Antero Resources experiences shortages of skilled labor or there is a lack of necessary equipment in the Appalachian Basin in the future, our allocation of labor costs and overall productivity could be materially and adversely affected. If our allocation of labor prices increase or if Antero Resources experiences materially increased health and benefit costs for employees, our business and results of operations could be materially and adversely affected.
Acquisitions and Takeovers
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future, we may acquire businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to successfully integrate the acquired businesses and assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, financial condition and results of operations.
In addition, our agreements governing our debt impose certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility and the indentures governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Certain provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our certificate of incorporation and bylaws:
● 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 only 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) the Sponsor Holders 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) the Sponsor Holders 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 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.
Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders.
Certain funds affiliated with Yorktown Partners LLC (“Yorktown”), Paul M. Rady and Glen C. Warren, Jr. (collectively, the “Sponsors”) own a significant interest in us. Messrs. Rady and Warren and an individual affiliated with Yorktown serve as members of our Board and the board of directors of Antero Resources. The Sponsors also own a significant portion of the shares of common stock of Antero Resources. As a result of their investments in Antero Resources, the Sponsors may have conflicting interests with other stockholders. Conflicts of interest could arise in the future between us, on the one hand, and the Sponsors, on the other hand, regarding, among other things, decisions related to our financing, capital expenditures and growth plans, the terms of our agreements with Antero Resources and its subsidiaries and the pursuit of potentially competitive business activities or business opportunities.
Joint Ventures
We own a 50% interest in the Joint Venture, which is operated by MarkWest. While we have the ability to influence certain business decisions affecting the Joint Venture, the success of our investment in the Joint Venture will depend on MarkWest’s operation of the Joint Venture.
On February 6, 2017, we entered into the Joint Venture with MarkWest. While we and MarkWest each own a 50% interest in the Joint Venture, MarkWest is the primary operator of the Joint Venture, and we depend on MarkWest for the day-to-day operations of the Joint Venture. Our lack of control over the Joint Venture’s day-to-day operations and the associated costs of operations could result in receiving lower cash distributions from the Joint Venture than currently anticipated. In addition, differences in views among the owners of the Joint Venture could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of the Joint Venture and, in turn, the amount of cash from the Joint Venture operations distributed to us.
If the Joint Venture is not successful or if the Joint Venture does not perform as expected, our future financial performance may be negatively impacted.
We may be exposed to certain risks in connection with our ownership interest in the Joint Venture, including regulatory, environmental and litigation risks. If such risks or other anticipated or unanticipated liabilities were to materialize, any desired benefits of our entry into the Joint Venture may not be fully realized, if at all, and its future financial performance may be negatively impacted.
In addition, the Joint Venture may result in other difficulties including, among other things:
● 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 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 apply to our operations. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations. Also, we might not be able to obtain or maintain all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.
In addition, new or additional regulations, new interpretations of existing requirements or changes in our operations could also trigger the need for Environmental Assessments or more detailed Environmental Impact Statements under the National Environmental Policy Act and analogous state laws, or that impose new permitting requirements on our operations could result in increased costs or delays of, or denial of rights to conduct, our development programs. For example, in April 2020, the federal district court for the District of Montana determined that the Corps Clean Water Act Section 404 Nationwide NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects. While the district court’s order has subsequently been limited pending appeal and NWP 12 authorizations remain available for certain oil and gas pipeline projects, we cannot predict the ultimate outcome of this case and its impacts to the nationwide permit program. Relatedly, in response to the vacatur, the Corps reissued NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rulemaking may be subject to litigation or to further revision under the Biden Administration. While the full extent and impact of the vacatur is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. This in turn could have an adverse effect on our business, financial condition and results of operation. Separately, in January 2020, EPA and the Corps issued a final rule under the Clean Water Act (“CWA”) revising the definition of waters of the United States (“WOTUS”); however, both this and prior revisions to the definition of WOTUS are currently subject to litigation, and it is possible that a new presidential administration could propose a broader interpretation of the CWA’s jurisdiction. As a result, the scope of the CWA’s jurisdiction is uncertain at this time. To the extent any rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse
effect on our business, financial condition and results of operations. Further, the discharges of natural gas, NGLs, oil and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. Please read “Item 1. Business-Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.
If our assets become subject to FERC regulation or federal, state or local regulations or policies change, or if we fail to comply with market behavior rules, our financial condition, cash flows and results of operations could be materially and adversely affected.
Our gathering and transportation operations are exempt from regulation by the FERC, under the NGA. Section 1(b) of the NGA, exempts natural gas gathering facilities from regulation by the FERC under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, cash flows and results of operations.
State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, compression and sale.
Moreover, FERC regulations indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and market center promotion, indirectly affect the intrastate natural gas market. Should we fail to comply with any applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines, which could have a material adverse effect on our financial condition, cash flows and results of operations. The FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1,307,164 per day for each violation and disgorgement of profits associated with any violation.
For more information regarding federal and state regulation of our operations, please read “Business-Regulation of Operations.”
Increased regulation of hydraulic fracturing could result in reductions or delays in production by our customers, which could reduce the throughput on our gathering and processing systems and the number of wells for which we provide water handling services, which could adversely impact our revenues.
All of Antero Resources’ natural gas, NGLs and oil production is developed from unconventional sources, such as shale formations. These reservoirs require hydraulic fracturing completion processes to release the liquids and natural gas from the rock so it can flow through casing to the surface. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand (or other proppant) combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. In addition, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. New legislation regulating hydraulic fracturing may be considered again in future, though we cannot predict when or the scope of any such legislation at this time. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. At the state level, several states have adopted or are considering adopting regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic
fracturing operations. For example, in July 2015, the Ohio Department of Natural Resources issued final rules for horizontal drilling well-pad construction. The Ohio legislature has also adopted laws requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drilling baseline water quality sampling of certain water wells near a proposed horizontal well. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.
We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal, state or local level, that could lead to delays, increased operating costs and process prohibitions that could reduce the amount of natural gas that moves through our gathering and processing systems or reduce the number of wells drilled and completed that require fresh water for hydraulic fracturing activities, which in turn could materially and adversely affect our revenues and results of operations.
We or any third-party customers may incur significant liability under, or costs and expenditures to comply with, environmental and occupational health and workplace safety regulations, which are complex and subject to frequent change.
As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state, provincial and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. These laws and regulations may impose various obligations that are applicable to our and our customer’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability. For example, following the election of President Biden and a Democratic majority in both houses of Congress, it is possible that our operations and those of our clients, may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and GHG emissions.
Our operations also pose risks of environmental liability due to potential leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations is expected to continue, which may result in increased costs of doing business and consequently affecting profitability. Please read “Business-Regulation of Environmental and Occupational Safety and Health Matters” for more information.
Our operations are subject to a series of risks related to climate change that could result in increased operating costs, limit the areas in which our customers may conduct oil and gas exploration and production activities, and reduce demand for the services we provide.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration, which includes certain potential initiatives for climate change legislation to be proposed and passed into law. Moreover, federal regulators, state and local governments and private parties have taken (or announced that they plan to take) actions that have or may have a significant influence on our operations. For example, in response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the
EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.
In June 2016, the EPA finalized new regulations, known as Subpart OOOOa, that establish emission standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. The EPA’s rule package included first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rule package extended existing VOC standards under the EPA’s Subpart OOOO to include previously unregulated equipment within the oil and natural gas source category. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified and existing oil and gas facilities. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states, including West Virginia and Ohio, have separately imposed their own regulations on methane emissions from oil and gas production activities.
Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had withdrawn from the Paris Agreement, effective January 20, 2021, President Biden has issued executive orders recommitting the United States to the Paris Agreement and directing the federal government to begin formulating the United States’ nationally determined emissions reduction target under the Paris Agreement. The impacts of this order, and any legislation or regulation promulgated to fulfill the United States commitments under the Paris Agreement cannot be predicted at this time.
Concern over the threat of climate change has also resulted in increasing political risks in the United States, including climate-change related pledges made by President Biden and other public office representatives. These have included promises to pursue actions to limit emissions and curtail the production of oil and gas, such as through the cessation of leasing public land for hydrocarbon development. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. Other actions that could be pursued by the Biden administration include more restrictive requirements for the development of pipeline infrastructure or LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities.
Increasingly, fossil fuel companies are also exposed to litigation risks from climate change. A number of cities and other local governments have brought suits against the largest fossil fuel companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer protection laws, alleging that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts. While we are not currently party to any such litigation, we could be named in future actions making similar claims of liability. Moreover, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
Additionally, in response to concerns related to climate change, companies in the fossil fuel sector may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to sustainable lending practices, and some of them may elect in future not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our midstream services.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other
regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for the services we provide. Additionally, political, litigation and financial risks may result in our restricting or cancelling oil and natural gas production activities, incurring liability for damages resulting from climate change or impairing our ability to continue operating in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation. Finally, it should be noted that a number of scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on exploration and production operations. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in HCAs. The regulations require operators to:
● perform ongoing assessments of pipeline integrity;
● identify and characterize applicable threats to pipeline segments that could impact an HCA;
● improve data collection, integration and analysis;
● repair and remediate the pipeline as necessary; and
● implement preventive and mitigating actions.
The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs. Consistent with the 2011 Pipeline Safety Act, the Pipelines and Hazardous Materials Safety Administration (“PHMSA”), finalized rules consistent with the signed act that increased the maximum administrative civil penalties for violations of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. In July 2019, those maximum civil penalties were increased to $218,647 and $2,186,465, respectively, to account for inflation. Should our operations fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.
In June 2016, the President of the United States signed into law important new legislation entitled Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “PIPES Act”). The PIPES Act facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. The PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from 2011 Pipeline Safety Act, of which several remain to be completed.
