UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended | |
or | |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
Commission File No.
(Exact name of registrant as specified in its charter)
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(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act: | ||||
Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||
Securities Registered Pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ⌧
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ◻ Yes ⌧
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ⌧
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ⌧
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Emerging growth company | Accelerated filer ◻ | Non-accelerated filer ◻ | Smaller reporting company |
If an emerging growth company, indicate by checkmark if the registrant has elected to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $
The registrant had
Documents incorporated by reference: Portions of the registrant’s proxy statement for its annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end are incorporated by reference into Part III of this Annual Report on Form 10-K.
TABLE OF CONTENTS
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this Annual Report on Form 10-K may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering these forward-looking statements, investors should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. These forward-looking statements are management’s belief, based on currently available information, as to the outcome and timing of future events. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
| ● | Antero Resources Corporation’s (“Antero Resources”) expected production and development plan; |
| ● | our ability to execute our business strategy; |
| ● | our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness; |
| ● | our ability to realize the anticipated benefits of our investments in unconsolidated affiliates; |
| ● | natural gas, natural gas liquids (“NGLs”) and oil prices; |
| ● | our ability to complete the construction of or purchase new gathering and compression, processing, water handling or other assets on schedule, at the budgeted cost or at all, and the ability of such assets to operate as designed or at expected levels; |
| ● | our ability to successfully complete our share repurchase program; |
| ● | competition and government regulations; |
| ● | actions taken by third-party producers, operators, processors and transporters; |
| ● | legal or environmental matters; |
| ● | costs of conducting our operations; |
| ● | general economic conditions; |
| ● | credit markets; |
| ● | operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control; |
| ● | uncertainty regarding our future operating results; and |
| ● | our other plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K. |
We caution investors that these forward-looking statements are subject to all of the risks and uncertainties incidental to our business, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, environmental risks, Antero Resources’ drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting Antero Resources’ future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under the heading “Risk Factors” in this Annual Report on Form 10-K.
Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
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All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K.
GLOSSARY OF COMMONLY USED TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in our industry:
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, NGLs, or water.
“Bbl/d.” Bbl per day.
“Bcf.” One billion cubic feet of natural gas.
“Bcfe.” One billion cubic feet of natural gas equivalent with one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.
“Bcfe/d.” Bcfe per day.
“DOT.” Department of Transportation.
“Dry gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
“EPA.” Environmental Protection Agency.
“Expansion capital.” Cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.
“FERC.” Federal Energy Regulatory Commission.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“High pressure pipelines.” Pipelines gathering or transporting natural gas that has been dehydrated and compressed to the pressure of the downstream pipelines or processing plants.
“Hydrocarbon.” An organic compound containing only carbon and hydrogen.
“Joint Venture.” The joint venture entered into on February 6, 2017 between Antero Midstream Partners L.P. (“Antero Midstream Partners”), which is our wholly owned subsidiary, and MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, LP (“MPLX”), to develop processing and fractionation assets in Appalachia.
“Low pressure pipelines.” Pipelines gathering natural gas at or near wellhead pressure that has yet to be compressed (other than by well pad gas lift compression or dedicated well pad compressors) and dehydrated.
“Maintenance capital.” Cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue.
“MBbl.” One thousand Bbls.
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“MBbl/d.” One thousand Bbls per day.
“Mcf.” One thousand cubic feet of natural gas.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet of natural gas.
“MMcf/d.” One million cubic feet per day.
“Natural gas.” Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutene and normal butane, and natural gasoline.
“NYMEX.” New York Mercantile Exchange.
“Oil.” Crude oil and condensate.
“SEC.” United States Securities and Exchange Commission.
“Tcfe.” One trillion cubic feet of natural gas equivalent with one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.
“Throughput.” The volume of product transported or passing through a pipeline, plant, terminal or other facility.
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PART I
References in this Annual Report on Form 10-K to the “Company,” “ARMM,” “we,” “our,” “us” or like terms, when referring to periods prior to May 4, 2017, refer to our predecessor, Antero Resources Midstream Management LLC and its consolidated subsidiaries, which did not include Antero Midstream Partners LP (“Antero Midstream Partners”) or its consolidated subsidiaries. References to the “Company,” “AMGP,” “we,” “our,” “us” or like terms, when referring to periods beginning on May 4, 2017 and ending on March 12, 2019, refer to our predecessor, Antero Midstream GP LP and its consolidated subsidiaries, which did not include Antero Midstream Partners or its consolidated subsidiaries. References to the “Company,” “Antero Midstream,” “AMC,” “we,” “our,” “us” or like terms, when referring to periods beginning on March 13, 2019 and prospectively, refer to Antero Midstream Corporation and its consolidated subsidiaries, including Antero Midstream Partners and its subsidiaries. References in this Annual Report on Form 10-K to the Company’s, Antero Midstream’s, AMC’s or our (i) indebtedness refer to the indebtedness of Antero Midstream Partners and (ii) operational or capital spending information refer to the operational or capital spending information of (1) for all periods prior to March 12, 2019, Antero Midstream Partners and its consolidated subsidiaries, and (2) for all periods on or after March 13, 2019, Antero Midstream and its consolidated subsidiaries, including Antero Midstream Partners and its subsidiaries.
Items 1 and 2. Business and Properties
Our Company and Organization Structure
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 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 Marcellus and Utica Shale plays. 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 Marcellus and Utica Shales in West Virginia and Ohio. Our assets also include two independent fresh water delivery systems that deliver fresh water from the Ohio River and several regional waterways. These fresh water delivery systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilitates, 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. 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, 2019, all of Antero Resources’ approximate 594,000 gross acres (541,000 net acres) are dedicated to us for gathering, compression and water services, except for approximately 140,000 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 Ritchie, Tyler and Wetzel Counties in West Virginia. 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 West Virginia, Ohio and Pennsylvania for gathering and compression services and all of its acreage within defined service areas in West Virginia and Ohio for water services. We also have certain rights of first offer with respect to gathering, compression, processing, and
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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.
Under 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 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 deliver 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. As a result, in January 2020, we paid Antero Resources $125 million. In the two-year period ended December 31, 2019, we delivered 123 million of the 219 million barrels of fresh water, and we do not expect to deliver at least 219 million barrels by December 31, 2020 based on Antero Resources’ 2020 budget.
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. The fresh water delivery services 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. As of December 31, 2019, we had the ability to store 5.8 million barrels of fresh water in 38 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. For additional information, please read “—Developments and Highlights—Idling of the Clearwater Facility.”
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.
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.
Developments and Highlights
2019 Capital Investments
For the year ended December 31, 2019, our total capital spending was $469 million, which included $414 million of expansion capital and $55 million of maintenance capital. We spent an aggregate of $315 million for gathering and compression infrastructure. The additional gathering and compression infrastructure included 37 miles of pipelines in the Marcellus and Utica Shales combined. Additionally, we invested an aggregate of $154 million in water infrastructure to construct 47 miles of additional buried fresh water pipelines and surface pipelines. Substantially all capital spending was invested in the Marcellus Shale. We also invested $179 million in our unconsolidated affiliates.
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2020 Capital Budget
During 2020, we plan to expand our existing Marcellus and Utica Shale gathering, processing and fresh water delivery infrastructure to accommodate Antero Resources’ development plans. Antero Resources announced that it plans to operate an average of four drilling rigs and complete between 120 and 130 horizontal wells, substantially all of which are expected to be located on acreage dedicated to us. Antero Resources’ announced 2020 drilling and completion capital budget is $1.15 billion. Our 2020 capital budget is a range of $300 million to $325 million.
Growth Incentive Fee Program With Antero Resources
On December 8, 2019, we and Antero Resources amended the existing gathering and compression agreement to establish a growth incentive fee program whereby we will provide quarterly fee reductions to Antero Resources from 2020 through 2023, contingent upon Antero Resources achieving volumetric growth targets on low pressure gathering. The compression, high pressure gathering and fresh water delivery fees payable to us were unchanged. In addition, we and Antero Resources agreed to extend the primary term of the gathering and compression for four additional years to November 10, 2038. The following table summarizes the low pressure gathering growth incentive targets 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 Year 2020 | |||||
First Quarter | >2,700 | $12 | |||
Second Quarter | >2,700 | $12 | |||
Third Quarter | >2,800 | $12 | |||
Fourth Quarter | >2,900 | $12 | |||
Calendar Years 2021-2023 | |||||
Threshold 1 | >2,900 and <3,150 | $12 | |||
Threshold 2 | >3,150 and <3,400 | $15.5 | |||
Threshold 3 | >3,400 | $19 |
Return of Capital Program
On August 12, 2019, our Board of Directors (the “Board”) authorized a share repurchase program to opportunistically repurchase up to $300 million of shares of our outstanding common stock through June 30, 2021. During the year ended December 31, 2019, we repurchased 22.9 million shares for approximately $125 million under this program. This included 19.4 million shares from Antero Resources at a price of $5.16 per share in December 2019, and we currently have approximately $175 million of share repurchase capacity remaining under this program.
On January 15, 2020, the Board declared a cash dividend on the shares of our common stock of $0.3075 per share for the quarter ended December 31, 2019. The dividend will be payable on February 12, 2020 to stockholders of record as of January 31, 2020.
The Board also declared a cash dividend of $138 thousand on our shares of Series A Non-Voting Perpetual Preferred Stock, par value $0.01 (the “Series A Preferred Stock”) to be paid on February 14, 2020 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.
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Idling of the Clearwater Facility
On September 18, 2019, we commenced a strategic evaluation of the Clearwater Facility. Based on the preliminary results of our evaluation and ongoing discussions with the Clearwater Facility’s contractor, the Clearwater Facility was idled. We expect the Clearwater Facility to continue to be idled for the foreseeable future. The decision to idle the Clearwater Facility was driven by its inability to operate at its intended specifications. Accordingly, we recorded impairment charges related to the Clearwater Facility of $409 million for property and equipment, $42 million of goodwill and $12 million in customer relationships during the year ended December 31, 2019. See Note 4—Clearwater Facility Impairment to our consolidated financial statements. We incurred $11 million in facility idling costs for the care and maintenance of the Clearwater Facility during the period from September 18, 2019 through December 31, 2019. 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.
Closing of Simplification Transaction
On March 12, 2019, AMGP and Antero Midstream Partners completed certain simplification transactions pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among AMGP, Antero Midstream Partners and certain of their affiliates (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 fair value.
Financial Results as Reported
For the year ended December 31, 2019, we generated cash flows from operations of $622 million and a net loss of $355 million. This compares to cash flows from operations of $84 million and net income of $67 million for the year ended December 31, 2018. For the year ended December 31, 2019, we consolidated the results of Antero Midstream Partners and its subsidiaries after March 12, 2019, whereas for the year ended December 31, 2018 and for the period from January 1, 2019 through March 12, 2019, our source of income and cash flow was solely from the incentive distribution rights of Antero Midstream Partners.
Credit Facility
Antero Midstream Partners, as borrower (the “Borrower”), has a senior secured revolving credit facility (the “Credit Facility”) with a consortium of banks. We will fund our operations through our operating cash flows, cash on our balance sheet, borrowings under the Credit Facility and capital market transactions. We increased lender commitments under the Credit Facility from $2.0 billion to $2.13 billion on November 19, 2019. At December 31, 2019, we had $960 million outstanding and no letters of credit outstanding under the Credit Facility. The maturity date of the Credit Facility is October 26, 2022. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Debt Agreements—Antero Midstream Partners Revolving Credit Facility” for a description of the Credit Facility.
Our Assets
The following table provides information regarding our gathering and processing systems as of December 31, 2019:
Low-Pressure | High-Pressure | Compression | |||||
| Pipeline (miles) |
| Pipeline (miles) |
| Capacity (MMcf/d) | ||
Marcellus | 173 | 151 | 2,505 | ||||
Utica | 74 | 36 | 320 | ||||
Total | 247 | 187 | 2,825 |
The following table provides information regarding our water handling systems as of December 31, 2019:
Buried Fresh | Surface Fresh | ||||
Water Pipeline | Water Pipeline | ||||
| (miles) |
| (miles) | ||
Marcellus | 149 | 98 | |||
Utica | 54 | 31 | |||
Total | 203 | 129 |
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Our Relationship with Antero Resources
Antero Resources has a 28.7% ownership interest in us. 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, 3.2 Bcfe/d net (30% liquids) during 2019, an increase of 19% as compared to 2018. As of December 31, 2019, Antero Resources’ estimated net proved reserves were 18.9 Tcfe, which were comprised of 61% natural gas, 38% NGLs, and 1% oil. As of December 31, 2019, Antero Resources’ drilling inventory consisted of 2,385 identified potential horizontal well locations (approximately 1,685 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 2020 drilling and completion budget is $1.15 billion, and includes plans to operate an average of four drilling rigs, primarily in the Marcellus Shale. 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 “—Contractual Arrangement with Antero Resources.”
We 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 contains 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. Additional high pressure lines and compressor stations installed on our own initiative are not subject to such volume commitments. These minimum volume commitments on new infrastructure are intended to support the stability of our cash flows.