PHMSA regularly revises its pipeline safety regulations. For example, in October 2019, PHMSA published three final rules on pipeline safety. The Enhanced Emergency Order Procedures rule (effective December 2, 2019) implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if unsafe conditions or practices, or a combination thereof, constitutes or causes an imminent hazard. The Safety of Hazardous Liquid Pipelines rule (effective July 1, 2020) expands PHMSA’s regulation of the safety of hazardous liquid pipelines by extending reporting requirements to certain hazardous liquid gravity flow and rural gathering pipelines, establishing new requirements for integrity management programs for hazardous liquid pipelines in HCAs and certain other hazardous liquid pipelines, and expanding various inspection and leak detection requirements. The Safety of Gas Transmission Pipelines rule (effective July 1, 2020) requires operators of certain gas transmission
pipelines to reconfirm the Maximum Allowable Operating Pressure (MAOP) of their lines and establishes a new “Moderate Consequence Area” for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. The rule also establishes new requirements for conducting baseline assessments and incorporates industry standards and guidelines as well as new requirements for integrity management programs. The rule also includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. We are in the process of assessing the impact of these rules on our future costs of operations and revenue from operations, but we do not expect our operations to be affected by these new rules any differently than other similarly situated midstream companies.
PHMSA is working on two additional rules related to gas pipeline safety, though we cannot predict when they will be finalized. The rule entitled “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments” is expected to adjust the repair criteria for pipelines in HCAs, create new criteria for pipelines in non-HCAs and strengthen integrity management assessment requirements. The rule entitled “Safety of Gas Gathering Pipelines” is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas. The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant, consistent with other similarly situated midstream companies. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow. Please read “Business-Pipeline Safety Regulation” for more information.
Human Capital
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of a relatively small group of senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including Paul M. Rady, Chairman and Chief Executive Officer, and Glen C. Warren, Jr., President, could have a material adverse effect on our business, financial condition and results of operations.
Our officers and employees provide services to both Antero Resources and us.
All of our executive officers and certain other personnel who provide corporate, general and administrative services to our business are, when providing services to us, concurrently employed by Antero Resources and us pursuant to the terms of a services agreement. In addition, our operational personnel are seconded to us by Antero Resources pursuant to the terms of a secondment agreement and are concurrently employed by Antero Resources and us during such secondment. As a result, there could be material competition for the time and effort of the officers and employees who provide services to Antero Resources and us. If such officers and employees do not devote sufficient attention to the management and operation of our business, our financial results may suffer.
Related Parties
Antero Resources owns a significant interest in us and, as a result, conflicts of interest will arise from time to time between it and us, and Antero Resources may favor their own interests to the detriment of us and our other stockholders. Additionally, Antero Resources is under no obligation to adopt a business strategy that favors us.
All of our officers and certain of our directors are also officers or directors of Antero Resources. Also, as of December 31, 2020, Antero Resources beneficially owned 29.2% of our outstanding common stock. Our directors and officers who are also directors and officers of Antero Resources have a fiduciary duty to manage Antero Resources in a manner that is beneficial to Antero Resources. Conflicts of interest will arise between Antero Resources and us. In resolving these actual or apparent conflicts of interest, members of our Board may choose strategies that favor Antero Resources over our interests and the interests of our stockholders. These conflicts include, for example, the decision to declare and pay dividends or the decision to repurchase shares of our common stock owned by Antero Resources. The resolution of any conflicts of interest between Antero Resources and its subsidiaries, on one hand, and us and our subsidiaries, on the other, to the extent we can resolve them, may be costly and reduce the amount of time and attention that our directors and officers may spend in operating our business, which, in each case, may adversely affect our business.
Furthermore, Antero Resources is under no obligation to adopt a business strategy that favors us. For example, Antero Resources has dedicated acreage to, and entered into long-term contracts for gathering and compression services on, our gathering and compression systems, as well as long-term contracts for receiving water services. However, while we have a right of first offer that
expires in 2038 to provide processing and fractionation services to Antero Resources, subject to certain exceptions, Antero Resources is under no obligation to consider whether any future drilling plans would create beneficial opportunities for us. Additionally, although our the processing and fractionation services provided by the Joint Venture are supported by minimum volume commitments, the gathering and compression agreement includes minimum volumes commitments only on high pressure pipelines and compressor stations constructed at Antero Resources’ request after November 2014. Any decision by Antero Resources to operate its assets in a manner that does not support our operations could have a material adverse effect on our business, financial condition and results of operations.
We are a holding company whose sole material asset is our equity interest in Antero Midstream Partners, and we are accordingly dependent upon distributions from Antero Midstream Partners to pay taxes, return capital to stockholders and cover our corporate and other overhead expenses.
We are a holding company and have no material assets other than our equity interest in Antero Midstream Partners. We have no independent means of generating revenue. To the extent Antero Midstream Partners has available cash, we intend to cause Antero Midstream Partners to make distributions to us in an amount at least sufficient to allow us to pay our taxes, to fund our return of capital to our stockholders, including paying dividends and repurchasing shares of our common stock and for our corporate and other overhead expenses. To the extent that we need funds and Antero Midstream Partners or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.
Income Taxes
Our future tax liability may be greater than expected if we do not generate deductions or net operating loss (“NOL”) carryforwards sufficient to offset taxable income or if tax authorities challenge certain of our tax positions.
We expect to generate deductions and NOL carryforwards that we can use to offset our taxable income. As a result, we do not expect to pay material U.S. federal and state income taxes through 2023. This expectation is based upon assumptions our management has made regarding, among other things, income, capital expenditures and net working capital. Further, the IRS or other tax authorities could challenge one or more tax positions we take, such as the classification of assets under the income tax depreciation rules, the characterization of expenses for income tax purposes, and the tax characterization of the Transactions. Further, any change in law may affect our tax position. While we expect that our deductions and NOL carryforwards will be available to us as a future benefit, in the event that they are not generated as expected, are successfully challenged by the IRS (in a tax audit or otherwise), or are subject to future limitations, our ability to realize these benefits may be limited.
Taxable gain or loss on the sale of our common stock could be more or less than expected.
If a holder sells our common stock, the holder will recognize gain or loss equal to the difference between the amount realized and the holder’s tax basis in the shares of common stock sold. To the extent that the amount of distributions on our common stock exceeds our current and accumulated earnings and profits, such distributions will be treated as a tax free return of capital and will reduce a holder’s tax basis in its common stock. We expect the majority of our distributions to be in excess of our earnings and profits through 2023. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in our common stock, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of our common stock.
The IRS Forms 1099-DIV that our stockholders receive from their brokers may over-report dividend income with respect to our common stock for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a stockholder’s U.S. federal income tax return. For non-U.S. holders of our common stock, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund to claim a refund of the overwithheld taxes.
Distributions we pay with respect to our common stock will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a stockholder’s tax basis in their common stock and then as capital gain realized on the sale or exchange of such stock. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax with respect to distribution amounts that should have been classified as a tax-free return of capital. In such a case, a stockholder generally would have to timely file an amended U.S. tax return or an appropriate claim
for refund to obtain a refund of the overpaid tax.
For a U.S. holder of our common stock, the IRS Forms 1099-DIV received from brokers may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a stockholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended U.S. federal, state or local income tax return). We will attempt to timely notify our stockholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our stockholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a stockholder’s tax return.
For a non-U.S. holder of our common stock, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with the conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that constitute a “dividend” for U.S. federal income tax purposes, or a stockholder’s broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a stockholder’s broker or other withholding agent may overwithhold taxes from distributions paid. In such a case, a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
General Risks
We expect to use a significant portion of our cash flows to pay dividends to our stockholders and/or repurchase shares of our common stock, which could limit our ability to grow and make acquisitions.
We have previously announced that we plan to return capital to our stockholders through dividends to our stockholders and repurchasing shares of our common stock, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional shares of common stock in connection with any acquisitions or expansion capital expenditures, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the cash that we have available to return capital to our stockholders through dividends and/or repurchases of shares of our common stock.
We may reduce or cease paying dividends on our common stock.
We are not obligated to pay dividends on shares of our common stock. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of our common stock are only entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our Board out of funds legally available for dividend payments. Our Board makes a determination each quarter as to the actual amount, if any, of dividends to pay on our common stock, based on various factors, some of which are beyond our control, including our operating cash flows, our working capital needs, our ability to access capital markets for debt and equity financing on reasonable terms, the restrictions contained in our debt instruments, our debt service requirements, credit metrics and the cost of acquisitions, if any. We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. Accordingly, we cannot guarantee that we will declare any future dividends at levels consistent with our historic practice or at all.
The price of our common stock may be volatile, and you could lose a significant portion of your investment.
The market price of our common stock could be volatile, and holders of common stock may not be able to resell their common stock at or above the price at which they acquired such securities due to fluctuations in the market price of our common stock.
Specific factors that may have a significant effect on the market price for our common stock include:
● our operating and financial performance and prospects and the trading price of our common stock;
● the level of our dividends;
● quarterly variations in the rate of growth of our financial indicators, such as dividends per share of our common stock, net income and revenues;
● levels of indebtedness;
● changes in revenue or earnings estimates or publication of research reports by analysts;
● speculation by the press or investment community;
● sales of our common stock by other stockholders;
● announcements by us or our competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments;
● general market conditions;
● changes in accounting standards, policies, guidance, interpretations or principles;
● adverse changes in tax laws or regulations;
● domestic and international economic, legal and regulatory factors related to our performance; and
● Antero Resources’ operating and financial performance and prospects, and the trading price of its common stock.
There may be future dilution of our common stock, which could adversely affect the market price of shares of our common stock.
We are not restricted from issuing additional shares of our common stock out of our authorized capital. In the future, we may issue shares of our common stock to raise cash for future activities, acquisitions or other purposes. We may also acquire interests in other companies by using a combination of cash and shares of our common stock or only shares. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, shares of our common stock. Any of these events may dilute the ownership interests of our stockholders, reduce our earnings per share or have an adverse effect on the price of shares of our common stock.