Water Handling Services
Pursuant to the water services agreement, we provide certain water handling services to Antero Resources within an area of dedication in defined service areas in Ohio and West Virginia. We also have certain rights of first offer with respect to water services for acreage located outside of the existing dedicated areas. Antero Resources agreed to pay us for all water handling services provided by us in accordance with the terms of the water services agreement. As of the start of 2020, there are no minimum volume commitments under this agreement. 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. On February 12, 2019, Antero Resources and Antero Midstream Partners amended and restated the water services agreement to, among other things, make certain clarifying changes with respect to the CPI adjustments. The initial term of the water services agreement runs to 2035.
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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 Marcellus Shale to certain third parties’ gathering and compression services. We refer to this acreage dedication as the “excluded acreage.” As of December 31, 2019, the excluded acreage consisted of approximately 140,000 of Antero Resources’ existing gross leasehold acreage, which included approximately 700 of Antero Resources’ 2,385 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 take-or-pay contracts with volume commitments for certain third parties’ high pressure gathering and compression services. Specifically, those volume commitments consist of up to an aggregate of 750 MMcf/d on four high pressure gathering pipelines and 1,020 MMcf/d on nine compressor stations.
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.
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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, or 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, or 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, or 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.
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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, or 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. On January 2, 2020, 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 $1,291,894 per violation per day.
Pipeline Safety Regulation
Some of our gas pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, or 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, or PSIA, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or 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 a 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
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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 regulation.
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. 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. These additional rulemakings are expected to be effective by mid-2020.
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;
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● limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands, coastal regions or areas inhabited by endangered or threatened species;
● 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.
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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, or RCRA, and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many 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.
The Clearwater Facility operates pursuant to West Virginia Department of Environmental Protection (“DEP”) permits for the management of stormwater and wastewater and the disposal and management of solid waste. The produced water, flowback water, and other waste associated with shale development treated at the Clearwater Facility are exempt from RCRA hazardous waste regulations. Likewise, the input (residual salt derived from the wastewater treated at the Clearwater Facility) and output (leachate derived from precipitation run-off contacting the non-hazardous salt) to and from the landfill also qualify as exploration and production-exempt non-hazardous wastes because they derive from non-hazardous exempt material. However, in the event that hazardous non-exempt waste streams are introduced to and mix with the exempt waste at the Clearwater Facility, or if we otherwise fail to handle or treat such exempt materials pursuant to our West Virginia DEP permits, we may be subject to penalties and/or corrective action measures. Additionally, in the event that we dispose of sludges containing naturally occurring radioactive material (generated at the Clearwater Facility) at the landfill or other third-party facility that is not authorized to receive such radioactive waste, we may be subject to significant liabilities in the form of administrative, civil or criminal penalties and/or remedial obligations to remove previously disposed radioactive wastes and remediate contaminated property. The Clearwater Facility was idled in the third quarter of 2019 and we expect will remain idled for the foreseeable future.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act, or 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.
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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, or 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, or BACT, to limit air emissions. In addition, in June 2016, the EPA finalized rules under the federal Clean Air Act regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries and compressor stations), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. Several EPA new source performance standards, or NSPS, and national emission standards for hazardous air pollutants, or 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, or 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. 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 U.S. Army Corps of Engineers issued a final rule defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the U.S. (the “WOTUS rule”). Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule. For example, 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. However, legal challenges to the new rule are expected, and multiple challenges to the EPA’s prior rulemakings remain pending. 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.
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, or 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.
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Endangered Species
The federal Endangered Species Act, or 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, or 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, or 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. Following the change in presidential administrations, there have been attempts to modify these regulations. Most recently, in August 2019, the EPA proposed amendments to the 2016 standards that, among other things, would remove sources in the transmission and storage segment from the oil and natural gas source category and rescind the methane-specific requirements applicable to sources in the production and processing segments of the industry. As an alternative, the EPA also proposed to rescind the methane-specific requirements that apply to all sources in the oil and natural gas industry, without removing the transmission and storage sources from the current source category. Under either alternative, the EPA plans to retain emissions limits for VOCs. Legal challenges to any final rulemaking that rescinds the 2016 standards are expected. As a result of these developments, future implementation of the 2016 standards is uncertain at this time. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. These rules (and any additional regulations) could impose new compliance costs and permitting burdens on natural gas operations.
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In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates seeking the office of the President of the United States in 2020. Two critical declarations made by one or more candidates running for the Democratic nomination for President include threats to take actions banning hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions that could be pursued by presidential candidates may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as the reversal of the United States’ withdrawal from the Paris Agreement in November 2020. 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 exploration and production 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, such as rising sea levels, and therefore are responsible for roadway and infrastructure 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 by failing to adequately disclose those impacts.
Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Increased scrutiny because of climate change related concern could result in a loss of certain investors. In addition, institutional lenders may, of their own accord, elect not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for companies to engage in exploration and production activities.
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 2019, nor do we anticipate that such expenditures will be material in 2020.
Our Officers and Employees Provide Services to Both Antero Resources and Us
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, 2019, approximately 547 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 satisfactory.
Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. See “Item 3. Legal Proceedings.”
We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
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Address, Website and Availability of Public Filings
Our principal executive offices are at 1615 Wynkoop Street, Denver, Colorado 80202. Our telephone number is (303) 357-7310. Our website is located at www.anteromidstream.com.
We file or furnish our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.
We also make available free of charge our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. These documents are located www.anteromidstream.com under the “Investors” link.
Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.
Item 1A. Risk Factors
We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks described in this Annual Report on Form 10-K could materially and adversely affect our business, financial condition, cash flows and results of operations. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.
Because substantially all of our revenue is 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
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have on Antero Resources’ ability to execute its drilling and development program or perform under our gathering and compression and water handling services agreements. 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, 2019 (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. In order 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’ acquisition of additional acreage, including acquisitions that offset any dispositions by Antero Resources, (iii) Antero Resources’ ability to replace declining production 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. In order 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; |
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| ● | 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 $4.25 per MMBtu to a low of $1.75 per MMBtu in 2019, and the daily spot prices for NYMEX West Texas Intermediate crude oil ranged from a high of $66.24 per barrel to a low of $46.31 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 61% 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 2020 capital budgets. For example, Antero Resources’ 2020 capital budget is between $1.15 billion, compared to 2019 capital expenditures of $1.3 billion. This will have a significant effect on our capital resources, liquidity and expected operating results. Natural gas and oil prices directly affect Antero Resources’ production. If prices decrease further, it could reduce our revenues, cash flows and results of operations. 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 of 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.
The gathering and compression agreement only includes minimum volume commitments 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. Any decrease in the current levels of throughput on our gathering and compression systems could reduce our revenue and cash flows.
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We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, we may be unable to expand our business operations and/or our financial leverage could increase.
In order 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.
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 Marcellus and Utica Shales. 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.
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.
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
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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 revolving credit facility and the indentures governing our senior notes 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.
We own a 50% interest in the Joint Venture, which is operated by MarkWest Energy. 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; |
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| ● | 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 Marcellus and Utica regions 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.
If additional takeaway pipelines or other future pipeline projects are not completed, Antero Resources’, and correspondingly, the Company’s, future growth may be limited.
Antero Resources has secured sufficient long-term firm takeaway capacity in each of its core operating areas to accommodate its current development plans, including through major pipelines that are in existence and through third-party trucking services; however, any failure of any future pipeline to be completed, any unavailability of existing takeaway pipelines or the failure of any third party to perform under its service contracts, could cause Antero Resources to curtail its future development and production plans. Sustained reductions in development or production activity in our areas of operation could lead to reduced demand for our services, which could adversely affect our operating margin and cash flows.
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. Following these proclamations, domestic prices for steel have risen and are expected to continue to rise. 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. 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.
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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.
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 outside 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.
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; |
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| ● | 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 also 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.”
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 acting on our previously announced plan to refinance borrowings under our revolving credit facility with long-term 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 restriction on our ability to dispose of assets and our use of the proceeds from such disposition. 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.
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
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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 $1,291,894 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.
Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Because the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.
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. 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.
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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 recently announced certain efficiency improvements and water initiatives, which are expected to reduce the amount of fresh water needed to complete their operations. Although we recently commenced operations to assist Antero Resources in reusing a portion of its produced water through blending, which we expect will offset a portion of the reduced revenues resulting from these initiatives, we may not be able to effectively commence such water treatment operations on a cost-effective basis. 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.
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.
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 applied to the crude oil and natural gas industry could continue, resulting 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.
Stricter regulation of wastes generated during our or our customers’ operations, or the introduction of hazardous non-exempt waste to the Clearwater Facility, could result in liability under, or costs and expenditures to comply with, environmental laws and regulations governing the handling, storage, treatment and disposal of solid and hazardous wastes, and the permits issued under them.
Our and Antero Resources’ operations generate solid wastes, including small quantities of hazardous wastes, that are subject to RCRA, and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste.
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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. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. In keeping with the consent decree, in April 2019, EPA signed a determination that revision of the regulations is not necessary at this time. However, any changes in laws or regulations regarding the handling of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business.
The Clearwater Facility operates pursuant to West Virginia DEP permits for the management of stormwater and wastewater and the disposal and management of solid waste. The produced water, flowback water, and other waste associated with shale development treated at the Clearwater Facility are exempt from RCRA hazardous waste regulations. Likewise, the input (residual salt derived from the wastewater treated at the Clearwater Facility) and output (leachate derived from precipitation run-off contacting the non-hazardous salt) to and from the Antero Landfill also qualify as exploration and production-exempt non-hazardous wastes because they derive from non-hazardous exempt material. However, in the event that hazardous non-exempt waste streams are introduced to and mix with the exempt waste at the Clearwater Facility, to the extent it recommences operations, or if we otherwise fail to handle or treat such exempt materials pursuant to our West Virginia DEP permits, we may be subject to penalties and/or corrective action measures.
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 response to findings that emissions of carbon dioxide, methane and other 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 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. For example, in December 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities, as well as completions and workovers of hydraulically fractured wells. The revisions also include the addition of well identification reporting requirements for certain facilities. These changes to EPA’s GHG emissions reporting rule could result in increased compliance costs.
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 includes 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 extends existing VOC standards under the EPA’s Subpart OOOO to include previously unregulated equipment within the oil and natural gas source category. There have been several attempts to delay or modify these regulations. Most recently, in August 2019, the EPA proposed amendments to the 2016 standards that, among other things, would remove sources in the transmission and storage segment from the oil and natural gas source category and rescind the methane-specific requirements applicable to sources in the production and processing segments of the industry. As an alternative, the EPA also proposed to rescind the methane-specific requirements that apply to all sources in the oil and natural gas industry, without removing the transmission and storage sources from the current source category. Under either alternative, the EPA plans to retain emissions limits for VOCs. Legal challenges to any final rulemaking that rescinds the 2016 standards are expected. As a result of the foregoing, substantial uncertainty exists with respect to implementation of the EPA’s 2016 methane rule. However, 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.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has been significant activity
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in the form of federal legislation in recent years. Nevertheless, increasing scientific and public concern over the threat of climate change has increased the possibility of political action related to climate change. For example, various pledges have been made by candidates running for the Democratic nomination for President of the United States in 2020. These have included promises to pursue actions that would be adverse to oil and gas production and processing activities, though the extent of any such actions cannot be predicted at this time.
In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions or transitions to alternative forms of energy could also adversely affect demand for the oil and natural gas Antero Resources produces and lower the value of its reserves. Depending on the severity of any such limitations, the effect on the value of Antero Resources reserves could be significant.
On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets (“Paris Agreement”). The Paris Agreement was signed by the United States in April 2016 and entered into force on November 4, 2016; however, the Paris Agreement does not impose any binding obligations on its participants. Moreover, on November 4, 2019, the United States formally initiated the yearlong process to withdraw from the Paris Agreement. However, the United States may subsequently choose to reenter the Paris Agreement or a separately negotiated agreement, though the terms of any such agreement are uncertain at this time.
Separately, increased attention to climate change risks has increased the possibility of claims brought by public and private entities against oil and gas companies in connection with their GHG emissions. While we are not currently party to any such private 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.
Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Increased scrutiny because of climate change related concerns could result in a loss of certain investors. In addition, institutional lenders may, of their own accord, elect not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects. 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.
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 United States Department of Transportation (“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 a HCA; |
| ● | improve data collection, integration and analysis; |
| ● | repair and remediate the pipeline as necessary; and |
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| ● | 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. Additionally, in May 2011, PHMSA published a final rule adding reporting obligations and integrity management standards to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner.
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 reauthorized PHMSA through 2019, and 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 approximately nine remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all HCAs, and requiring pipeline owners or operators to reconfirm their MAOP as expeditiously as economically feasible.
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. 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. These additional rulemakings are expected to be effective by mid-2020. 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.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our business, financial condition and results of operations.
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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.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, 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.
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
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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 September 2015, the EPA and U.S. Army Corps of Engineers, or the Corps, issued a final rule under the federal Clean Water Act, or the CWA, defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the United States (“WOTUS”), but following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule. For example, 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. However, legal challenges to the new rule are expected, and multiple challenges to the EPA’s prior rulemakings remain pending. As a result of these developments, future implementation of the rule 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.
The loss of key personnel could adversely affect our ability to operate.