Sales of a substantial amount of shares of our common stock in the public market could adversely affect the market price of our shares.
Sales of a substantial amount of shares of our common stock in the public market or grants to our directors and officers under 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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
Not applicable.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business.
We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Veolia
The Company is currently involved in a consolidated lawsuit with Veolia Water Technologies, Inc. (“Veolia”) and Veolia Water North America Operating Services, LLC (“Veolia North America”) relating to the Clearwater Facility.
On March 13, 2020, Antero Treatment LLC (“Antero Treatment”), a wholly owned subsidiary of the Company, filed suit against Veolia and Veolia North America in the district court of Denver County, Colorado, asserting claims of fraud, breach of contract and other related claims. Antero Treatment alleges that Veolia failed to meet its contractual obligations to design and build a “turnkey” wastewater disposal facility under a Design/Build Agreement dated August 18, 2015 (the “DBA”), and that Veolia fraudulently concealed certain design flaws during contract negotiations and continued to conceal and fraudulently misrepresent the impact of certain design changes post-execution of the DBA. Antero Treatment is seeking damages from Veolia of at least $457 million, which represents the Company’s recorded impairment of the idled Clearwater Facility. In the alternative, Antero Treatment sought rescission of the DBA and restitution of, at a minimum, the $230 million out-of-pocket costs paid to Veolia pursuant to the DBA. Antero Treatment also asserts related claims against Veolia North America, including equitable claims with respect to certain amounts Antero paid to Veolia North America.
On March 13, 2020, Veolia filed a separate suit against the Company, Antero Resources, and certain of the Company’s wholly owned subsidiaries (collectively, the “Antero Defendants”) in Denver County, Colorado. In its lawsuit, Veolia asserts breach of contract and equitable claims against the Antero Defendants for alleged failures under the DBA, including an allegation that the Antero Defendants improperly terminated the DBA to prevent Veolia from earning an approximate $26 million contract balance. The Antero Defendants vigorously deny Veolia’s claims. Veolia seeks money damages in an amount not yet specified. Veolia’s suit has been consolidated into the action filed by Antero Treatment.
On April 17, 2020, Veolia, Veolia North America and the Antero Defendants each filed partial motions to dismiss directed at certain claims asserted by the opposing party. On July 23, 2020, the Court dismissed Veolia’s equitable claims against the Antero
Defendants and Antero Treatment’s alternative claim for rescission against Veolia. All other claims remain part of the consolidated action. The case is set for trial beginning on November 29, 2021.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
We have one class of common equity outstanding, our common stock, par value $0.01 per share. Our common stock is listed on the New York Stock Exchange and traded under the symbol “AM.” On February 12, 2021, shares of our common stock were held by 49 holders of record. The number of holders does not include the holders for whom shares of our common stock are held in a “nominee” or “street” name. In addition, as of February 12, 2021, Antero Resources and its subsidiaries owned 139,042,345 shares of our common stock, which represented a 29.2% interest in us.
Issuer Purchases of Equity Securities
The following table sets forth our common stock repurchase activity for each period presented:
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, 2020 - October 31, 2020
1,461
$
6.43
-
$
149,767,409
November 1, 2020 - November 30, 2020
-
-
-
N/A
December 1, 2020 - December 31, 2020
-
-
-
N/A
Total
1,461
$
6.43
-
$
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. During the three months ended December 31, 2020, we did not make any repurchases under this program.
Dividends
On January 20, 2021, the Board declared an aggregate cash dividend on the shares of our common stock of $0.3075 per share for the quarter ended December 31, 2020. The dividend will be payable on February 11, 2021 to stockholders of record as of February 3, 2021.
The Board also declared a cash dividend of $138 thousand on shares of our Series A Non-Voting Perpetual Preferred Stock, par value $0.01 (the “Series A Preferred Stock”), to be paid on February 16, 2021 in accordance with the terms of the Series A Preferred Stock, which are discussed in Note 14-Equity and Earnings Per Common Share to our consolidated financial statements. As of December 31, 2020, there were dividends in the amount of $69 thousand accumulated in arrears on our Series A Preferred Stock.
Stock Performance Graph
The graph below shows the cumulative total shareholder return assuming the investment of $100 on May 4, 2017, the date of our initial public offering, in each of our predecessor’s common shares through March 12, 2019 and our common stock thereafter, the
Standard & Poor’s 500 (“S&P 500”) Index, and the Alerian Midstream Energy (“AMNA”) Index. We believe the AMNA Index is meaningful because it is an independent, objective view of the performance of similarly-sized midstream energy companies.
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.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. Selected financial data
The following table presents our selected historical financial data, for the periods and as of the dates indicated, for the Company and its predecessors. Our predecessor, AMGP, was originally formed as ARMM to become the general partner of Antero Midstream Partners and converted into a limited partnership on May 4, 2017 in connection with our IPO. On March 12, 2019, pursuant to the Simplification Agreement, we completed the Transactions.
The Merger has been accounted for as an acquisition by AMGP of Antero Midstream Partners under ASC 805 - Business Combinations and accounted for as a business combination, with the assumed assets and liabilities of Antero Midstream Partners recorded at their estimated fair value. As a result of the Merger, our historical financial data for previous periods are not comparable to the years ended December 31, 2019 and 2020 or to our future financial results. The selected financial data for the years ended December 31, 2016, 2017 and 2018 are the financial statements of AMGP and its consolidated subsidiaries, which do not include Antero Midstream Partners and its subsidiaries. Effective March 12, 2019, we began consolidating Antero Midstream Partners and its subsidiaries in our consolidated financial statements. As a result, our selected balance sheet financial data presented below at December 31, 2019 includes the financial position of Antero Midstream Partners and its subsidiaries, and our selected consolidated statements of operations and comprehensive income and cash flows data for the year ended December 31, 2019 include the results of operations of Antero Midstream Partners and its subsidiaries beginning on March 13, 2019. The historical selected consolidated statement of operations data included herein reflects that, prior to the Merger, AMGP’s only income resulted from distributions made on the incentive distribution rights (the “IDRs”) of Antero Midstream Partners and expenses were limited to general and administrative expenses and equity-based compensation. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations -Items Affecting Comparability of our Financial Results.”
Accordingly, we are also presenting our pro forma results of operations for the years ended December 31, 2018 and December 31, 2019, which give effect to the adjustments described in Exhibit 99.1 to this Annual Report on Form 10-K. The pro forma information presented below should be read in conjunction with the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K and describe the assumptions and adjustments used in preparing such information. The pro forma adjustments are based on currently available information and certain estimates and
assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the results of operations on a more meaningful basis.
The selected statement of operations data and statement of cash flows data for the years ended December 31, 2018, 2019 and 2020 and the balance sheet data as of December 31, 2019 and 2020 are derived from our audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K. The selected statement of operations data and statement of cash flows data for the years ended December 31, 2016 and 2017 and the selected balance sheet data as of December 31, 2016, 2017 and 2018 is derived from our audited consolidated financial statements not included in Item 8 of this Annual Report on Form 10-K.
The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this report:
Year Ended December 31,
(in thousands, except per share amounts)
Revenue:
Gathering and compression-Antero Resources
$
-
-
-
543,538
711,459
Water handling-Antero Resources
-
-
-
306,010
259,932
Water handling-third party
-
-
-
-
Amortization of customer relationships
-
-
-
(57,010)
(70,672)
Total revenue
-
-
-
792,588
900,719
Operating expenses:
Direct operating
-
-
-
195,818
165,386
General and administrative (excluding equity-based compensation)
6,201
8,740
44,596
39,435
Equity-based compensation
-
34,933
35,111
73,517
12,778
Facility idling
-
-
-
11,401
15,219
Impairment of goodwill
-
-
-
340,350
575,461
Impairment of property and equipment
-
-
-
409,739
98,179
Impairment of customer relationships
-
-
-
11,871
-
Depreciation
-
-
-
95,526
108,790
Accretion and change in fair value of contingent acquisition consideration
-
-
-
8,076
-
Accretion of asset retirement obligations
-
-
-
Loss on asset sale
-
-
-
-
2,929
Total operating expenses
41,134
43,851
1,191,081
1,018,357
Operating loss
(814)
(41,134)
(43,851)
(398,493)
(117,638)
Interest expense, net
-
-
(136)
(110,402)
(147,007)
Equity in earnings of unconsolidated affiliates
16,944
69,720
142,906
51,315
86,430
Income (loss) before income taxes
16,130
28,586
98,919
(457,580)
(178,215)
Provision for income tax benefit (expense)
(6,419)
(26,261)
(32,311)
102,466
55,688
Net income (loss) and comprehensive income (loss)
$
9,711
2,325
66,608
(355,114)
(122,527)
Net income (loss) per share-basic and diluted
$
0.03
0.33
(0.80)
(0.26)
Weighted average common shares outstanding:
Basic
186,176
186,203
442,640
478,278
Diluted
186,176
186,203
442,640
478,278
Year Ended December 31,
(in thousands, except per share amounts)
Balance sheet data (at period end):
Cash and cash equivalents
$
9,609
5,987
2,822
1,235
Other current assets
-
107,323
93,291
Total current assets
9,826
5,987
2,909
108,558
93,931
Property and equipment, net
-
-
-
3,273,410
3,254,044
Investments in unconsolidated affiliates
7,543
23,772
43,492
709,639
722,478
Other assets
-
-
1,304
2,191,271
1,540,459
Total assets
$
17,369
29,759
47,705
6,282,878
5,610,912
Current liabilities
7,100
14,151
16,844
242,084
94,005
Long-term indebtedness
-
-
-
2,892,249
3,091,626
Other long-term liabilities
-
-
-
5,131
6,995
Total partners' capital and stockholders' equity
10,269
15,608
30,861
3,143,414
2,418,286
Total liabilities and partners' capital and stockholders' equity
$
17,369
29,759
47,705
6,282,878
5,610,912
Cash flows data:
Net cash provided by operating activities
$
9,537
28,080
83,531
622,387
753,382
Net cash used in investing activities
$
-
-
-
(525,675)
(219,231)
Net cash used in financing activities
$
-
(31,702)
(86,696)
(98,299)
(534,746)
Other financial data:
Distributions or dividends declared per share
$
0.16
0.54
1.23
1.23
Pro forma Net income (loss)
$
312,894
(285,076)
Adjusted EBITDA(1)(2)
$
708,635
829,558
850,209
(1) 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”.