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 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.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
| ● | our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to our gathering and compression agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms; |
| ● | our funds available for operations and future business opportunities will be reduced by that portion of our cash flows required to make interest payments on our debt; |
| ● | we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
| ● | our flexibility in responding to changing business and economic conditions may be limited. |
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Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing or not paying dividends, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.
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.
We may reduce or cease paying dividends on our common stock.
We are not obligated to pay dividends on shares of our common stock. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of our common stock are only entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our Board out of funds legally available for dividend payments. Our Board makes a determination each quarter as to the actual amount, if any, of dividends to pay on our common stock, based on various factors, some of which are beyond our control, including our operating cash flows, our working capital needs, our ability to access capital markets for debt and equity financing on reasonable terms, the restrictions contained in our debt instruments, our debt service requirements, credit metrics and the cost of acquisitions, if any. We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. Accordingly, we cannot guarantee that we will declare any future dividends at levels consistent with our historic practice or at all.
The price of our common stock may be volatile, and you could lose a significant portion of your investment.
The market price of our common stock could be volatile, and holders of common stock may not be able to resell their common stock at or above the price at which they acquired such securities due to fluctuations in the market price of our common stock.
Specific factors that may have a significant effect on the market price for our common stock include:
| ● | our operating and financial performance and prospects and the trading price of our common stock; |
| ● | the level of our dividends; |
| ● | quarterly variations in the rate of growth of our financial indicators, such as dividends per share of our common stock, net income and revenues; |
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| ● | levels of indebtedness; |
| ● | 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 AMC 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 Partners LLC (“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.
We expect to use a significant portion of our cash flows to pay dividends to our stockholders, which could limit our ability to grow and make acquisitions.
We have previously announced that we plan to return capital in 2020 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.
Antero Resources owns a significant interest in us and, as a result, conflicts of interest will arise from time to time between it and us, and Antero Resources may favor their own interests to the detriment of us and our other stockholders. Additionally, Antero Resources is under no obligation to adopt a business strategy that favors us.
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All of our officers and certain of our directors are also officers or directors of Antero Resources. Also, as of December 31, 2019, Antero Resources beneficially owned 28.7% 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 2034 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.
Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders.
Certain funds affiliated with 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.
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.
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 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 |
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| 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. |
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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 Delaware General Corporation Law (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. 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 have elected not to be subject to the provisions of Section 203 of 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 NYSE, 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.
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.
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.
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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.
Item 1B. Unresolved Staff Comments
Not applicable.
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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. However, we are not currently subject to any material litigation.
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.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
We have one class of common equity outstanding, our common stock, par value $0.01 per share. Our common stock is listed on the New York Stock Exchange and traded under the symbol “AM.” On February 7, 2020, shares of our common stock were held by 62 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 7, 2020, Antero Resources and its subsidiaries owned 139,042,345 shares of our common stock, which represented a 28.7% interest in us.
Issuer Purchases of Equity Securities
The following table sets forth our common stock repurchase activity for each period presented:
Total Number of | Approximate Value | ||||||||||
Number of | Average Price | Shares Purchased | of Shares that May | ||||||||
Shares | Paid per | as Part of Publicly | Yet be Purchased | ||||||||
Period |
| Purchased(1) | Share | Announced Plans(2) | Under the Plan |
| |||||
October 1, 2019 – October 31, 2019 |
| 974 | $ | 7.45 | — | N/A | |||||
November 1, 2019 – November 30, 2019 |
| — | $ | — | — | N/A | |||||
December 1, 2019 – December 31, 2019 |
| 19,377,592 | $ | 5.16 | 19,377,592 | $ | 175,000,000 | ||||
Total | 19,378,566 | $ | 5.16 | 19,377,592 | $ | 175,000,000 | |||||
| (1) | The total number of shares purchased includes 974 shares repurchased in October 2019, representing 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. There were no such repurchases in November and December. |
| (2) | In August 2019, the Board authorized a $300 million share repurchase program. On December 16, 2019, we repurchased 19,377,592 shares of our common stock from Antero Resources at a price of $5.1606 per share, which shares were thereafter cancelled. |
Dividends
On January 15, 2020, 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, 2019. The dividend will be payable on February 12, 2020 to stockholders of record as of January 31, 2020.
The Board also declared a cash dividend of $138 thousand on shares of our Series A Preferred Stock to be paid on February 14, 2020 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, 2019, there were dividends in the amount of $69 thousand accumulated in arrears on our Series A Preferred Stock.
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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.
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 year ended December 31, 2019 or to our future financial results. The selected financial data for the years ended December 31, 2015, 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
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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, 2017, 2018, and 2019 and the balance sheet data as of December 31, 2018 and 2019 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, 2015 and 2016 and the selected balance sheet data as of December 31, 2015, 2016 and 2017 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:
December 31, | ||||||||||||||||
(in thousands, except per share amounts) |
| 2015 |
| 2016 |
| 2017 |
| 2018 |
| 2019 |
| |||||
Revenue: | ||||||||||||||||
Gathering and compression–Antero Resources | $ | — | — | — | — | 543,538 | ||||||||||
Water handling–Antero Resources | — | — | — | — | 306,010 | |||||||||||
Water handling–third party | — | — | — | — | 50 | |||||||||||
Amortization of customer relationships | — | — | — | — | (57,010) | |||||||||||
Total revenue | — | — | — | — | 792,588 | |||||||||||
Operating expenses: | ||||||||||||||||
Direct operating | — | — | — | — | 195,818 | |||||||||||
General and administrative (excluding equity-based compensation) | — | 814 | 6,201 | 8,740 | 44,596 | |||||||||||
Equity-based compensation | — | — | 34,933 | 35,111 | 73,517 | |||||||||||
Facility idling | — | — | — | — | 11,401 | |||||||||||
Impairment of property and equipment | — | — | — | — | 409,739 | |||||||||||
Impairment of goodwill | — | — | — | — | 340,350 | |||||||||||
Impairment of customer relationships | — | — | — | — | 11,871 | |||||||||||
Depreciation | — | — | — | — | 95,526 | |||||||||||
Accretion and change in fair value of contingent acquisition consideration | — | — | — | — | 8,076 | |||||||||||
Accretion of asset retirement obligations | — | — | — | — | 187 | |||||||||||
Total operating expenses | — | 814 | 41,134 | 43,851 | 1,191,081 | |||||||||||
Operating loss | — | (814) | (41,134) | (43,851) | (398,493) | |||||||||||
Interest expense, net | — | — | — | (136) | (110,402) | |||||||||||
Equity in earnings of unconsolidated affiliates | 1,264 | 16,944 | 69,720 | 142,906 | 51,315 | |||||||||||
Income (loss) before income taxes | 1,264 | 16,130 | 28,586 | 98,919 | (457,580) | |||||||||||
Provision for income tax benefit (expense) | (483) | (6,419) | (26,261) | (32,311) | 102,466 | |||||||||||
Net income (loss) and comprehensive income (loss) | $ | 781 | 9,711 | 2,325 | 66,608 | (355,114) | ||||||||||
Net income (loss) per share–basic and diluted | $ | 0.03 | 0.33 | (0.80) | ||||||||||||
Weighted average common shares outstanding: | ||||||||||||||||
Basic | 186,176 | 186,203 | 442,640 | |||||||||||||
Diluted | 186,176 | 186,203 | 442,640 | |||||||||||||
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December 31, | ||||||||||||||||
(in thousands, except per share amounts) |
| 2015 |
| 2016 |
| 2017 |
| 2018 |
| 2019 |
| |||||
Balance sheet data (at period end): | ||||||||||||||||
Cash and cash equivalents | $ | 72 | 9,609 | 5,987 | 2,822 | 1,235 | ||||||||||
Other current assets | — | 217 | — | 87 | 107,323 | |||||||||||
Total current assets | 72 | 9,826 | 5,987 | 2,909 | 108,558 | |||||||||||
Property and equipment, net | — | — | — | — | 3,273,410 | |||||||||||
Investments in unconsolidated affiliates | 969 | 7,543 | 23,772 | 43,492 | 709,639 | |||||||||||
Other assets | — | — | — | 1,304 | 2,191,271 | |||||||||||
Total assets | $ | 1,041 | 17,369 | 29,759 | 47,705 | 6,282,878 | ||||||||||
Current liabilities | 115 | 7,100 | 14,151 | 16,844 | 242,084 | |||||||||||
Long-term indebtedness | — | — | — | — | 2,892,249 | |||||||||||
Other long-term liabilities | 368 | — | — | — | 5,131 | |||||||||||
Total partners' capital and stockholders' equity | 558 | 10,269 | 15,608 | 30,861 | 3,143,414 | |||||||||||
Total liabilities and partners' capital and stockholders' equity | $ | 1,041 | 17,369 | 29,759 | 47,705 | 6,282,878 | ||||||||||
Cash flows data: | ||||||||||||||||
Net cash provided by operating activities | $ | 295 | 9,537 | 28,080 | 83,531 | 622,387 | ||||||||||
Net cash used in investing activities | $ | — | — | — | — | (525,675) | ||||||||||
Net cash activities provided by (used in) financing activities | $ | (223) | — | (31,702) | (86,696) | (98,299) | ||||||||||
Other financial data: | ||||||||||||||||
Distributions or dividends declared per share | $ | 0.16 | 0.54 | 1.23 | ||||||||||||
Pro forma Net income (loss) | $ | 312,894 | (285,076) | |||||||||||||
Pro forma Adjusted EBITDA(1) | $ | 708,635 | 829,558 | |||||||||||||
(1) | For a discussion of the non-GAAP financial measure Pro Forma Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure” below. |
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The following table presents our pro forma results of operations for the years ended December 31, 2018 and 2019, which give effect to the adjustments described in Exhibit 99.1 to this Annual Report on Form 10-K. The pro forma information presented below should be read in conjunction with the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.1 to this Annual Report on Form 10-K and describe the assumptions and adjustments used in preparing such information.
Year Ended December 31, | |||||||
2018 | 2019 | ||||||
Revenues: | |||||||
Revenue–Antero Resources | $ | 1,027,015 | 1,067,858 | ||||
Revenue–third-party | 924 | 101 | |||||
Gain on sales of assets–Antero Resources | 583 | — | |||||
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 | |||||
Facility idling | — | 11,401 | |||||
Equity-based compensation | 56,184 | 75,994 | |||||
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 | 135 | 250 | |||||
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 Measure
We use Pro Forma Adjusted EBITDA as an important indicator of our performance. We define Pro Forma Adjusted EBITDA as net income (loss) before net interest expense, income tax expense (benefit), 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 and including cash distributions from unconsolidated affiliates and including Antero Midstream Partners’ pre-acquisition: net income before interest expense, depreciation, impairment, accretion and changes in fair value of contingent acquisition consideration, accretion of asset retirement obligations, equity-based compensation, amortization of customer relationships excluding equity in earnings of unconsolidated affiliates, including cash distributions from unconsolidated affiliates and excluding equity in earnings of Antero Midstream Partners.
We use Pro Forma 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.
Pro Forma Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Pro Forma Adjusted EBITDA is Pro Forma Net income (loss). The non-GAAP financial measure of Pro Forma Adjusted EBITDA should
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not be considered as an alternative to the GAAP measure of net income. Pro Forma 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 Pro Forma Net income (loss). You should not consider Pro Forma Adjusted EBITDA in isolation or as a substitute for analyses of results as reported under GAAP. Our definition of Pro Forma Adjusted EBITDA may not be comparable to similarly titled measures of other corporations.
The following table represents a reconciliation of our Pro Forma Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods presented:
Year Ended December 31, |
| ||||||
(in thousands) |
| 2018 |
| 2019 |
| ||
Reconciliation of Pro Forma Net Income (Loss) to Pro Forma Adjusted EBITDA: |
| ||||||
Pro Forma Net income (loss) | $ | 312,894 | (285,076) | ||||
Interest expense | 83,794 | 130,518 | |||||
Income tax expense (benefit) | 114,406 | (79,120) | |||||
Amortization of customer relationships | 71,082 | 70,874 | |||||
Depreciation expense | 145,745 | 120,363 | |||||
Impairment | 5,771 | 768,942 | |||||
Accretion and change in fair value of contingent acquisition consideration | (92,884) | 10,254 | |||||
Equity-based compensation | 56,184 | 75,994 | |||||
Equity in earnings of unconsolidated affiliates | (34,189) | (62,394) | |||||
Distributions from unconsolidated affiliates | 46,415 | 76,925 | |||||
Contract restructuring fees | — | 2,278 | |||||
Gain on sale of assets—Antero Resources | (583) | — | |||||
Pro Forma Adjusted EBITDA | $ | 708,635 | 829,558 | ||||
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. The information provided below supplements, but does not form part of, our consolidated financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, 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 AMGP, Antero Midstream Partners and certain of their affiliates, (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, and (iii) Antero Midstream Corporation exchanged each issued and outstanding Series B Units representing a membership interest in IDR Holdings for 176.0041 shares of its common stock, par value $0.01 per share.
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 sheet of Antero Midstream Corporation at December 31, 2019 includes 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, 2019 include the results of operations of Antero Midstream Partners and its subsidiaries commencing on March 13, 2019.