(2) 2018 and 2019 information is Pro Forma.
The following table presents our pro forma results of operations for the years ended December 31, 2018 and 2019, which give effect to the adjustments described in Exhibit 99.1 to this Annual Report on Form 10-K. The pro forma information presented below should be read in conjunction with the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K and describe the assumptions and adjustments used in preparing such information.
Year Ended December 31,
Revenues:
Revenue-Antero Resources
$
1,027,015
1,067,858
Revenue-third-party
Gain on sales of assets-Antero Resources
-
Amortization of customer relationships
(71,082)
(70,874)
Total revenues
957,440
997,085
Operating expenses:
Direct operating
316,423
260,636
General and administrative (excluding equity-based compensation)
49,296
45,567
Equity-based compensation
56,184
75,994
Facility idling
-
11,401
Impairment of property and equipment
5,771
416,721
Impairment of goodwill
-
340,350
Impairment of customer relationships
-
11,871
Depreciation
145,745
120,363
Accretion and change in fair value of contingent acquisition consideration
(93,019)
10,004
Accretion of asset retirement obligations
Total expenses
480,535
1,293,157
Operating income (loss)
476,905
(296,072)
Other income (expenses):
Interest expense, net
(83,794)
(130,518)
Equity in earnings of unconsolidated affiliates
34,189
62,394
Income (loss) before taxes
427,300
(364,196)
Provision for income tax benefit (expense)
(114,406)
79,120
Net income (loss) and comprehensive income (loss)
$
312,894
(285,076)
Non-GAAP Financial Measures
We use Adjusted EBITDA as an important indicator of our performance. In our presentation of Adjusted EBITDA for the year ended December 31, 2020, net income (loss) and the corresponding adjustments reflect our actual results of operations. In our presentation of Adjusted EBITDA for the years ended December 31, 2019 and 2018, net income (loss) and the corresponding adjustments reflect our pro forma results of operations. The pro forma information should be read in conjunction with the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K. For more information, see “Items Affecting Comparability of Our Financial Results.”
We define Adjusted EBITDA as net income before net interest expense, income tax expense, depreciation, impairment, accretion and changes in fair value of contingent acquisition consideration, accretion of asset retirement obligations, equity-based compensation, excluding equity in earnings of unconsolidated affiliates, contract restructuring expenses, amortization of customer relationships, gains and losses on asset sales and including cash distributions from unconsolidated affiliates.
We use Adjusted EBITDA to assess:
● the financial performance of our assets, without regard to financing methods capital structure or historical cost basis;
● our operating performance and return on capital as compared to other publicly traded companies in the midstream energy sector, without regard to financing or capital structure; and
● the viability of acquisitions and other capital expenditure projects.
Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss). The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income (loss). Adjusted EBITDA presentations are not made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect net income (loss). You should not consider Adjusted EBITDA in isolation or as a substitute for analyses of results as reported under GAAP. Our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other corporations.
The following table represents a reconciliation of our Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods presented:
Year Ended December 31,
(in thousands)
2018(1)
2019(1)
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net income (loss)
$
312,894
(285,076)
(122,527)
Interest expense, net
83,794
130,518
147,007
Income tax expense (benefit)
114,406
(79,120)
(55,688)
Amortization of customer relationships
71,082
70,874
70,672
Depreciation expense
145,745
120,363
108,790
Impairment
5,771
768,942
673,640
Accretion and change in fair value of contingent acquisition consideration
(92,884)
10,254
Equity-based compensation
56,184
75,994
12,778
Equity in earnings of unconsolidated affiliates
(34,189)
(62,394)
(86,430)
Gain on sale of assets-Antero Resources
(583)
-
-
Loss on asset sale
-
-
2,929
Contract restructuring fees
-
2,278
-
Distributions from unconsolidated affiliates
46,415
76,925
98,858
Adjusted EBITDA
$
708,635
829,558
850,209
(1) Pro Forma.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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, please 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.
On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among Antero Midstream Partners GP LP (“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, (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 the Simplification Agreement, the “Transactions”) each issued and outstanding Series B Unit (the “Series B Units”) representing a membership interest in Antero IDR Holdings LLC (“IDR Holdings”) for 176.0041 shares of its common stock, par value $0.01 per share (“AM common stock”).
The Merger has been accounted for as an acquisition by AMGP of Antero Midstream Partners under ASC 805, Business Combinations and accounted for as a business combination, with the assumed assets and liabilities of Antero Midstream Partners recorded at fair value. As a result, the consolidated balance sheets of Antero Midstream Corporation as of December 31, 2019 and 2020 include the financial position of Antero Midstream Partners and its subsidiaries and the consolidated statements of operations
and comprehensive income and cash flows for the three years ended December 31, 2020 include the results of operations of Antero Midstream Partners and its subsidiaries commencing on March 13, 2019. Unless the context otherwise requires, references to the “Company,” “we,” “us,” or “our” refer to (i) for the period prior to March 13, 2019, AMGP and its consolidated subsidiaries, which did not include Antero Midstream Partners and its subsidiaries, and (ii) for the period beginning and after March 13, 2019, Antero Midstream Corporation and its consolidated subsidiaries, including Antero Midstream Partners and its subsidiaries.
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 fresh 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 fresh water storage facilities, as well as pumping stations and impoundments to transport the fresh 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.
COVID-19 Pandemic
In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs. Also in March 2020, Saudi Arabia and Russia failed to agree to cut production of oil along with the Organization of the Petroleum Exporting Countries (“OPEC”), and Saudi Arabia significantly reduced the price at which it sells oil and announced plans to increase production, which contributed to a sharp drop in the price of oil. While OPEC, Russia and other allied producers reached an agreement in April 2020 to reduce production, oil prices have remained low. The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices.
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. We have continued to operate 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 these protocols have not reduced Antero Resources’ production and our throughput in a significant manner. A substantial portion of our non-field level employees continue to 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.
Our midstream assets are located in West Virginia and Ohio to serve the production of natural gas, NGLs and oil in the Appalachian Basin, primarily by Antero Resources. Our operations support well completion and production operations for Antero Resources and as such, we are directly impacted by changes in Antero Resources’ operations. While Antero Resources has seen a decrease in the overall demand for its products, demand for natural gas and NGLs has not declined as much as demand for oil, and there has not been as substantial an oversupply of natural gas and NGLs as there has been of oil. Furthermore, the decrease in demand for oil has significantly reduced the number of rigs drilling for oil in the continental U.S. and, as a result, estimates of future gas supply associated with oil production have declined. Additionally, the restart of economic activity in Asia and Europe, coupled with lower refinery liquefied petroleum gas (“LPG”) production from refineries in the U.S., Europe and Asia during the second quarter, provided support for international LPG prices relative to oil. Further, reductions in OPEC+ and North American oil production and the associated NGL volumes are expected to have a supportive effect on propane and butane prices into 2021. During the year ended December 31, 2020, all of our gathering, compression and processing revenues were derived from the production of natural gas.
Neither our nor Antero Resources’ supply chain has experienced any significant interruptions. The industry continues to experience storage capacity constraints for oil and certain NGL products, and Antero Resources may become subject to those constraints if it is not able to sell its production or certain components thereof, or enter into additional storage arrangements. The lack of a market or available storage for any one NGL product or oil could result in Antero Resources having to delay or discontinue well completions and commercial production or shut in production for other products as it has disclosed that it cannot curtail the production of individual products in a meaningful way without reducing the production of other products. Antero Resources has indicated that
the potential impacts of these constraints may include partial shut-in of production, although it is not able to determine the extent of or for how long any shut-ins may occur. Antero Resources has also indicated that because some of its wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, it has the ability to change the mix of products that it produces and wells that it completes to adjust its production to address takeaway capacity constraints for certain products. For example, Antero Resources has indicated that it has the ability to shut-in rich gas wells and still produce from its dry gas wells if processing or storage capacity of NGL products becomes further limited or constrained. Also, 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. Since the outbreak of the pandemic, Antero Resources has expanded its customer base and its condensate storage capacity within the basin. However, any production curtailments or shut-ins by Antero Resources or our other customers will reduce throughput for our gathering and processing systems. In addition, if our customers delay or discontinue drilling or completion activities, it will reduce the volumes of water that we handle and therefore revenues for our water distribution and handling business.
In addition, Antero Resources announced in April 2020 that it had reduced its drilling and completion capital budget for 2020 by approximately 34%. Antero Resources continues to monitor its five-year drilling plan and has indicated it will make further revisions as appropriate. Reducing its 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells are brought online, which will directly impact our throughput and cash flows for the same time periods.
During the years ended December 31, 2019 and 2020, we recognized various impairment charges related to certain freshwater delivery system assets and fully impaired our Clearwater Facility and goodwill. Additional impairment charges related to our assets may occur if we experience disruptions in operations, decreases in our revenues or other adverse effects of the COVID-19 pandemic.
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, we were able to recognize an income tax refund receivable in March 2020 of $55 million, including $11 million in income tax benefit for the current year and $44 million of previously recognized deferred income tax benefit. As of December 31, 2020, we had received $39 million of this refund.
The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control and may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under our Credit Facility and our ability to access the capital markets.
Commodity Price Risk
Our gathering and compression and water services agreements with Antero Resources provide for fixed-fee structures, and we intend to continue to pursue additional fixed-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 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.
2021 Capital Investment
During 2021, we plan to expand our existing Appalachian Basin gathering, compression and water handling infrastructure to accommodate Antero Resources’ announced development plans. Antero Resources’ announced 2021 consolidated drilling and completion budget of $590 million. Antero Resources announced that it plans to operate three drilling rigs and complete between 65 and 70 horizontal wells, substantially all of which are located on acreage dedicated to us. A further or extended decline in commodity prices could cause some of the development and production projects of Antero Resources or third parties to be uneconomic or less profitable, which could reduce gathering and water handling volumes in our current and future potential areas of operation. Those reductions in gathering and water handling volumes could reduce our revenue and cash flows and adversely affect our ability to return capital to holders of our common stock.
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, 2020, we repurchased 8 million shares for approximately $25 million under this program. We currently have approximately $150 million of share repurchase capacity remaining under this program.
On January 20, 2021, the Board declared a cash dividend on the shares of our common stock of $0.3075 per share for the quarter ended December 31, 2020. The dividend will be payable on February 11, 2021 to stockholders of record as of February 3, 2021.
The Board also declared a cash dividend of $138 thousand on the Series A Preferred Stock to be paid on February 16, 2021 in accordance with the terms of the Series A Preferred Stock, which are discussed in Note 14-Equity and Earnings Per Common Share to our consolidated financial statements
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’ 515,000 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 adjustments. In addition, we also provide fluid handling services for flowback and produced water, including blending, storage and transportation operations. These operations, along with our fresh water delivery systems, support well completion and production operations for Antero Resources. These services are provided by us directly or through third-parties with which we contract. For flowback and produced water services provided by third-parties, Antero Resources reimburses our third-party out-of-pocket costs plus 3%. For flowback and produced water services provided by us, we charge Antero Resources a cost of service fee. The initial term of the water services agreement runs to 2035. All of Antero Resources’ existing acreage is dedicated to us for gathering and compression services except for existing third-party commitments. Approximately 135,000 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, 2020, Antero Resources had disclosed estimated net proved reserves 17.6 Tcfe, of which 57% was natural gas, 42% were NGLs and 1% was oil. As of December 31, 2020, Antero Resources’ drilling inventory consisted of 2,133 identified potential horizontal well locations, approximately 1,531 of which were located on acreage dedicated to us, providing us with significant opportunity for growth as Antero Resources’ drilling program continues and its production increases.
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 “Item 6. Selected Financial Data-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 and oil to maintain or increase throughput on our systems. Our ability to maintain existing supplies of natural gas and oil and obtain additional supplies is primarily impacted by our acreage dedication and the level of successful drilling activity by Antero Resources and 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 treatment volumes are primarily driven by produced water volumes, which are a function of Antero Resources’ production. Other fluid handling volumes are driven by hydraulic fracturing activities and produced water volumes. Antero Resources’ consolidated acreage positions allow 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.
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 fresh water system. Other water handling costs, which include the costs related to water blending, relate to contract services performed by us and third parties. Our other water handling costs consist of labor, monitoring and repair and maintenance costs. Wastewater treatment costs vary directly with the water volumes treated, and the operating efficiency of the Clearwater Facility which was idled in September 2019 for the foreseeable future. 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.
Our general and administrative expenses also include equity-based compensation costs related to the Antero Midstream GP LP Long-Term Incentive Plan (“AMGP LTIP”) and the Series B Units prior to the Transactions. Equity-based compensation after the Transactions include (i) costs allocated to Antero Midstream Partners by Antero Resources for grants made prior to the Transactions pursuant to Antero Resources’ long-term incentive plan, (ii) costs due to Antero Midstream Corporation LTIP (the “AM LTIP”) and (iii) Series B Exchange. As of December 31, 2020, there were no unvested awards related to the AMGP LTIP or Series B Exchange.
● 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. In 2019, our impairment expense primarily related to (i) the Clearwater Facility, which was idled in the third quarter of 2019 and (ii) the impairment of goodwill associated with the fresh water delivery and services reporting unit. In 2020, our impairment expense primarily related to (i) the impairment of
goodwill associated with our gathering and processing reporting unit and (ii) the fresh water delivery assets in the Utica Shale region.
● 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.
● Interest. From January 1, 2019 through March 12, 2019, interest expense related to interest incurred on borrowings under AMGP’s credit facility, which was terminated on March 12, 2019 in connection with the Transactions. Following the closing of the Transactions on March 12, 2019, interest expense represented interest related to: (i) borrowings under our revolving credit facility, (ii) borrowings of $650 million under our 5.375% senior notes due September 15, 2024 (the “2024 Notes”), (iii) borrowings of $550 million of our 7.875% senior notes due May 15, 2026 (the “2026 Notes”), (iv) borrowings of $650 million of our 5.75% senior notes due March 1, 2027 (the “2027 Notes”), (v) borrowings of $650 million of our 5.75% senior notes due January 15, 2028 (the “2028 Notes”), (vi) operating leases and (vii) amortization of deferred financing costs incurred in connection with the revolving credit facility and the issuance of the 2024 Notes, 2026 Notes, 2027 Notes and 2028 Notes.
● 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 benefit to the extent our deferred tax assets exceed our deferred tax liabilities. Our deferred tax assets result from temporary differences between tax and financial statement income primarily from goodwill impairment and net operating loss carryforwards. At December 31, 2020, we had approximately $211 million of U.S. federal net operating loss carryforwards (“NOLs”), and approximately $315 million of state NOLs. The amount of deferred tax assets considered realizable, however, could change in the near term 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.
Items Affecting Comparability of Our Financial Results
Our historical financial results discussed below are not comparable to our future financial results primarily as a result of the Merger. The Merger has been accounted for as an acquisition by AMGP of Antero Midstream Partners under ASC 805, Business Combinations, and accounted for as a business combination with the acquired assets and liabilities of Antero Midstream Partners recorded at estimated fair value. Effective March 12, 2019, Antero Midstream commenced consolidating Antero Midstream Partners and its subsidiaries in the consolidated financial statements of Antero Midstream. As a result, our consolidated balance sheet as of December 31, 2019 includes the financial position of Antero Midstream Partners and its subsidiaries, and our consolidated statements of operations and comprehensive income and cash flows for the year ended December 31, 2019 include the results of operations of Antero Midstream Partners and its subsidiaries beginning on March 13, 2019.
The historical consolidated financial statements included herein are the financial statements of Antero Midstream, formerly AMGP, which prior to the Merger reflect that AMGP’s only income resulted from distributions made on the IDRs of Antero Midstream Partners and expenses were limited to general and administrative expenses and equity-based compensation. The consolidated financial statements for the year ended December 31, 2019 include the results of Antero Midstream Partners and its subsidiaries beginning on March 13, 2019.
Accordingly, in addition to presenting a discussion of our results of operations as reported, we are also presenting our pro forma results of operations, which give effect to the adjustments described in Exhibit 99.1 to this Annual Report on Form 10-K. The pro forma information presented below should be read in conjunction with the unaudited pro forma combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K and describe the assumptions and adjustments used in preparing such information. The pro forma adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the results of operations on a more meaningful basis.
Results of Operations as Reported
Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
Revenue and Direct Operating Expenses. Revenues from Antero Resources and direct operating expenses for the year ended December 31, 2019 reflect 294 days of revenue and operating expenses generated by Antero Midstream Partners after the completion of the Transactions on March 12, 2019.
General and administrative expenses. General and administrative expenses (excluding equity-based compensation expense) decreased 12% from $45 million for the year ended December 31, 2019 to $39 million for the year ended December 31, 2020. The decrease was primarily due to cost reduction efforts, partially offset by inclusion of general and administrative expenses of Antero Midstream Partners after the completion of the Transactions on March 12, 2019. Equity-based compensation decreased from $74 million for the year ended December 31, 2019 to $13 million for the year ended December 31, 2020 due to the 17,353,999 shares of Antero Midstream common stock that were issued in exchange for the 98,600 Series B Units then outstanding (the “Exchanged B Units”) that were fully vested on December 31, 2019.
Impairment of goodwill expense. Impairment of goodwill expense of $340 million for the year ended December 31, 2019 reflects (i) $42 million of impairment of goodwill expense associated with the Clearwater Facility and (ii) $298 million of impairment of goodwill expense associated with our fresh water delivery and services reporting unit. Impairment of goodwill expense of $575 million for the year ended December 31, 2020 was associated with our gathering system due to declines in commodity prices and the general industry environment.
Impairment of property and equipment expense. Impairment of property and equipment expense of $410 million for the year ended December 31, 2019 was primarily due to the idling of the Clearwater Facility. Impairment of property and equipment expense of $98 million for the year ended December 31, 2020 was primarily due to the impairment of fresh water delivery assets in the Utica Shale region.
Impairment of customer relationships expense. Impairment of customer relationships expense of $12 million for the year ended December 31, 2019 reflects an impairment of the customer relationships that were associated with the idled Clearwater Facility.
Depreciation expense. Depreciation expense increased from $96 million for the year ended December 31, 2019 to $109 million for the year ended December 31, 2020 as a result of our acquisition of Antero Midstream Partners on March 12, 2019.
Accretion and change in fair value of contingent acquisition consideration. Accretion expense of $8 million for the year ended December 31, 2019 relates to the contingent consideration payment that was made in January 2020. No additional contingent consideration is expected to be paid.
Interest expense. Interest expense increased $37 million from $110 million for the year ended December 31, 2019 to $147 million for the year ended December 31, 2020 as a result of the acquisition of Antero Midstream Partners (which included the assumption of approximately $2.4 billion of debt) and Antero Midstream Partners’ issuance of the 2028 Notes in June 2019 and 2026 Notes in November 2020.