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 Marcellus and Utica shale plays. 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 Marcellus and Utica Shales in West Virginia and Ohio. Our assets also include two independent fresh water delivery systems that deliver fresh water from the Ohio River and several regional waterways. These fresh water delivery systems consist of permanent buried pipelines, surface pipelines and fresh water storage facilitates, 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.
Recent Trends and Uncertainties
The gathering and compression agreement with Antero Resources is based on 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 plan and, therefore, our gathering and water handling volumes.
During 2020, we plan to expand our existing Marcellus and Utica Shale gathering, compression, and water handling infrastructure to accommodate Antero Resources’ announced development plans. Antero Resources’ announced 2020 consolidated drilling and completion capital budget is $1.15 billion. Antero Resources announced that it plans to operate an average of four drilling rigs and complete between 120 to 130 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.
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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. In December 2019, we and Antero Resources agreed to a growth incentive fee program whereby we will provide quarterly fee reductions to Antero Resources from 2020 through 2023, contingent upon Antero Resources achieving volumetric growth targets on low pressure gathering. In addition, we and Antero Resources agreed to extend the initial term of the gathering and compression contract to 2038. We have also entered into a long-term water services agreement covering Antero Resources’ 541,000 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 140,000 gross leasehold acres characterized by dry gas and liquids-rich production that 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, 2019, Antero Resources had disclosed estimated net proved reserves of 18.9 Tcfe, of which 61% was natural gas, 38% were NGLs, and 1% was oil. As of December 31, 2019, Antero Resources’ drilling inventory consisted of 2,385 identified potential horizontal well locations, approximately 1,685 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.
Pro Forma Adjusted EBITDA
We use Pro Forma 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. Pro Forma Adjusted EBITDA is a non-GAAP financial measure. See “Item 6. Selected Financial Data—Non-GAAP Financial Measure” for more information regarding this financial measure, including a reconciliation of Pro Forma Adjusted EBITDA to the most directly comparable GAAP measure.
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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, to a lesser extent in the future, 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 Marcellus and Utica Shale 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 Marcellus and Utica Shales 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 and vary depending on the cost of service provided to Antero Resources. These costs are billed to Antero Resources at our cost plus 3%. 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. 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 “AMC LTIP”) and (iii) each Series B Unit that was exchanged for 176.0041 shares of our common stock, a certain portion of which remained subject to vesting until December 31, 2019 (the “Series B Exchange”). As of December 31, 2019, there were no unvested awards related to these plans.
| ● | 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 |
49
| 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. |
| ● | 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. We depreciate our property and equipment using an estimated useful life of five years for our fresh water surface pipelines and equipment, 10 years for our above ground storage tanks, 20 years for our permanent buried fresh water pipelines and equipment, 50 years for our gathering pipelines and compressor stations and our landfill on a units of production basis. |
| ● | Interest. In 2018 and 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 Transaction 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 $650 million of our 5.75% senior notes due March 1, 2027 (the “2027 Notes”), (iv) borrowings of $650 million of our 5.75% senior notes due January 15, 2028 (the “2028 Notes”), (v) operating leases, and (vi) amortization of deferred financing costs incurred in connection with the revolving credit facility and the issuance of the 2024 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 and net operating loss carryforwards. At December 31, 2019, we had approximately $277 million of U.S. federal net operating loss carryforwards (“NOLs”), and approximately $202 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. As such, the consolidated financial statements for the year ended December 31, 2018 and as of December 31, 2018 are the consolidated financial statements of AMGP and its consolidated subsidiaries, which does not include Antero Midstream Partners and its subsidiaries. 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 at 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.
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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, 2018 Compared to Year Ended December 31, 2019
Revenue and Direct Operating Expenses. Revenues from Antero Resources and direct operating expenses 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) increased from $9 million for the year ended December 31, 2018 to $45 million for the year ended December 31, 2019. The increase was primarily due to the inclusion of general and administrative expenses of Antero Midstream Partners after the completion of the Transactions on March 12, 2019. Equity-based compensation increased from $35 million for the year ended December 31, 2018 to $74 million for the year ended December 31, 2019 due to the Series B Exchange and the adoption of the AMC LTIP as result of the Transactions.
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 in September 2019.
Impairment of goodwill expense. Impairment of goodwill expense of $340 million for the year ended December 31, 2019, which reflects (i) an impairment of goodwill expense associated with the Clearwater Facility of $42 million and (ii) an impairment of goodwill expense associated our fresh water delivery and services reporting unit of $298 million.
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, which was idled in September 2019.
Depreciation expense. Depreciation expense increased from none for the year ended December 31, 2018 to $96 million for the year ended December 31, 2019 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 expenses increased from none for the year ended December 31, 2018 to $8 million for the year ended December 31, 2019 as a result of our acquisition of Antero Midstream Partners on March 12, 2019.
Interest expense. Interest expense increased from $136 thousand for the year ended December 31, 2018 to $110 million for the year ended December 31, 2019 as a result of the acquisition of Antero Midstream Partners, which included the assumption of approximately $2.4 billion of debt.
Operating loss. Total operating loss increased from a loss of $44 million for the year ended December 31, 2018 to $398 million for the year ended December 31, 2019. The increase was due to net operating revenues and expenses as a result of the acquisition of Antero Midstream Partners on March 12, 2019 and impairments to property and equipment, goodwill and customer relationships of approximately $410 million, $340 million and $12 million, respectively. Prior to the acquisition of Antero Midstream Partners, we had no operating revenues. All income was derived from our equity in earnings of unconsolidated affiliates.
Equity in earnings of unconsolidated affiliates. Equity in earnings of unconsolidated affiliates for the year ended December 31, 2018 represents AMGP’s equity investment in Antero Midstream Partners. Equity in earnings of unconsolidated affiliates for the
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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.
Income tax benefit (expense). Income tax benefit (expense) changed from an income tax expense of $32 million for the year ended December 31, 2018 to a benefit of $102 million for the year ended December 31, 2019 primarily due to the loss before taxes for the year ended December 31, 2019.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2018
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” in our 2018 Annual Report on Form 10-K for a discussion of the results of operations for the year ended December 31, 2017 compared to the year ended December 31, 2018.
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, 2018.
The pro forma segment results of operations and the pro forma operations data for the years ended December 31, 2018 and 2019 have been prepared to give pro forma effect to the Transactions as if they had occurred on January 1, 2018. 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, 2018, 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, 2018. 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.
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Pro Forma Segment Results of Operations for the year ended December 31, 2018 and 2019
Pro Forma | ||||||||||||||||
| Gathering and |
| Water |
| Pro Forma |
|
| Consolidated | ||||||||
| Processing |
| Handling |
| Adjustments |
| Unallocated (1) |
| Total | |||||||
Year ended December 31, 2018 |
| |||||||||||||||
Revenues: | ||||||||||||||||
Revenue–Antero Resources | $ | 520,566 | 506,449 | — | — | 1,027,015 | ||||||||||
Revenue–third-party | — | 924 | — | — | 924 | |||||||||||
Gain on sales of assets–Antero Resources | 583 | — | — | — | 583 | |||||||||||
Amortization of customer contracts | — | — | (71,082) | — | (71,082) | |||||||||||
Total revenues | 521,149 | 507,373 | (71,082) | — | 957,440 | |||||||||||
Operating expenses: | ||||||||||||||||
Direct operating | 49,256 | 267,167 | — | — | 316,423 | |||||||||||
General and administrative (excluding equity-based compensation) | 30,091 | 10,465 | — | 8,740 | 49,296 | |||||||||||
Equity-based compensation | 16,518 | 4,555 | — | 35,111 | 56,184 | |||||||||||
Impairment of property and equipment | 5,771 | — | — | — | 5,771 | |||||||||||
Depreciation | 83,250 | 46,763 | 15,732 | — | 145,745 | |||||||||||
Accretion and change in fair value of contingent acquisition consideration | — | (93,019) | — | — | (93,019) | |||||||||||
Accretion of asset retirement obligations | — | 135 | — | — | 135 | |||||||||||
Total expenses | 184,886 | 236,066 | 15,732 | 43,851 | 480,535 | |||||||||||
Operating income | 336,263 | 271,307 | (86,814) | (43,851) | 476,905 | |||||||||||
Other income (expenses): | ||||||||||||||||
Interest expense, net | — | — | (21,752) | (62,042) | (83,794) | |||||||||||
Equity in earnings of unconsolidated affiliates | 40,280 | — | (6,091) | — | 34,189 | |||||||||||
Income before taxes | 376,543 | 271,307 | (114,657) | (105,893) | 427,300 | |||||||||||
Provision for income tax expense | — | — | (82,095) | (32,311) | (114,406) | |||||||||||
Net income and comprehensive income | $ | 376,543 | 271,307 | (196,752) | (138,204) | 312,894 | ||||||||||
Pro Forma Adjusted EBITDA(2) | $ | 708,635 | ||||||||||||||
| (1) | Corporate expenses that are not directly attributable to either the gathering and processing or water handling segments. |
| (2) | For a reconciliation of Pro Forma Adjusted EBITDA to the most directly comparable financial measure calculated and presented in accordance with GAAP, see “Item 6. Selected Financial Data—Non-GAAP Financial Measure.” |
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Pro Forma | ||||||||||||||||
| Gathering and |
| Water |
| Pro Forma |
|
| Consolidated | ||||||||
| 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 | — | 101 | — | — | 101 | |||||||||||
Amortization of customer relationships | (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 | |||||||||||
Facility idling | — | 11,401 | — | — | 11,401 | |||||||||||
Equity-based compensation | 7,105 | 3,063 | — | 65,826 | 75,994 | |||||||||||
Impairment of property and equipment | 7,182 | 409,539 | — | — | 416,721 | |||||||||||
Impairment of goodwill | — | 340,350 | — | — | 340,350 | |||||||||||
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 | — | 250 | — | — | 250 | |||||||||||
Total 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 | — | — | (23,346) | 102,466 | 79,120 | |||||||||||
Net income (loss) and comprehensive income (loss) | $ | 556,507 | (708,487) | (29,481) | (103,615) | (285,076) | ||||||||||
Pro Forma Adjusted EBITDA(2) | $ | 829,558 | ||||||||||||||
| (1) | Corporate expenses that are not directly attributable to either the gathering and processing or water handling segments. |
| (2) | For a reconciliation of Pro Forma Adjusted EBITDA to the most directly comparable financial measure calculated and presented in accordance with GAAP, see “Item 6. Selected Financial Data—Non-GAAP Financial Measure.” |
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The operating data below represents (i) the operating data of Antero Midstream Partners and its subsidiaries for the year ended December 31, 2018 and (ii) the operating data of Antero Midstream Corporation and its subsidiaries, including Antero Midstream Partners and its subsidiaries, for the year ended December 31, 2019.
Amount of | |||||||||||||
Year Ended December 31, | Increase | Percentage | |||||||||||
2018 |
| 2019 | or Decrease | Change | |||||||||
Pro Forma Operating Data: | |||||||||||||
Gathering—low pressure (MMcf) | 784,079 | 963,799 | 179,720 | 23 | % | ||||||||
Gathering—high pressure (MMcf) | 770,910 | 948,496 | 177,586 | 23 | % | ||||||||
Compression (MMcf) | 634,303 | 866,912 | 232,609 | 37 | % | ||||||||
Fresh water delivery (MBbl) | 71,180 | 51,426 | (19,754) | (28) | % | ||||||||
Treated water (MBbl) | 2,544 | 7,137 | 4,593 | 181 | % | ||||||||
Other fluid handling (MBbl) | 18,848 | 19,495 | 647 | 3 | % | ||||||||
Wells serviced by fresh water delivery | 162 | 118 | (44) | (27) | % | ||||||||
Gathering—low pressure (MMcf/d) | 2,148 | 2,641 | 493 | 23 | % | ||||||||
Gathering—high pressure (MMcf/d) | 2,112 | 2,599 | 487 | 23 | % | ||||||||
Compression (MMcf/d) | 1,738 | 2,375 | 637 | 37 | % | ||||||||
Fresh water delivery (MBbl/d) | 195 | 141 | (54) | (28) | % | ||||||||
Treated water (MBbl/d) | 7 | 20 | 13 | 186 | % | ||||||||
Other fluid handling (MBbl/d) | 52 | 53 | 1 | 2 | % | ||||||||
Pro Forma Average realized fees: | |||||||||||||
Average gathering—low pressure fee ($/Mcf) | $ | 0.32 | 0.33 | 0.01 | 3 | % | |||||||
Average gathering—high pressure fee ($/Mcf) | $ | 0.19 | 0.20 | 0.01 | 5 | % | |||||||
Average compression fee ($/Mcf) | $ | 0.19 | 0.19 | — | — | % | |||||||
Average fresh water delivery fee ($/Bbl) | $ | 3.78 | 3.89 | 0.11 | 3 | % | |||||||
Average treatment fee ($/Bbl) | $ | 4.72 | 4.51 | (0.21) | (4) | % | |||||||
Pro Forma Joint Venture Operating Data: | |||||||||||||
Processing—Joint Venture (MMcf) | 227,113 | 385,402 | 158,289 | 70 | % | ||||||||
Fractionation—Joint Venture (MBbl) | 4,784 | 10,285 | 5,501 | 115 | % | ||||||||
Processing—Joint Venture (MMcf/d) | 622 | 1,056 | 434 | 70 | % | ||||||||
Fractionation—Joint Venture (MBbl/d) | 13 | 28 | 15 | 115 | % | ||||||||
Discussion of Pro Forma Results of Operations for the Year Ended December 31, 2018 Compared to Year ended December 31, 2019
Revenues. Total revenues, including the amortization of customer relationships of $71 million, increased by 4% from $957 million for the year ended December 31, 2018 to $997 million for the year ended December 31, 2019. Gathering and processing revenues increased by 23%, from $521 million for the year ended December 31, 2018 to $639 million for the year ended December 31, 2019. Water handling revenues decreased by 27%, from $507 million for the year ended December 31, 2018 to $372 million for the year ended December 31, 2019. These fluctuations primarily resulted from the following:
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Gathering and Processing
| ● | low pressure gathering revenue increased $62 million period over period due to an increase in throughput volumes of 493 MMcf/d, which was due to 128 additional wells connected to our system since December 31, 2018; |
| ● | high pressure gathering revenue increased $38 million period over period due to an increase in throughput volumes of 487 MMcf/d, primarily as a result of the addition of two new high pressure gathering lines placed in service and additional wells connected to our system since December 31, 2018; and |
| ● | compression revenue increased $48 million period over period due to an increase in throughput volumes of 637 MMcf/d, primarily due to the addition of one new compressor station that was placed in service since December 31, 2018, and additional wells connected to our system. |
Water Handling
| ● | fresh water delivery revenue decreased $70 million period over period due to a decrease in fresh water delivery of 54 MBbl/d, as a result of a decrease in the number of wells completed as Antero Resources reduced its drilling and completion program; |
| ● | revenue from the Clearwater Facility increased $20 million as throughput volumes increased by 13 MBbl/d; and |
| ● | other fluid handling services revenue decreased $58 million as costs for these services, which are billed at cost plus 3%, decreased as a result of operational efficiencies and cost reductions. |
Direct operating expenses. Total direct operating expenses decreased from $316 million for the year ended December 31, 2018 to $261 million for the year ended December 31, 2019. Gathering and processing direct operating expenses increased from $49 million for the year ended December 31, 2018 to $53 million for the year ended December 31, 2019. The increase was primarily due to an increase in the number of gathering pipelines and compressor stations. Water handling direct operating expenses decreased from $267 million for the year ended December 31, 2018 to $208 million for the year ended December 31, 2019. The decrease was primarily due to a decrease in other fluid handling services as a result of operational efficiencies and cost reductions.
General and administrative (excluding equity-based compensation) expenses. General and administrative expenses (excluding equity-based compensation expense) decreased from $49 million for the year ended December 31, 2018 to $46 million for the year ended December 31, 2019 primarily due to a decrease of general and administrative expenses as a result of cost reduction efforts.
Equity-based compensation expenses. Equity-based compensation expenses increased from $56 million for the year ended December 31, 2018 to $76 million for the year ended December 31, 2019 primarily due to the revaluation of the Series B Units as result of the Transactions.
Impairment of property and equipment expense. Impairment of property and equipment expense of $6 million for the year ended December 31, 2018 was due to the impairment of gathering assets acquired from Antero Resources at the time of Antero Midstream Partners’ initial public offering related to well pads Antero Resources no longer planned to drill and complete. 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 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 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 17%, from $146 million for the year ended December 31, 2018 to $120 million for the year ended December 31, 2019. The decrease was primarily due to the change in estimated useful lives of gathering and compression facilities in the fourth quarter of 2018, partially offset by additional assets placed into service.
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Accretion and change in fair value of contingent acquisition consideration. Accretion of contingent acquisition consideration changed from a reduction of $93 million for the year ended December 31, 2018 to an increase of $10 million for the year ended December 31, 2019. This was primarily due to a decrease in fair value of $106 million for the year ended 2018. In connection with our entrance into the water services agreement, we agreed to pay Antero Resources $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. As of December 31, 2019, we had delivered 178 million barrels during the period the period between January 1, 2017 and December 31, 2019 and paid Antero Resources $125 million in January 2020. We have agreed to pay 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. As of December 31, 2019, we had delivered 123 million of the 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020 and we currently do not expect to deliver at least 219 million barrels based on Antero Resources’ announced 2020 budget.
Interest expense. Interest expense increased by 56%, from $84 million, net of $4 million in capitalized interest, for the year ended December 31, 2018 to $131 million for the year ended December 31, 2019. No interest was capitalized for the year ended December 31, 2019. Total interest costs increased from $88 million for the year ended December 31, 2018 to $131 million for the year ended December 31, 2019 primarily due to (i) an increase in interest expense incurred on increased borrowings under the Credit Facility during the period, (ii) increased interest rates, (iii) the issuance of $650 million of the 2027 Notes on February 25, 2019, and (iv) the issuance of $650 million of the 2028 Notes on June 28, 2019.
Operating income (loss). Total operating income was $477 million for the year ended December 31, 2018. Total operating loss was $296 million for the year ended December 31, 2019. Gathering and processing operating income increased by 47%, from $336 million for the year ended December 31, 2018 to $493 million for the year ended December 31, 2019. The increase was primarily due to an increase in gathering and compression throughput volumes and lower depreciation on the gathering system in 2019. Water handling operating income was $271 million for the year ended December 31, 2018. Water handling operating loss was $708 million for the year ended December 31, 2019. The operating loss was primarily due to the impairment of the Clearwater Facility and its associated goodwill and customer relationships and the impairment of the goodwill associated with the fresh water delivery and services reporting unit.
Equity in earnings of unconsolidated affiliates. Equity in earnings in unconsolidated affiliates increased by 82%, from $34 million for the year ended December 31, 2018 to $62 million for the year ended December 31, 2019. 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 in 2019.
Net income (loss). Net income was $313 million for the year ended December 31, 2018. Net loss was $285 million for the year ended December 31, 2019. The net loss was primarily due to the impairment of the Clearwater Facility and its associated goodwill and customer relationships and the impairment of the goodwill associated with the fresh water delivery and services reporting unit.
Pro Forma Adjusted EBITDA. Pro Forma Adjusted EBITDA increased by 17%, from $709 million for the year ended December 31, 2018 to $830 million for the year ended December 31, 2019. The increase was primarily due to an increase in revenue resulting from an increase in gathering and compression volumes. 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 Measure.”
Capital Resources and Liquidity as Reported
Sources and Uses of Cash
Capital resources and liquidity are provided by operating cash flow, 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, 2019, we paid distributions and dividends of $1.0815 per share, or a total of $492 million, to holders of our common shares or common stock, as applicable, and we paid $374 thousand of dividends on our Series A Preferred Stock. On January 15, 2020, the Board declared a cash dividend on the shares of our common stock of $0.3075 per share for the quarter ended December 31, 2019 to be paid on February 12, 2020 to stockholders of record as of January 31, 2020. The Board also
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declared an aggregate cash dividend of $138 thousand on our Series A Preferred Stock to be paid on February 14, 2020. As of December 31, 2019, 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, | ||||||||||
(in thousands) |
| 2017 |
| 2018 |
| 2019 | ||||
Net cash provided by operating activities | $ | 28,080 | 83,531 | 622,387 | ||||||
Net cash used in investing activities | — | — | (525,675) | |||||||
Net cash used in financing activities | (31,702) | (86,696) | (98,299) | |||||||
Net decrease in cash and cash equivalents | $ | (3,622) | (3,165) | (1,587) | ||||||
Year Ended December 31, 2018 Compared to Year Ended December 31, 2019
Cash Flows Provided by Operating Activities
Net cash provided by operating activities was $84 million and $622 million for the years ended December 31, 2018 and 2019, respectively. The increase in cash flows from operations for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily the result of increased cash flows associated with Antero Midstream Partners for the period March 13, 2019 through December 31, 2019 following the Transactions.
Cash Flows Used in Investing Activities
During the year ended December 31, 2019, we used cash flows in investing activities of $526 million while we had no cash flows from investing activities during the year ended December 31, 2018. The increase was due to $599 million of cash paid to Antero Midstream Partners unitholders as consideration in the Merger, $154 million in investments in unconsolidated affiliates and $392 million in capital expenditures for gathering systems and facilities and water handling assets partially offset by cash received of $620 million, which was borrowed by Antero Midstream Partners on the Credit Facility primarily to pay the aforementioned $599 million of consideration in the Merger.
Our board of directors approved a capital budget with a range of $300 million to $325 million for 2020. 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.
Cash Flows Provided by Financing Activities
Net cash used in financing activities was $87 million and $98 million for the years ended December 31, 2018 and 2019, respectively. 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. For the year ended December 31, 2018, net cash used in financing activities consisted of $86 million in distributions to shareholders and holders of Series B Units.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2018
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, 2018 for a discussion of the cash flows for the year ended December 31, 2017 compared to the year ended December 31, 2018.
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Debt Agreements
Antero Midstream Partners Revolving 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 described below. Our Credit Facility provides for borrowing under either the Eurodollar Rate or the Base Rate (as each term is defined in the credit facility agreement).
The Credit Facility was amended on October 31, 2018 and February 26, 2019 to, among other things: (i) increase lender commitments from $1.5 billion to $2.0 billion, which were further increased to $2.13 billion on November 19, 2019, (ii) permit us, the Borrower and the guarantors under the facility to consummate the Transactions and (iii) to modify pricing to the levels described in more detail below. The Credit Facility matures on October 26, 2022. At December 31, 2019, we had $960 million of borrowings and no letters of credit outstanding under the Credit Facility.
Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred and the Borrower is in pro forma compliance with the financial covenants under the Credit Facility, commences when the Borrower elects to give notice to the Administrative Agent that the Borrower has received at least one of either (i) a BBB- or better rating from Standard and Poor’s or (ii) a Baa3 or better from Moody’s (provided that the non-investment grade rating from the other rating agency is at least either Ba1 if Moody’s or BB+ if Standard and Poor’s (an “Investment Grade Rating”)). An Investment Grade Period can end at the Borrower’s election.
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 (i) 125 to 225 basis points during any period that is not an Investment Grade Period, depending on the leverage ratio then in effect and (ii) 112.5 to 200 basis points during an Investment Grade Period, depending on the Borrower’s credit rating 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 (i) 25 to 125 basis points during any period that is not an Investment Grade Period, depending on the leverage ratio then in effect and (ii) 12.5 to 100 basis points during an Investment Grade Period, depending on the Borrower’s credit rating then in effect.
During any period that is not an Investment Grade Period, the Credit Facility is guaranteed by our subsidiaries and is secured by mortgages on substantially all of Antero Midstream Partners’ and its subsidiaries’ properties; provided that the liens securing the Credit Facility shall be automatically released during an Investment Grade Period. 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. |
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The Credit Facility also requires us to maintain the following financial ratios:
| ● | 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; provided that during an Investment Grade Period, the Borrower will not to be subject to such ratio; |
| ● | 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 during an Investment Grade Period or 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 (and up to the commencement of an Investment Grade Period), 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, 2019. The actual borrowing capacity available to Antero Midstream Partners may be limited by the interest coverage ratio, consolidated total leverage ratio, and consolidated senior secured leverage ratio covenants.
5.375% Senior Notes Due 2024
On September 13, 2016, Antero Midstream Partners and its wholly owned subsidiary, Finance Corp (together with Antero Midstream Partners, the “Issuers”), issued $650 million in aggregate principal amount of 5.375% senior notes due September 15, 2024 (the “2024 Notes”) at par. The 2024 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2024 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners’ wholly owned subsidiaries (other than Finance Corp) and certain of its future restricted subsidiaries. Interest on the 2024 Notes is payable on March 15 and September 15 of each year. Antero Midstream Partners may redeem all or part of the 2024 Notes at any time at redemption prices ranging from 104.031% as of December 31, 2019 to 100.00% on or after September 15, 2022. If Antero Midstream Partners undergoes a change of control followed by a rating decline, the holders of the 2024 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the 2024 Notes at a price equal to 101% of the principal amount of the 2024 Notes, plus accrued and unpaid interest.
5.75% Senior Notes Due 2027
On February 25, 2019, the Issuers issued the 2027 Notes at par. The 2027 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2027 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners’ wholly owned subsidiaries (other than Finance Corp) and certain of its future restricted subsidiaries. Interest on the 2027 Notes is payable on March 1 and September 1 of each year. Antero Midstream Partners may redeem all or part of the 2027 Notes at any time on or after March 1, 2022 at redemption prices ranging from 102.875% on or after March 1, 2022 to 100.00% on or after March 1, 2025. In addition, prior to March 1, 2022, Antero Midstream Partners may redeem up to 35% of the aggregate principal amount of the 2027 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.75% of the principal amount of the 2027 Notes, plus accrued and unpaid interest. At any time prior to March 1, 2022, Antero Midstream Partners may also redeem the 2027 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2027 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream Partners undergoes a change of control followed by a rating decline, the holders of the 2027 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the 2027 Notes at a price equal to 101% of the principal amount of the 2027 Notes, plus accrued and unpaid interest.