Operating loss. Total operating loss decreased from a loss of $398 million for the year ended December 31, 2019 to $118 million for the year ended December 31, 2020. The decrease was due to (i) higher revenue and lower direct operating expenses and general and administrative expenses between periods as a result of the acquisition of Antero Midstream Partners on March 12, 2019 and cost reduction efforts and (ii) lower impairment of property and equipment and impairment of customer relationships for the year ended December 31, 2020 as compared to the same period in 2019, partially offset by higher impairment of goodwill expense for the year ended December 31, 2020 as compared to the same period in 2019.
Equity in earnings of unconsolidated affiliates. Equity in earnings of unconsolidated affiliates for the year ended December 31, 2019 represents AMGP’s equity investment in Antero Midstream Partners from January 1, 2019 through March 12, 2019 and the portion of the net income from Antero Midstream Partners’ investments in Stonewall and the Joint Venture, which is allocated to us based on our equity interests for the period from March 13, 2019 through December 31, 2019. Equity in earnings in unconsolidated affiliates increased by $35 million from $51 million for the year ended December 31, 2019 to $86 million for the year ended December 31, 2020 primarily attributable to an increase in the level of operations at the Joint Venture during the year ended December 31, 2020.
Income tax benefit (expense). Income tax benefit for the year ended December 31, 2019 was $102 million. Income tax benefit for the year ended December 31, 2020 was $56 million primarily due to the loss before taxes for the year ended December 31, 2020 coupled with an $11 million rate benefit related to the carryback of NOLs to prior tax years. This carryback generated a federal income tax receivable of $55 million, of which $39 million had been received as of December 31, 2020. This carryback is a result of a provision included in the CARES Act that allows corporations with 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 is taxable income, and claim an income tax refund in the applicable carryback years. The income tax receivable account is classified as a current asset on the balance sheet.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2019
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations -Results of Operations” in our 2019 Annual Report on Form 10-K for a discussion of the results of operations for the year ended December 31, 2018 compared to the year ended December 31, 2019.
Pro Forma Segment Results of Operations
Unless the context otherwise requires, references in this “Pro Forma Segment Results of Operations” to the “Company,” “we,” “us” or “our” refer to, and the results of operations discussed below relate to, the combined results of Antero Midstream Corporation and Antero Midstream Partners as if the Transactions had occurred on January 1, 2019.
The pro forma segment results of operations and the pro forma operations data for the year ended December 31, 2019 have been prepared to give pro forma effect to the Transactions as if they had occurred on January 1, 2019. The pro forma adjustments are based on currently available information and certain estimates and assumptions, including the final purchase price allocation for the acquisition of Antero Midstream Partners. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the significant effects of the Transactions.
The pro forma information is for illustrative purposes only. If the Transactions had occurred on January 1, 2019, operating results might have been materially different from those presented in the pro forma financial information. The pro forma financial information should not be relied upon as an indication of operating results that we would have achieved if the Transactions had taken place on January 1, 2019. In addition, future results may vary significantly from the pro forma results reflected herein and should not be relied upon as an indication of our future results. The pro forma information presented below should be read in conjunction with the unaudited pro forma combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K.
Pro Forma Segment Results of Operations for the year ended December 31, 2019
Pro Forma
Gathering and
Water
Pro Forma
Consolidated
(in thousands)
Processing
Handling
Adjustments
Unallocated (1)
Total
Year ended December 31, 2019
Revenues:
Revenue-Antero Resources
$
668,311
399,547
-
-
1,067,858
Revenue-third-party
-
-
-
Amortization of customer contracts
(29,850)
(27,160)
(13,864)
-
(70,874)
Total revenues
638,461
372,488
(13,864)
-
997,085
Operating expenses:
Direct operating
52,719
207,917
-
-
260,636
General and administrative (excluding equity-based compensation)
30,553
17,321
(15,345)
13,038
45,567
Equity-based compensation
7,105
3,063
-
65,826
75,994
Facility idling
-
11,401
-
-
11,401
Impairment of goodwill
-
340,350
-
-
340,350
Impairment of property and equipment
7,182
409,539
-
-
416,721
Impairment of customer relationships
-
11,871
-
-
11,871
Depreciation
47,974
69,259
3,130
-
120,363
Accretion and change in fair value of contingent acquisition consideration
-
10,004
-
-
10,004
Accretion of asset retirement obligations
-
-
-
Total operating expenses
145,533
1,080,975
(12,215)
78,864
1,293,157
Operating income (loss)
492,928
(708,487)
(1,649)
(78,864)
(296,072)
Other income (expenses):
Interest expense, net
-
-
(3,301)
(127,217)
(130,518)
Equity in earnings of unconsolidated affiliates
63,579
-
(1,185)
-
62,394
Income (loss) before taxes
556,507
(708,487)
(6,135)
(206,081)
(364,196)
Provision for income tax (expense) benefit
-
-
(23,346)
102,466
79,120
Net income (loss) and comprehensive income (loss)
$
556,507
(708,487)
(29,481)
(103,615)
(285,076)
Adjusted EBITDA(2)
$
829,558
(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 “Item 6. Selected Financial Data-Non-GAAP Financial Measures”.
Segment Results of Operations for the year ended December 31, 2020
Gathering and
Water
Consolidated
(in thousands)
Processing
Handling
Unallocated (1)
Total
Year ended December 31, 2020
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
12,778
Facility idling
-
15,219
-
15,219
Impairment of goodwill
575,461
-
-
575,461
Impairment of property and equipment
97,232
-
98,179
Depreciation
57,300
51,490
-
108,790
Accretion of asset retirement obligations
-
-
Loss on asset sale
2,689
-
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 (expenses):
Interest expense, net
-
-
(147,007)
(147,007)
Equity in earnings of unconsolidated affiliates
86,430
-
-
86,430
Income (loss) before taxes
37,999
(61,077)
(155,137)
(178,215)
Provision for 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 “Item 6. Selected Financial Data-Non-GAAP Financial Measures”.
The operating data below represents the operating data of Antero Midstream Corporation and its subsidiaries, including Antero Midstream Partners and its subsidiaries, for the years ended December 31, 2019 and 2020.
Year Ended
Amount of
December 31,
Increase
Percentage
2019(1)
or Decrease
Change
Operating Data:
Gathering-low pressure (MMcf)
963,799
1,069,822
106,023
%
Gathering-high pressure (MMcf)
948,496
1,058,119
109,623
%
Compression (MMcf)
866,912
991,726
124,814
%
Fresh water delivery (MBbl)
51,426
40,076
(11,350)
(22)
%
Treated water (MBbl)
7,137
-
(7,137)
*
Other fluid handling (MBbl)
19,495
20,945
1,450
%
Wells serviced by fresh water delivery
(27)
(23)
%
Gathering-low pressure (MMcf/d)
2,641
2,923
%
Gathering-high pressure (MMcf/d)
2,599
2,891
%
Compression (MMcf/d)
2,375
2,710
%
Fresh water delivery (MBbl/d)
(32)
(23)
%
Treated water (MBbl/d)
-
(20)
*
Other fluid handling (MBbl/d)
%
Average realized fees:
Average gathering-low pressure fee ($/Mcf)
$
0.33
0.33
-
*
Average gathering-high pressure fee ($/Mcf)
$
0.20
0.20
-
*
Average compression fee ($/Mcf)
$
0.19
0.20
0.01
%
Average fresh water delivery fee ($/Bbl)
$
3.89
3.96
0.07
%
Average treatment fee ($/Bbl)
$
4.51
-
(4.51)
*
Joint Venture Operating Data:
Processing-Joint Venture (MMcf)
385,402
523,739
138,337
%
Fractionation-Joint Venture (MBbl)
10,285
13,200
2,915
%
Processing-Joint Venture (MMcf/d)
1,056
1,431
%
Fractionation-Joint Venture (MBbl/d)
%
(1) Pro Forma.
Discussion of Results of Operations for the Year Ended December 31, 2019 (Pro Forma) Compared to Year Ended December 31, 2020
Revenues. Revenues decreased by 10% from $997 million, including the amortization of customer relationships of $71 million, for the year ended December 31, 2019 to $901 million, including the amortization of customer relationships of $71 million, for the year ended December 31, 2020. Gathering and processing revenues increased by 6%, from $638 million for the year ended December 31, 2019 to $674 million for the year ended December 31, 2020. Water handling revenues decreased by 39%, from $372 million for the year ended December 31, 2019 to $226 million for the year ended December 31, 2020. These fluctuations primarily resulted from the following:
Gathering and Processing
● low pressure gathering revenue decreased $8 million year over year due to $48 million in rebates to Antero Resources for achieving certain volumetric targets, partially offset by an increase in throughput volumes of 282 MMcf/d, which was due to 108 additional wells connected to our system during the year ended December 31, 2020;
● high pressure gathering revenue increased $25 million year over year due to an increase in throughput volumes of 292 MMcf/d, primarily as a result of the addition of one new high pressure gathering line placed in service and additional wells connected to our system during the year ended December 31, 2020; and
● compression revenue increased $26 million year over year due to an increase in throughput volumes of 335 MMcf/d, primarily due to the addition of one new compressor station that was placed in service and additional wells connected to our system during the year ended December 31, 2020.
Water Handling
● fresh water delivery revenue decreased $42 million year over year due to a decrease in fresh water delivery of 32 MBbl/d, as a result of a decrease in the number of wells completed by Antero Resources due to its reduced drilling and completion program during the year ended December 31, 2020;
● revenue from the Clearwater Facility decreased $32 million year-over-year from $32 million for the year ended December 31, 2019 to zero during the year ended December 31, 2020 due to the idling of the Clearwater Facility in September 2019; and
● other fluid handling services revenue decreased $66 million primarily due to a $76 million decrease in services that are billed at cost plus 3% as a result of operational efficiencies associated with our flowback and produced wastewater services, which commenced in the fourth quarter of 2019, and cost reductions, partially offset by a $10 million increase in water blending services.
Direct operating expenses. Total direct operating expenses decreased from $261 million for the year ended December 31, 2019 to $165 million for the year ended December 31, 2020. Gathering and processing direct operating expenses increased by 7% from $53 million for the year ended December 31, 2019 to $57 million for the year ended December 31, 2020. The increase was primarily due to the cost associated with the new compressor station that came online in 2020 as well as higher throughput volumes between periods. Water handling direct operating expenses decreased 48% from $208 million for the year ended December 31, 2019 to $109 million for the year ended December 31, 2020. The decrease was primarily due to operational efficiencies associated with flowback and produced wastewater services.
General and administrative (excluding equity-based compensation) expenses. General and administrative expenses (excluding equity-based compensation expense) decreased by 13% from $46 million for the year ended December 31, 2019 to $39 million for the year ended December 31, 2020 primarily due to cost reduction efforts, partially offset by legal costs associated with the Clearwater Facility.
Equity-based compensation expenses. Equity-based compensation expenses decreased from $76 million for the year ended December 31, 2019 to $13 million for the year ended December 31, 2020 due to the Exchanged B Units that were fully vested on December 31, 2019.
Impairment of goodwill expense. Impairment of goodwill expense of $340 million for the year ended December 31, 2019 reflects an impairment of the goodwill that was associated with the Clearwater Facility and the fresh water delivery and services reporting unit. 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 general industry environment.
Impairment of property and equipment expense. Impairment of property and equipment expense of $417 million for the year ended December 31, 2019 was primarily for the idling of the Clearwater Facility and the decommissioning of assets related to a third-party compressor station. 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 customer relationships expense. Impairment of customer relationships expense of $12 million for the year ended December 31, 2019 reflects an impairment of the customer relationships that were associated with the Clearwater Facility.
Depreciation expense. Total depreciation expense decreased by 10%, from $120 million for the year ended December 31, 2019 to $109 million for the year ended December 31, 2020. The decrease was primarily due to assets that were impaired during the third quarter of 2019 and the first quarter of 2020, partially offset by additional gathering, compression and water handling assets placed in service in 2020.
Accretion and change in fair value of contingent acquisition consideration. Accretion expense of $10 million for the year ended December 31, 2019 relates to the contingent consideration payment that was made in January 2020. No additional contingent consideration is expected to be paid.
Interest expense. Interest expense increased by 13%, from $131 million for the year ended December 31, 2019 to $147 million for the year ended December 31, 2020 primarily due to an increase in interest expense incurred on (i) higher borrowings under the Credit Facility during 2020, (ii) the 2027 Notes that were issued during the first quarter of 2019, (iii) the 2028 Notes that were issued during the second quarter of 2019 and (iv) the 2026 Notes that were issued during the fourth quarter of 2020.
Operating income (loss). Total operating loss was $296 million and $118 million the year ended December 31, 2019 and 2020, respectively. Gathering and processing operating income was $493 million for the year ended December 31, 2019. Gathering and processing operating loss was $48 million for the year ended December 31, 2020 primarily due to an impairment of goodwill. Water handling operating loss was $708 million for the year ended December 31, 2019 and $61 million for the year ended December 31, 2020 primarily due to impairment charges related to the Clearwater Facility and fresh water delivery assets in the Utica Shale region in 2019 and 2020, respectively.
Equity in earnings of unconsolidated affiliates. Equity in earnings in unconsolidated affiliates increased by 39%, from $62 million for the year ended December 31, 2019 to $86 million for the year ended December 31, 2020. Equity in earnings of unconsolidated affiliates represents the portion of the net income from our investments in Stonewall and the Joint Venture, which is allocated to us based on our equity interests. The increase is primarily attributable to an increase in the level of operations at the Joint Venture for the year ended December 31, 2020.
Net income (loss). Net loss was $285 million for the year ended December 31, 2019 primarily due to the impairments of property and equipment, goodwill and customer relationship for the Clearwater Facility. Net loss was $123 million for the year ended December 31, 2020 primarily due to impairment of goodwill associated with our gathering system and impairment of property and equipment of our freshwater delivery assets in the Utica Shale region.
Pro Forma Adjusted EBITDA. Pro Forma Adjusted EBITDA increased by 2%, from $830 million for the year ended December 31, 2019 to $850 million for the year ended December 31, 2020. The increase was primarily due to increased throughput and decreased direct operating expenses. For a discussion of the non-GAAP financial measure Pro Forma Adjusted EBITDA, including a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, read “Item 6. Selected Financial Data-Non-GAAP Financial Measures.”
Capital Resources and Liquidity as Reported
Sources and Uses of Cash
Capital resources and liquidity are provided by operating cash flows, cash on our balance sheet, borrowings under the 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.
In the year ended December 31, 2020, we paid dividends of $1.23 per share, or a total of $590 million, to holders of our common shares or common stock, as applicable, and we paid $550 thousand of dividends on our Series A Preferred Stock. On January 20, 2021, the Board declared a cash dividend on the shares of our common stock of $0.3075 per share for the quarter ended December 31, 2020 to be paid on February 11, 2021 to stockholders of record as of February 3, 2021. The Board also declared an aggregate cash dividend of $138 thousand on our Series A Preferred Stock to be paid on February 16, 2021. As of December 31, 2020, there were dividends in the amount of $69 thousand accumulated in arrears on our Series A Preferred Stock.
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, 2020
(in thousands)
Net cash provided by operating activities
$
83,531
622,387
753,382
Net cash used in investing activities
-
(525,675)
(219,231)
Net cash used in financing activities
(86,696)
(98,299)
(534,746)
Net decrease in cash and cash equivalents
$
(3,165)
(1,587)
(595)
Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
Operating Activities. Net cash provided by operating activities was $622 million and $753 million for the years ended December 31, 2019 and 2020, respectively. The increase in net cash provided by operating activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily the result of higher gathering and processing revenues, lower
direct operating and general and administrative costs and increased cash flows associated with the Merger between periods, partially offset by an increase in Clearwater Facility idling costs in 2020.
Investing Activities. Net cash flows used in investing activities was $526 million and $219 million for the years ended December 31, 2019 and 2020, respectively. The decrease in cash flows used in investing activities was due to a (i) $129 million decrease in investments made in unconsolidated affiliates, (ii) $109 million decrease in additions to our gathering system and (iii) $86 million decrease in additions to our water handling system. Additionally, cash flows provided by investing activities for the year ended December 31, 2019 included $620 million of cash received upon the acquisition of Antero Midstream Partners LP, which amount was borrowed by Antero Midstream Partners under the Credit Facility to fund, in part, $599 million of cash paid to Antero Midstream Partners unitholders as consideration in the Merger.
Financing Activities. Net cash used in financing activities was $98 million and $535 million for the years ended December 31, 2019 and 2020, respectively. 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. Net cash used in financing activities for the year ended December 31, 2019 included: (i) issuance of the 2028 Notes of $650 million; (ii); total distributions or dividends to our common stockholders, holders of Series B Units and preferred stockholders of $496 million; (iii) $125 million in repurchases of common stock; (iv) net payments on the Credit Facility of $116 million and (v) $9 million of payments for deferred financing.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2019
Refer to “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, 2019 for a discussion of the cash flows for the year ended December 31, 2018 compared to the year ended December 31, 2019.
2020 Capital Investments and 2021 Capital Budget
Antero Midstream Partners’ capital spending for the year ended December 31, 2020 included investing activities of (i) $141 million to our gathering system, (ii) $41 million to our water handling system and (iii) $25 million invested in our Joint Venture.
The Board approved a 2021 capital budget with a range of $240 million to $260 million, which includes approximately $65 million of additional growth capital supporting the increased volumes expected from Antero Resources’ drilling partnership in addition to its previously disclosed maintenance capital program for 2021. Our 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”), entered into a senior secured revolving credit facility (the “Credit Facility”) with a consortium of banks on October 26, 2017. The Credit Facility includes fall away covenants and lower interest rates that are triggered if and when the Borrower elects to enter into an Investment Grade Period (as defined in the Credit Facility). The Credit Facility provides for borrowing under either the Eurodollar Rate or the Base Rate (as each term is defined in the Credit Facility).
The Credit Facility has lender commitments of $2.13 billion and matures on October 26, 2022. As of December 31, 2020, we had $614 million of borrowings and no letters of credit outstanding under the Credit Facility.
We have a choice of borrowing in Eurodollars 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 Eurodollar loans, the last day of each Interest Period (as defined below); provided that if any Interest Period for a Eurodollar loan exceeds three months, interest will be payable on the respective dates that fall every three months after the beginning of such Interest Period. Eurodollar loans bear interest at a rate per annum equal to the LIBOR Rate administered by the ICE Benchmark Administration for one, two, three, six or, if available to the lenders, twelve months (the “Interest Period”) plus an applicable margin ranging from 125 to 225 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 Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 25 to 125 basis points (subject to certain exceptions) depending on the leverage ratio then in effect.
The Credit Facility is guaranteed by our subsidiaries and is secured by mortgages on substantially all of Antero Midstream Partners’ and its subsidiaries’ properties. The Credit Facility contains restrictive covenants that may limit our ability to, among other things:
● incur additional indebtedness;
● sell assets;
● make loans to others;
● make investments;
● 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, 2020.
Senior Notes
The following table summarizes the material terms of our senior unsecured notes as of December 31, 2020:
2024 Notes
2026 Notes
2027 Notes
2028 Notes
Outstanding principal (in thousands)
$
650,000
$
550,000
$
650,000
$
650,000
Interest rate
5.375
%
7.875
%
5.75
%
5.75
%
Maturity date
September 15, 2024
May 15, 2026
March 1, 2027
January 15, 2028
Interest payment dates
Mar. 15, Sept. 15
May 15, Nov. 15
Mar. 1, Sept. 1
Jan. 15, July 15
Make-whole redemption date (1)
September 15, 2022
May 15, 2025
March 1, 2025
January 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.
Please refer to Note 10-Long-term Debt to the consolidated financial statements for more information on our senior notes.