5.75% Senior Notes Due 2028
On June 28, 2019, the Issuers issued the 2028 Notes at par. The 2028 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2028 Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by Antero Midstream Corporation, Antero Midstream Partners’ wholly owned subsidiaries (other than Finance Corp) and certain of its future restricted subsidiaries. Interest on the 2028 Notes is payable on January 15 and July 15 of each year. Antero Midstream Partners may redeem all or part of the 2028 Notes at any time on or after January 15, 2023 at redemption prices ranging from 102.875% on or after January 15, 2023 to 100.00% on or after January 15, 2026. In addition, prior to January 15, 2023, Antero Midstream Partners may redeem up to 35% of the aggregate principal
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amount of the 2028 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.75% of the principal amount of the 2028 Notes, plus accrued and unpaid interest. At any time prior to January 15, 2023, Antero Midstream Partners may also redeem the 2028 Notes, in whole or in part, at a price equal to 100% of the principal amount of the 2028 Notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream Partners undergoes a change of control followed by a rating decline, the holders of the 2028 Notes will have the right to require Antero Midstream Partners to repurchase all or a portion of the 2028 Notes at a price equal to 101% of the principal amount of the 2028 Notes, plus accrued and unpaid interest.
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, 2019 is provided in the following table.
Year Ended December 31, | ||||||||||||||||||||||
(in millions) |
| 2020 |
| 2021 |
| 2022 |
| 2023 |
| 2024 |
| Thereafter | Total | |||||||||
Credit Facility (1) | $ | — | — | 960 | — | — | — | 960 | ||||||||||||||
5.375% senior notes due 2024—principal | — | — | — | — | 650 | — | 650 | |||||||||||||||
5.375% senior notes due 2024—interest | 35 | 35 | 35 | 35 | 35 | — | 175 | |||||||||||||||
5.75% senior notes due 2027—principal | — | — | — | — | — | 650 | 650 | |||||||||||||||
5.75% senior notes due 2027—interest | 37 | 37 | 37 | 37 | 37 | 93 | 278 | |||||||||||||||
5.75% senior notes due 2028—principal | — | — | — | — | — | 650 | 650 | |||||||||||||||
5.75% senior notes due 2028—interest | 39 | 37 | 37 | 37 | 37 | 131 | 318 | |||||||||||||||
Contingent acquisition consideration | 125 | — | — | — | — | — | 125 | |||||||||||||||
Asset retirement obligations | 3 | — | — | 1 | — | 2 | 6 | |||||||||||||||
Total |
| $ | 239 |
| 109 |
| 1,069 |
| 110 |
| 759 |
| 1,526 |
| 3,812 | |||||||
(1) | Includes outstanding principal amounts on the Credit Facility at December 31, 2019. 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 Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification 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
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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 quantitative analysis using a weighted-average cost of capital of 10.0%, 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.
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. We update our assumptions each reporting period based on new developments and adjust such amounts to fair value based on revised assumptions, if applicable, until such consideration is satisfied through payment upon achievement of the specified objectives or it is eliminated upon failure to achieve the specified objectives.
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As of December 31, 2019, we had delivered 176 million barrels of fresh water during the period between January 1, 2017 and December 31, 2019, which entitled Antero Resources to $125 million pursuant to clause (a) above, and, as a result, we paid Antero Resources $125 million in January 2020. We do not expect to deliver more than 219 million barrels of fresh water during the period between January 1, 2018 and December 31, 2020 based on Antero Resources’ disclosed 2020 budget. Accordingly, the fair value of the liability for contingent acquisition consideration was $125 million as of December 31, 2019. The fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 measurement within the fair value hierarchy. The fair value of the contingent consideration liability associated with future milestone payments was based on the risk adjusted present value of the contingent consideration payout.
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
In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement: Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement,” which provides changes to certain fair value disclosure requirements. This ASU is effective for annual reporting periods beginning after December 15, 2019 and interim periods within those annual periods, with early adoption permitted. The adoption of this update is not expected to have a material impact on our consolidated financial statements.
Off-Balance Sheet Arrangements
As of December 31, 2019, we did not have any off-balance sheet arrangements.
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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. At December 31, 2019, we had $960 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 $7.0 million increase in interest expense, for the year ended December 31, 2019.
Credit Risk
We are dependent on Antero Resources as our primary customer, and we expect to derive a substantial majority 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 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.
Item 8. Financial Statements and Supplementary Data
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page F-2 of this Annual Report on Form 10-K and are incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported,
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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, 2019 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, 2019 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, 2019.
The effectiveness of our internal control over financial reporting as of December 31, 2019 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, 2019, as stated in their report which appears on page F-2 in this Annual Report on Form 10-K.
Item 9B. Other Information
None.
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PART III
Item 10. Directors, Executive Officers, and Corporate Governance
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
Directors and Executive Officers
The following table sets forth names, ages and titles of our directors and executive officers as of February 12, 2020:
Name | Age | Title | |||
Paul M. Rady | 66 | Chairman and Chief Executive Officer | |||
Glen C. Warren, Jr. | 64 | Director, President and Secretary | |||
Michael N. Kennedy | 45 | Chief Financial Officer and Senior Vice President | |||
Alvyn A. Schopp | 61 | Chief Administrative Officer and Regional Senior Vice President | |||
W. Patrick Ash | 41 | Senior Vice President - Reserves, Planning & Midstream | |||
Peter A. Dea | 66 | Director | |||
W. Howard Keenan, Jr. | 69 | Director | |||
David H. Keyte | 63 | Director | |||
Brooks J. Klimley | 62 | Director | |||
John C. Mollenkopf | 58 | Director | |||
Rose M. Robeson | 59 | Director |
Set forth below is the description of the backgrounds of our directors and executive officers.
Paul M. Rady has served as our Chief Executive Officer and Chairman of the Board of Directors since the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Rady served as Chief Executive Officer of the general partner of AMGP beginning in January 2017 and as Chairman of the Board of Directors of such entity beginning in April 2017. Mr. Rady also previously served as Chief Executive Officer and Chairman of the Board of Directors of AMGP beginning in February 2014. Mr. Rady was a co-founder and has served as Chief Executive Officer and Chairman of the Board of Directors of Antero Resources since May 2004 and of its predecessor company from its founding in 2002 until its sale to XTO Energy, Inc. in April 2005. Prior to Antero, Mr. Rady served as President, CEO and Chairman of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Prior to Pennaco, Mr. Rady was with Barrett Resources from 1990 until 1998 where he initially was recruited as Chief Geologist in 1990, then served as Exploration Manager, EVP Exploration, President, COO and Director and ultimately CEO. Mr. Rady began his career with Amoco where he served 10 years as a geologist focused on the Rockies and Mid-Continent. Mr. Rady is the managing member of Salisbury Investment Holdings, LLC. Mr. Rady holds a B.A. in Geology from Western Colorado University and M.Sc. in Geology from Western Washington University.
Mr. Rady’s significant experience as a chief executive of oil and gas companies, together with his training as a geologist and broad industry knowledge, enable Mr. Rady to provide the board with executive counsel on a full range of business, strategic and professional matters.
Glen C. Warren, Jr. has served as our President and Secretary and as a director since the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Warren served as President and Secretary of the general partner of AMGP beginning in January 2017, and as a director of such entity beginning in April 2017. Mr. Warren also previously served as President and Secretary and as a director of AMGP beginning in January 2016, prior to which he served as President, Chief Financial Officer and Secretary and as a director beginning in February 2014. Mr. Warren was a co-founder and has served as President, Chief Financial Officer and Secretary and as a director of Antero Resources since May 2004 and of its predecessor company from its founding in 2002 until its sale to XTO Energy, Inc. in April 2005. Prior to Antero Resources, Mr. Warren served as EVP, CFO and Director of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Mr. Warren spent 10 years as a natural resources investment banker focused on equity and debt financing and M&A advisory with Lehman Brothers, Dillon Read and Kidder Peabody. Mr. Warren began his career as a landman in the Gulf Coast region with Amoco, where he spent six years. Mr. Warren is the managing member of Canton Investment Holdings, LLC. Mr. Warren holds a B.A. from the University of Mississippi, a J.D. from the University of Mississippi School of Law and an M.B.A. from the Anderson School of Management at U.C.L.A.
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Mr. Warren’s significant experience as a chief financial officer of oil and gas companies, together with his experience as an investment banker and broad industry knowledge, enable Mr. Warren to provide the board with executive counsel on a full range of business, strategic, financial and professional matters.
Michael N. Kennedy has served as our Chief Financial Officer since the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Kennedy served as Chief Financial Officer and Senior Vice President of Finance of AMGP beginning in January 2016, prior to which he served as Vice President of Finance of such entity beginning in August 2013. Mr. Kennedy has also served as Senior Vice President of Finance of Antero Resources since January 2016, prior to which he served as Vice President of Finance from August 2013 to December 2015. Mr. Kennedy was Executive Vice President and Chief Financial Officer of Forest Oil Corporation (“Forest”) from 2009 to 2013. From 2001 until 2009, Mr. Kennedy held various financial positions of increasing responsibility within Forest. From 1996 to 2001, Mr. Kennedy was an auditor with Arthur Andersen focusing on the Natural Resources industry. Mr. Kennedy holds a B.S. in Accounting from the University of Colorado at Boulder.
Alvyn A. Schopp has served as our Chief Administrative Officer and Senior Regional Vice President since January 2020, as Chief Administrative Officer, Regional Senior Vice President and Treasurer from the closing of the Transactions in March 2019 to December 2019. Prior to the Transactions, Mr. Schopp served as Chief Administrative Officer, Senior Regional Vice President, and Treasurer of AMGP beginning in January 2016, prior to which he served as Chief Administrative Officer, Regional Vice President and Treasurer of such entity beginning in February 2014. Mr. Schopp has also served as Chief Administrative Officer and Senior Regional Vice President of Antero Resources since January 2020, as Chief Administrative Officer, Regional Senior Vice President and Treasurer from January 2016 to December 2019, as Chief Administrative Officer, Regional Vice President and Treasurer from October 2013 to January 2016, as Vice President of Accounting and Administration and Treasurer from January 2005 to September 2013, as Controller and Treasurer from 2003 to 2005 and as Vice President of Accounting and Administration and Treasurer of Antero Resources’ predecessor company from January 2005 until its sale to XTO Energy, Inc. in April 2005. Mr. Schopp has also served as Chief Administrative Officer, Senior Regional Vice President, and Treasurer of the general partner of AMGP since April 2017. From 1993 to 2000, Mr. Schopp was CFO, Director and ultimately CEO of T-Netix. From 1980 to 1993 Mr. Schopp was with KPMG LLP. As a Senior Manager with KPMG, he maintained an extensive energy and mining practice. Mr. Schopp holds a B.B.A. from Drake University.
W. Patrick Ash has served as our and Antero Resources’ Senior Vice President – Reserves, Planning & Midstream, since June 2019, prior to which he served as our and Antero Resources’ Vice President of Reservoir Engineering and Planning beginning with the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Ash served as Vice President of Reservoir Engineering and Planning of Antero Resources and AMGP beginning in December 2017. Prior to joining us, Mr. Ash was at Ultra Petroleum for six years in management positions of increasing responsibility, most recently serving as Vice President, Development, including during and after Ultra’s bankruptcy proceedings, from which it emerged in 2017. In this position he led the reservoir engineering, geoscience, and corporate engineering groups. From 2001 to 2011, Mr. Ash served in engineering roles at Devon, NFR Energy and Encana. Mr. Ash holds a B.S. in Petroleum Engineering from Texas A&M University and a MBA from Washington University in St. Louis.
Peter Dea has served as a director of the Company since the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Dea served as a director of the general partner of AMGP beginning in April 2018. He is the Co-Founder and Executive Chairman of Confluence Resources LP, a Denver, Colorado-based oil and gas exploration and production company, and has been with the company since its inception in September 2016. Mr. Dea also serves on the Boards of Encana Corporation and Liberty Oilfield Services. Additionally, Mr. Dea served as Co-Founder, President and CEO of Cirque Resources LP since its inception in May 2007 and served as President, CEO and a Director of Western Gas Resources, Inc., from 2001 through their merger with Anadarko Petroleum Corporation in 2006. He joined Barrett Resources Corporation in 1993 and was CEO from 1999 and Chairman of the Board from 2000 until its sale in 2001 to Williams. Prior to joining Barrett, Mr. Dea held various management and geologic positions for Exxon Company USA. In addition to receiving geology degrees from the University of Montana, MS, and Western Colorado University, BA, he also attended the Harvard Business School Advanced Management Program.
Mr. Dea brings to the Board 35 years of experience and leadership in the exploration and development of multiple shale plays across the U.S., further supporting our integrated long-term strategy and focus. We believe his background and skill set make Mr. Dea well-suited to serve as a member of our board of directors.