Contractual Obligations
Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance. A summary of our contractual obligations by maturity date as of December 31, 2020 is provided in the following table.
Year Ending December 31,
(in millions)
Thereafter
Total
Credit Facility (1)
$
-
-
-
-
-
Senior notes-principal
-
-
-
-
1,850
2,500
Senior notes-interest
Asset retirement obligations
-
-
-
Total
$
2,024
4,026
(1) Includes outstanding principal amounts on the Credit Facility as of December 31, 2020. This table does not include future commitment fees, interest expense or other fees on the Credit Facility because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.
Critical Accounting Policies and Estimates
The following discussion relates to the critical accounting policies and estimates for both the Company and our Predecessor. 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 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 deliver 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. This contingent consideration liability is valued based on Level 3 inputs related to the expected average volumes and weighted average cost of capital and was recorded at the time of such acquisition in
accordance with accounting guidance for business combinations. In January 2020, Antero Midstream Partners paid Antero Resources $125 million and, as of December 31, 2020, no additional contingent acquisition consideration was earned.
General and Administrative and Equity-Based Compensation Costs
General and administrative costs are charged or allocated to us based on the nature of the expenses and are allocated based on our proportionate share of Antero Resources’ gross property and equipment, capital expenditures and labor costs, as applicable. These allocations are based on estimates and assumptions that management believes are reasonable.
Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Estimating the fair value of each award requires management to apply judgment.
Equity-based compensation expenses that are subject to allocation as described in “-Principal Components of our Cost Structure,” are allocated to us based on our proportionate share of Antero Resources’ labor costs. These allocations are based on estimates and assumptions that management believes are reasonable.
New Accounting Pronouncements
There were no new accounting pronouncements issued during the year ended December 31, 2020 that had or are expected to have a material effect on the Company’s financial reporting.
Off-Balance Sheet Arrangements
As of December 31, 2020, we did not have any off-balance sheet arrangements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 structures, and we intend to continue to pursue additional fixed-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 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, 2020, we had $614 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 $11 million increase in interest expense for the year ended December 31, 2020.
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’ 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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 of this Annual Report on Form 10-K and are incorporated herein by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.

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ITEM 9A. CONTROLS AND PROCEDURES
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, 2020 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, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Our internal control over financial reporting includes those policies and procedures that:
(i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets;
(ii)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
(iii)
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect all misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework in 2013, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2020.
The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by KPMG LLP, an independent registered public accounting firm which also audited our consolidated financial statements as of and for the year ended December 31, 2020, as stated in their report which appears on page in this Annual Report on Form 10-K.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 2021 Annual Meeting of Stockholders.
Code of Ethics
We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of our Corporate Code of Business Conduct and Ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and other persons performing similar functions by posting such information in the “Governance” subsection of our website at www.anteromidstream.com.

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ITEM 11. EXECUTIVE COMPENSATION
Item 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 2021 Annual Meeting of Stockholders.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2021 Annual Meeting of Stockholders.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2021 Annual Meeting of Stockholders.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
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 2021 Annual Meeting of Stockholders.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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.
(a)(3) Exhibits.
Exhibit
Number
Description of Exhibit
2.1
Simplification Agreement, dated as of October 9, 2018, by and among AMGP GP LLC, Antero Midstream GP LP, Antero IDR Holdings LLC, Arkrose Midstream Preferred Co LLC, Arkrose Midstream NewCo Inc., Arkrose Midstream Merger Sub LLC, Antero Midstream Partners GP LLC and Antero Midstream Partners LP (incorporated by reference to Exhibit 2.1 to Antero Midstream GP LP’s Current Report on Form 8-K (Commission File No. 001-38075) filed on October 10, 2018).
3.1
Certificate of Conversion of Antero Midstream Corporation, dated March 12, 2019 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
3.2
Certificate of Incorporation of Antero Midstream Corporation, dated March 12, 2019 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
3.3
Bylaws of Antero Midstream Corporation, dated March 12, 2019 (incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
3.4
Certificate of Designations of Antero Midstream Corporation, dated March 12, 2019 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
4.1
Indenture, dated as of September 13, 2016, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on September 13, 2016).
4.2
Form of 5.375% Senior Note due 2024 (incorporated by reference to Exhibit 4.2 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on September 13, 2016).
4.3
First Supplemental Indenture, dated as of January 17, 2017, among Antero Midstream Partners LP, Antero Midstream Finance Corporation, Antero Midstream Corporation, each of the other parties identified therein and Wells Fargo Bank, National Association, a national banking association to the indenture governing the 2024 Notes (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
4.4
Second Supplemental Indenture, dated as of April 15, 2019, among Antero Midstream Partners LP, Antero Midstream Finance Corporation, Antero Midstream Corporation, each of the other parties identified therein and Wells Fargo Bank, National Association, a national banking association to the indenture governing the 2024 Notes (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on April 16, 2019).
4.5
Indenture, dated as of February 25, 2019, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on February 25, 2019).
4.6
Form of 5.75% Senior Note due 2027 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on February 25, 2019).
4.7
First Supplemental Indenture, dated as of April 15, 2019, among Antero Midstream Partners LP, Antero Midstream Finance Corporation, Antero Midstream Corporation, each of the other parties identified therein and Wells Fargo Bank, National Association, a national banking association, to the indenture governing the 2027 Notes (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on April 16, 2019).
4.8
Indenture, dated as of June 28, 2019, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 28, 2019).
4.9
Form of 5.75% Senior Note due 2028 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on June 28, 2019).
4.10
Registration Rights Agreement, dated March 12, 2019, by and among the Company, Antero Resources Corporation, Arkrose Subsidiary Holdings LLC, Glen C. Warren, Jr., Canton Investment Holdings LLC, Paul M. Rady, Mockingbird Investments, LLC and the other holders named therein (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
4.11
Indenture, dated as of November 10, 2020, by and among Antero Midstream Partners LP, Antero Midstream Finance Corporation, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on November 10, 2020)
4.12
Form of 7.875% Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on November 10, 2020).
4.13
Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended (incorporated by reference to Exhibit 4.11 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.1
Second Amended and Restated Gathering and Compression Agreement, dated as of December 8, 2019, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.2
Amended and Restated Secondment Agreement, effective as of March 13, 2019, by and between Antero Midstream Corporation, Antero Midstream Partners LP, Antero Midstream Partners GP LLC, Antero Midstream LLC, Antero Water LLC, Antero Treatment LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.3
Second Amended and Restated Services Agreement, effective as of March 13, 2019, by and among Antero Midstream Partners LP, Antero Midstream Corporation, Antero Midstream Partners GP LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.4**
Amended and Restated Water Services Agreement, dated as of February 12, 2019, by and between Antero Resources Corporation and Antero Water LLC (incorporated by reference to Exhibit 10.4 to Antero Midstream Partners LP’s Annual Report on Form 10-K (Commission File No. 001-36719) filed on February 13, 2019).
10.5
Amended and Restated Contribution Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.6
Second Amended and Restated Right of First Offer Agreement, dated as of February 13, 2018, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.2 to Antero Midstream Partners LP’s Quarterly Report on Form 10-Q (Commission File No. 001-36719) filed on April 25, 2018).
10.7
License Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.4 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.8
First Amendment and Joinder Agreement, dated as of October 31, 2018 (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 2, 2018).
10.9
Second Amendment, dated as of February 26, 2019, by and among the Lenders party thereto, Antero Midstream Partners LP, and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.10
Joinder Agreement, dated as of November 19, 2019, by and among the Lenders party thereto, Antero Midstream Partners LP, and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
10.11
Amended and Restated Credit Agreement, by and among Antero Midstream Partners LP, the lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Quarterly Report on Form 10-Q (Commission File No. 001-36719) filed on November 1, 2017).
10.12†
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on March 12, 2019).
10.13†
Antero Midstream Corporation Long Term Incentive Plan, effective as of March 12, 2019 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K/A (Commission File No. 001-38075) filed on March 12, 2019).
10.14†
Letter to Phantom Unitholders under the Antero Midstream Partners LP Long-Term Incentive Plan Regarding the Phantom Unit Exchange (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on May 1, 2019).
10.15†
Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement under the Antero Midstream Corporation Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on July 31, 2019).
10.16†
Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement under the Antero Midstream Corporation Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on July 31, 2019).
10.17†
Form of Phantom Unit Agreement under the Antero Midstream Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to Antero Midstream Partners LP’s Registration Statement on Form S-8 (Commission File No. 333-200111) filed on November 12, 2014).
10.18†
Global Grant Amendment to Grant Notices and Award Agreements Under the Antero Midstream Partners LP Long-Term Incentive Plan, effective as of October 24, 2016 (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Quarterly Report on Form 10-Q (Commission File No. 001-36719) filed on October 26, 2016).
10.19†
Form of Retention Award Grant Notice and Retention Award Agreement under the Antero Midstream Corporation Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on April 29, 2020).
10.20†
Form of Retention Award Grant Notice and Retention Award Agreement under the Antero Midstream Corporation Long Term Incentive Plan (Employees) (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-38075) filed on October 28, 2020).
10.21
Stockholders’ Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP, Arkrose Subsidiary Holdings LLC, Paul M. Rady, Mockingbird Investment, LLC, Glen C. Warren, Jr., Canton Investment Holdings LLC and the other holders named therein (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (Commission File No. 001-38075) filed on October 10, 2018).
21.1*
Subsidiaries of Antero Midstream Corporation.
22.1*
List of Guarantor and Issuer Subsidiaries.
23.1*
Consent of KPMG LLP.
31.1*
Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*
Certification of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*
Certification of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
99.1
Unaudited pro forma condensed combined financial statements of Antero Midstream Corporation (incorporated by reference to Exhibit 99.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-38075) filed on February 12, 2020).
101*
The following financial information from this Form 10-K of Antero Midstream Corporation for the year ended December 31, 2020, 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 (formatted as Inline XBRL and contained in Exhibit 101).
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