W. Howard Keenan, Jr. has served as a director of the Company since the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Keenan served as a director of AMGP beginning in April 2017 and as a director of AMGP beginning in February 2014. Mr. Keenan also has served as a director of Antero Resources since 2004. Mr. Keenan has over 40 years of experience in the financial and energy businesses. Since 1997, he has been a Member of Yorktown Partners LLC, a private
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investment manager focused on the energy industry. From 1975 to 1997, he was in the Corporate Finance Department of Dillon, Read & Co. Inc. and active in the private equity and energy areas, including the founding of the first Yorktown Partners fund in 1991. He is serving or has served as a director of multiple Yorktown Portfolio companies and currently serves as a director of the following public companies: Brigham Minerals, Inc. and Solaris Oilfield Infrastructure, Inc. Mr. Keenan holds an B.A. degree cum laude from Harvard College and an M.B.A. degree from Harvard University.
Mr. Keenan has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Keenan well-suited to serve as a member of our board of directors.
David H. Keyte has served as a director of the Company since April 2019. Mr. Keyte is the Chairman of the board and Chief Executive Officer of Caerus Oil and Gas LLC, which he co-founded in November 2009. Prior to that, Mr. Keyte held senior executive positions at Forest Oil Corporation from November 1997 until November 2009, including the positions of Chief Financial Officer, Executive Vice President and Chief Accounting officer. Mr. Keyte served on the board of Regal Entertainment Group, a publicly held movie exhibition company, from 2006 until the company was sold in 2018. Mr. Keyte holds a B.S. degree in economics from the University of Pennsylvania’s Wharton School of Finance.
Mr. Keyte has significant experience in executive management and finance in the oil and gas industry. We believe his background and skill set make Mr. Keyte well-suited to serve as a member of our board of directors.
Brooks J. Klimley has served as a director of the Company since the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Klimley served as a director of the general partner of AMGP beginning in 2017, and as a director of AMGP from March 2015 to 2017. Mr. Klimley joined The Silverfern Group, which is focused on private equity co-investments, after a nearly 25 year career leading investment banking practices covering the energy and mining sectors. Additionally, Mr. Klimley has served as an Adjunct Professor at Columbia University’s graduate schools of business and international affairs since 2010. Previously, Mr. Klimley acted as President of Brooks J. Klimley & Associates, an energy advisory services firm focused on strategy and capital raising for energy and natural resources companies. Prior to founding his own firm in 2009, Mr. Klimley acted as the President of CIT Energy and held senior leadership positions at a number of financial institutions, including Citicorp, Bear Stearns, UBS and Kidder, Peabody. Mr. Klimley holds a dual B.A. / M.A. in Jurisprudence (Law) from Oxford University and a joint degree in Economics and History from Columbia University.
Mr. Klimley has significant experience with energy companies and investments and broad knowledge of the oil and gas industry. We believe his background and skill set make Mr. Klimley well-suited to serve as a member of our board of directors.
John C. Mollenkopf has served as a director of the Company since the closing of the Transactions in March 2019. Prior to the Transactions, Mr. Mollenkopf served as a director of the general partner of AMGP beginning in April 2017. Mr. Mollenkopf retired from MPLX, L.P. in October 2016. He previously served MPLX as Executive Vice President and Chief Operating Officer, MarkWest operations, from December 2015 through September 2016 following the merger of MPLX and MarkWest. From 2011 through 2015, he served as Executive Vice President and Chief Operating Officer of MarkWest. Mr. Mollenkopf began his employment with MarkWest Hydrocarbon, Inc. in 1996 as Manager New Projects and progressed to General Manager and later to Vice President of the Michigan Business unit. In 2002, Mr. Mollenkopf was one of the founders of MarkWest Energy GP, LLC, the general partner of MarkWest. Between 2002 and 2011, Mr. Mollenkopf served MarkWest as Vice President — Business Development, Senior Vice President — Southwest Business Unit, Senior Vice President and Chief Operations Officer, Senior Vice President and Chief Operating Officer. Between 1982 and 1996, Mr. Mollenkopf worked for ARCO Oil and Gas Company in California and Texas, holding positions of increasing responsibility in facilities, project, process and plant engineering as well as operations supervision. Mr. Mollenkopf holds a Bachelor of Science degree in mechanical engineering from the University of Colorado at Boulder, at which he continues to serve on the Engineering Advisory Council for the college of engineering.
Mr. Mollenkopf has significant experience in executive management, business development, marketing, engineering and operations in the oil and gas industry. We believe his background and skill set make Mr. Mollenkopf well-suited to serve as a member of our board of directors.
Rose M. Robeson has served as a director of the Company since the closing of the Transactions in March 2019. Prior to the Transactions, Ms. Robeson served as a director of the general partner of AMGP beginning in 2017. Prior to her retirement in March 2014, Ms. Robeson was Senior Vice President & Chief Financial Officer of DCP Midstream GP, LLC, the general partner of DCP Midstream Partners, LP from May 2012 until January 2014. Ms. Robeson also served as Group Vice President and Chief Financial Officer of DCP Midstream LLC from January 2002 to May 2012. Ms. Robeson served as a director of American Midstream GP, LLC, the general partner of American Midstream Partners, LP from June 2014 to June 2016. Ms. Robeson served as a
68
director of Tesco Corporation from November 2015 to December 2017. Ms. Robeson earned her B.S. degree in accounting from Northwest Missouri State University. Ms. Robeson became a certified public accountant in 1983 and her license is currently inactive. Ms. Robeson is a member of the board of directors of SM Energy, an independent energy company engaged in the acquisition, development, and production of crude oil, natural gas and natural gas liquids in onshore North America, and serves as Audit Committee Chair and serves on the Nominating and Governance Committee. Ms. Robeson is also a director of Newpark Resources, a worldwide provider of drilling fluids systems and composite matting systems used in oilfield services, and serves on the Audit, Nominating and Governance and Compensation committees.
Ms. Robeson brings to the Board over 30 years of experience in various aspects of the oil and gas industry, including exploration and production, midstream and refining and marketing. She also has significant financial management, risk management and accounting oversight experience. We believe her background and skill set make Ms. Robeson well-suited to serve as a member of our board of directors.
Code of Ethics
We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of our Corporate Code of Business Conduct and Ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and other persons performing similar functions by posting such information in the “Governance” subsection of our website at www.anteromidstream.com.
Item 11. Executive Compensation
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder 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 2020 Annual Meeting of Stockholders.
Item 13. Certain Relationships and Related Transactions and Director Independence
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.
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 2020 Annual Meeting of Stockholders.
69
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
The consolidated financial statements are listed on the Index to Financial Statements to this Annual Report on Form 10-K beginning on page F-1.
(a)(3) Exhibits.
Exhibit | Description of Exhibit |
2.1 | |
3.1 | |
3.2 | |
3.3 | |
3.4 | |
4.1 | |
4.2 | |
4.3* | |
4.4 | |
4.5 | |
4.6 | |
4.7 |
70
4.8 | |
4.9 | |
4.10 | |
4.11* | |
10.1* | |
10.2* | |
10.3* | |
10.4** | |
10.5 | |
10.6 | |
10.7 | |
10.8 | |
10.9* | |
10.10* | |
10.11 | |
10.12† |
71
10.13† | |
10.14† | |
10.15† | |
10.16† | |
10.17† | |
10.18† | |
10.19 | |
10.20 | |
10.21 | |
10.22 | |
21.1* | |
23.1* | |
31.1* | |
31.2* | |
32.1* | |
32.2* | |
99.1* | Unaudited pro forma condensed combined financial statements of Antero Midstream Corporation. |
72
101* | The following financial information from this Form 10-K of Antero Midstream Corporation for the year ended December 31, 2019, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text. |
104* | Cover Page Interactive Data File (embedded within the Inline XBRL document). |
The exhibits marked with the asterisk symbol (*) are filed or furnished with this Annual Report on Form 10-K.
** | Portions of this exhibit have been omitted pursuant to a request for confidential treatment. |
† | Management contract or compensatory plan or arrangement |
73
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ANTERO MIDSTREAM CORPORATION | |
By: | /s/ MICHAEL N. KENNEDY |
Michael N. Kennedy | |
Chief Financial Officer | |
Date: | February 12, 2020 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Signature |
| Title |
| Date |
|
/s/ PAUL M. RADY | Chairman of the Board, | February 12, 2020 | |||
Paul M. Rady | (principal executive officer) | ||||
/s/ MICHAEL N. KENNEDY | Chief Financial Officer | February 12, 2020 | |||
Michael N. Kennedy | (principal financial officer) | ||||
/s/ K. PHIL YOO | Vice President, Accounting and Chief Accounting Officer | February 12, 2020 | |||
K. Phil Yoo | (principal accounting officer) | ||||
/s/ GLEN C. WARREN, JR. | President, Director, and Secretary | February 12, 2020 | |||
Glen C. Warren, Jr. | |||||
/s/ PETER A. DEA |
| February 12, 2020 | |||
Peter A. Dea | |||||
/s/ W. HOWARD KEENAN, JR. |
| February 12, 2020 | |||
W. Howard Keenan, Jr. | |||||
/s/ DAVID H. KEYTE |
| February 12, 2020 | |||
David H. Keyte | |||||
/s/ BROOKS J. KLIMLEY |
| February 12, 2020 | |||
Brooks J. Klimley | |||||
/s/ JOHN C. MOLLENKOPF |
| February 12, 2020 | |||
John C. Mollenkopf | |||||
/s/ ROSE M. ROBESON |
| February 12, 2020 | |||
Rose M. Robeson |
74
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |
Audited Historical Consolidated Financial Statements as of December 31, 2018 and 2019 and for the Years Ended December 31, 2017, 2018, and 2019 | |
F-2 | |
F-5 | |
Consolidated Statements of Operations and Comprehensive Income | F-6 |
Consolidated Statements of Partners’ Capital and Stockholders’ Equity | F-7 |
F-8 | |
F-9 |
F-1
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors or
Antero Midstream Corporation:
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying consolidated balance sheets of Antero Midstream Corporation and subsidiaries (the Company) as of December 31, 2018 and 2019, the related consolidated statements of operations and comprehensive income, partners’ capital and stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting within Item 9A Controls and Procedures. Our responsibility is to express an opinion on the Company’s consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
F-2
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Evaluation of lease classification for ongoing modifications to the gathering and compression assets
As discussed in Note 7 to the consolidated financial statements, the Company determined that the gathering and compression agreement with Antero Resources is an operating lease. The Company continues to expand its gathering and compression system to serve its customer and, as a result, the minimum volume commitments and the lease payments increase for the expanded system. The increases in volume commitments and lease payments are modifications of the arrangement that require reconsideration of the lease classification.
We identified the evaluation of lease classification for ongoing modifications to the gathering and compression assets as a critical audit matter. The evaluation of lease classification for these modified leases, including evaluating economic life as a key estimate, required significant judgment.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s process for identifying lease modifications and determining lease classification for those modifications, including controls related to the review and approval of the Company’s lease modifications and the Company’s review of the lease classification. We evaluated the Company’s accounting memoranda and other documentation underlying the accounting conclusions reached, including application of relevant accounting guidance in regards to the modification accounting and subsequent lease classification. We evaluated the economic life used in the determination of lease classification. We evaluated fixed assets that are placed in service for new minimum volume commitments which would require reassessment of the lease.
Evaluation of the initial measurement of property and equipment and customer relationships acquired in the Antero Midstream Partners LP business combination
As discussed in Note 3 to the consolidated financial statements, on March 12, 2019, the Company acquired Antero Midstream Partners LP in a business combination. As a result of the transaction, the Company recognized property and equipment of $3,371,427 thousand and customer relationships intangible assets of $1,567,000 thousand.
We identified the evaluation of the initial measurement of property and equipment and the customer relationships acquired in the Antero Midstream Partners LP business combination as a critical audit matter. There was a high degree of subjectivity in evaluating the key assumptions used to calculate the acquisition date fair value of the property and equipment and the customer relationships intangible assets. The Company used the indirect cost and market approaches to value the property and equipment. The key assumptions included the inflationary trend and the useful lives of the underlying assets for the indirect cost method and comparable price per acre for the market approach. The Company used a discounted cash flow to value the customer relationships for which the key assumptions included forecasted revenue and the discount rate.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s business combination process, including controls related to the selection of the key assumptions used to determine the acquisition date fair value of property and equipment and customer relationships intangible assets. For the customer relationships intangible assets we evaluated the Company’s forecasts of revenues based on the Company’s
F-3
budgets and the Antero Midstream Partners LP historical performance. In addition, we involved valuation professionals with specialized skills and knowledge who assisted in:
| ● | Evaluating the approaches used to value the respective assets; |
| ● | Evaluating the inflationary trends, useful lives, and recent transactions based on publicly available information related to the estimated values for the property and equipment; |
| ● | Independently developing range of estimates of the fair value of the property and equipment and comparing it to the Company’s estimated fair values for the property and equipment; |
| ● | Evaluating the Company’s discount rate applied in the valuation of the customer relationships intangible assets by comparing the Company’s inputs to publicly available data, the implied rate of return on the transaction, and the return on other acquired assets; and |
| ● | Testing the estimate of the customer relationships intangible assets fair value using the Company’s cash flow assumptions and discount rate, and evaluated the result with the Company’s fair value estimate. |
/s/ KPMG LLP
We have served as the Company’s auditor since 2016.
Denver, Colorado
February 12, 2020
F-4
ANTERO MIDSTREAM CORPORATION
Consolidated Balance Sheets
December 31, 2018 and 2019
(In thousands)
December 31, | |||||||
| 2018 |
| 2019 |
| |||
Assets | |||||||
Current assets: |
| ||||||
Cash and cash equivalents | $ | | | ||||
Accounts receivable–Antero Resources | — | | |||||
Accounts receivable–third party | — | | |||||
Other current assets | | | |||||
Total current assets | | | |||||
Property and equipment, net | — | | |||||
Investments in unconsolidated affiliates | | | |||||
Deferred tax asset | | | |||||
Customer relationships | — | | |||||
Goodwill | — | | |||||
Other assets, net | — | | |||||
Total assets | $ | | | ||||
Liabilities and Equity | |||||||
Current liabilities: | |||||||
Accounts payable–Antero Resources | $ | | | ||||
Accounts payable–third party | | | |||||
Accrued liabilities | | | |||||
Contingent acquisition consideration | — | | |||||
Taxes payable | | — | |||||
Other current liabilities | — | | |||||
Total current liabilities | | | |||||
Long-term liabilities: | |||||||
Long-term debt | — | | |||||
Other | — | | |||||
Total liabilities | | | |||||
Partners' Capital and Stockholders' Equity: | |||||||
Common shareholders— | ( | — | |||||
IDR LLC Series B units ( | | — | |||||
Preferred stock, $ | |||||||
Series A non-voting perpetual preferred stock; | — | — | |||||
Common stock, $ | — | | |||||
Additional paid-in capital | — | | |||||
Accumulated loss | — | ( | |||||
Total partners' capital and stockholders' equity | | | |||||
Total liabilities and partners' capital and stockholders' equity | $ | | | ||||
See accompanying notes to consolidated financial statements.
F-5
ANTERO MIDSTREAM CORPORATION
Consolidated Statements of Operations and Comprehensive Income
Years Ended December 31, 2017, 2018, and 2019
(In thousands, except per unit amounts)
Year Ended December 31, | |||||||||
2017 |
| 2018 |
| 2019 |
| ||||
Revenue: | |||||||||
Gathering and compression–Antero Resources | $ | — | — | | |||||
Water handling–Antero Resources | — | — | | ||||||
Water handling–third party | — | — | | ||||||
Amortization of customer relationships | — | — | ( | ||||||
Total revenue | — | — | | ||||||
Operating expenses: | |||||||||
Direct operating | — | — | | ||||||
General and administrative (including $ | | | | ||||||
Facility idling | — | — | | ||||||
Impairment of property and equipment | — | — | | ||||||
Impairment of goodwill | — | — | | ||||||
Impairment of customer relationships | — | — | | ||||||
Depreciation | — | — | | ||||||
Accretion and change in fair value of contingent acquisition consideration | — | — | | ||||||
Accretion of asset retirement obligations | — | — | | ||||||
Total operating expenses | | | | ||||||
Operating loss | ( | ( | ( | ||||||
Interest expense, net | — | ( | ( | ||||||
Equity in earnings of unconsolidated affiliates | | | | ||||||
Income (loss) before income taxes | | | ( | ||||||
Provision for income tax benefit (expense) | ( | ( | | ||||||
Net income (loss) and comprehensive income (loss) | $ | | | ( | |||||
Net income (loss) per share–basic and diluted | $ | | | ( | |||||
Weighted average common shares outstanding: | |||||||||
Basic | | | | ||||||
Diluted | | | | ||||||
See accompanying notes to consolidated financial statements.
F-6
ANTERO MIDSTREAM CORPORATION
Consolidated Statements of Partners’ Capital and Stockholders’ Equity
Years Ended December 31, 2017, 2018, and 2019
(In thousands)
Antero | ||||||||||||||||||||||||||||
|
| Common |
| Resources |
|
|
|
|
|
| ||||||||||||||||||
Shares | Midstream | |||||||||||||||||||||||||||
Representing | Management | |||||||||||||||||||||||||||
Limited | LLC | Additional | ||||||||||||||||||||||||||
Common Stock | Partner | Members' | Series B | Paid-In | Preferred | Accumulated | Total | |||||||||||||||||||||
Shares | Amount | Interests | Equity | Unitholders | Capital | Stock | Loss | Equity | ||||||||||||||||||||
Balance at December 31, 2016 | — | $ | — | — | | — | — | — | — | | ||||||||||||||||||
Pre-IPO net loss and comprehensive loss | — | — | — | ( | — | — | — | — | ( | |||||||||||||||||||
Pre-IPO equity-based compensation | — | — | — | | — | — | — | — | | |||||||||||||||||||
Conversion of Antero Resources Midstream Management LLC to a limited partnership | — | — | | ( | — | — | — | — | — | |||||||||||||||||||
Post-IPO net income and comprehensive income | — | — | | — | | — | — | — | | |||||||||||||||||||
Post-IPO equity-based compensation | — | — | | — | — | — | — | — | | |||||||||||||||||||
Distributions to Antero Resources Investment LLC | — | — | ( | — | — | — | — | — | ( | |||||||||||||||||||
Distributions to shareholders | — | — | ( | — | — | — | — | — | ( | |||||||||||||||||||
Vesting of Series B units | — | — | ( | — | | — | — | — | — | |||||||||||||||||||
Balance at December 31, 2017 | — | — | ( | — | | — | — | — | | |||||||||||||||||||
Net income and comprehensive income | — | — | | — | | — | — | — | | |||||||||||||||||||
Equity-based compensation | — | — | | — | — | — | — | — | | |||||||||||||||||||
Distributions to shareholders | — | — | ( | — | — | — | — | — | ( | |||||||||||||||||||
Distributions to Series B unitholders | — | — | — | — | ( | — | — | — | ( | |||||||||||||||||||
Vesting of Series B units | — | — | ( | — | | — | — | — | — | |||||||||||||||||||
Balance at December 31, 2018 | — | — | ( | — | | — | — | — | | |||||||||||||||||||
Distributions to unitholders | — | — | ( | — | ( | — | — | — | ( | |||||||||||||||||||
Net (loss) and comprehensive (loss) pre-acquisition | — | — | ( | — | — | — | — | — | ( | |||||||||||||||||||
Equity-based compensation pre-acquisition | — | — | | — | — | — | — | — | | |||||||||||||||||||
Exchange of common shares for shares of common stock and cash consideration paid | | | | — | ( | | — | — | | |||||||||||||||||||
Issuance of Series A non-voting perpetual preferred stock | — | — | — | — | — | — | — | — | — | |||||||||||||||||||
Dividends to stockholders | — | — | — | — | — | ( | — | — | ( | |||||||||||||||||||
Equity-based compensation post-acquisition | — | — | — | — | — | | — | — | | |||||||||||||||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of common stock withheld for income taxes | | | — | — | — | ( | — | — | ( | |||||||||||||||||||
Repurchases and retirement of common stock | ( | ( | — | — | — | ( | — | — | ( | |||||||||||||||||||
Net loss and comprehensive loss post-acquisition | — | — | — | — | — | — | — | ( | ( | |||||||||||||||||||
Balance at December 31, 2019 | | $ | | — | — | — | | — | ( | | ||||||||||||||||||
See accompanying notes to consolidated financial statements.
F-7
ANTERO MIDSTREAM CORPORATION
Consolidated Statements of Cash Flows
Years Ended December 31, 2017, 2018, and 2019
(In thousands)
Year Ended December 31, | ||||||||||
| 2017 |
| 2018 |
| 2019 |
| ||||
Cash flows provided by (used in) operating activities: |
| |||||||||
Net income (loss) | $ | | | ( | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||
Distributions from Antero Midstream Partners LP, prior to the Transactions | | | | |||||||
Depreciation | — | — | | |||||||
Accretion and change in fair value of contingent acquisition consideration | — | — | | |||||||
Impairment | — | — | | |||||||
Deferred income tax benefit | — | ( | ( | |||||||
Equity-based compensation | | | | |||||||
Equity in earnings of unconsolidated affiliates | ( | ( | ( | |||||||
Distributions from unconsolidated affiliates | — | — | | |||||||
Amortization of customer relationships | — | — | | |||||||
Amortization of deferred financing costs | — | | | |||||||
Changes in assets and liabilities: | ||||||||||
Accounts receivable–Antero Resources | — | — | | |||||||
Accounts receivable–third party | — | — | | |||||||
Other current assets | — | ( | ( | |||||||
Accounts payable–Antero Resources | | | ( | |||||||
Accounts payable–third party | — | | ( | |||||||
Accrued liabilities | ( | | | |||||||
Income taxes payable | | | ( | |||||||
Net cash provided by operating activities | | | | |||||||
Cash flows used in investing activities: | ||||||||||
Additions to gathering systems and facilities | — | — | ( | |||||||
Additions to water handling systems | — | — | ( | |||||||
Investments in unconsolidated affiliates | — | — | ( | |||||||
Cash received on acquisition of Antero Midstream Partners LP | — | — | | |||||||
Cash consideration paid to Antero Midstream Partners LP unitholders | — | — | ( | |||||||
Change in other assets | — | — | | |||||||
Change in other liabilities | — | — | ( | |||||||
Net cash used in investing activities | — | — | ( | |||||||
Cash flows provided by (used in) financing activities: | ||||||||||
Distributions to Antero Resources Investment LLC | ( | — | — | |||||||
Distributions to unitholders and dividends to stockholders | ( | ( | ( | |||||||
Distributions to Series B unitholders | — | ( | ( | |||||||
Distributions to preferred stockholders | — | — | ( | |||||||
Repurchases of common stock | — | — | ( | |||||||
Issuance of senior notes | — | — | | |||||||
Payments of deferred financing costs | — | ( | ( | |||||||
Payments on bank credit facilities, net | — | — | ( | |||||||
Employee tax withholding for settlement of equity compensation awards | — | — | ( | |||||||
Other | — | — | ( | |||||||
Net cash used in financing activities | ( | ( | ( | |||||||
Net decrease in cash and cash equivalents | ( | ( | ( | |||||||
Cash and cash equivalents, beginning of period | | | | |||||||
Cash and cash equivalents, end of period | $ | | | | ||||||
Supplemental disclosure of cash flow information: | ||||||||||
Cash paid during the period for interest | $ | — | | | ||||||
Cash paid during the period for income taxes | $ | | | | ||||||
Decrease in accrued capital expenditures and accounts payable for property and equipment | $ | — | — | ( | ||||||
See accompanying notes to consolidated financial statements.
F-8
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements
Years Ended December 31, 2016, 2017, and 2018
(1) Organization
Antero Midstream Corporation was originally formed as Antero Resources Midstream Management LLC in 2013 to become the general partner of Antero Midstream Partners LP (“Antero Midstream Partners”). On May 4, 2017, Antero Resources Midstream Management LLC converted from a limited liability company to a limited partnership under the laws of the State of Delaware and changed its name to Antero Midstream GP LP (“AMGP”) in connection with its initial public offering. On March 12, 2019, pursuant to the Simplification Agreement, dated as of October 9, 2018, by and among AMGP, Antero Midstream Partners and certain of their affiliates (the “Simplification Agreement”), (i) AMGP was converted from a limited partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation (the “Conversion”), (ii) an indirect, wholly owned subsidiary of Antero Midstream Corporation was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream Corporation (the “Merger”), and (iii) Antero Midstream Corporation exchanged (the “Series B Exchange” and, together with the Conversion, the Merger and the other transactions pursuant to by the Simplification Agreement, the “Transactions”) each issued and outstanding Series B Unit (the “Series B Units”) representing a membership interest in Antero IDR Holdings LLC (“IDR Holdings”) for
We are a growth-oriented midstream company formed to own, operate and develop midstream energy infrastructure primarily to service Antero Resources and its production and completion activity in the Appalachian Basin’s Marcellus Shale and Utica Shale located in West Virginia and Ohio. Our assets consist of gathering pipelines, compressor stations, interests in processing and fractionation plants, and water handling assets. The Company, through Antero Midstream Partners and its affiliates, provides midstream services to Antero Resources under long-term contracts.
The Company’s gathering and compression assets comprise of high and low pressure gathering pipelines, compressor stations, and processing and fractionation plants that collect and process natural gas and NGLs from Antero Resources’ wells in West Virginia and Ohio. The Company’s water handling assets include
The Company, through Antero Midstream Partners, also has a
The Company’s corporate headquarters are located in Denver, Colorado.
(2) Summary of Significant Accounting Policies
(a) | Basis of Presentation |
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, these consolidated statements include all adjustments (consisting of normal and recurring accruals) considered necessary for a fair presentation of the Company’s financial position as of December 31, 2018 and 2019, and the results of the Company’s operations and its cash flows for the years ended December 31, 2017, 2018 and 2019. The Company has no items of other comprehensive income (loss); therefore, net income (loss) is equal to comprehensive income (loss).
F-9
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
Certain costs of doing business incurred and charged to the Company by Antero Resources have been reflected in the accompanying consolidated financial statements. These costs include general and administrative expenses provided to the Company by Antero Resources in exchange for:
● business services, such as payroll, accounts payable and facilities management;
● corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy; and
● employee compensation, including equity-based compensation.
Transactions between the Company and Antero Resources have been identified in the consolidated financial statements (see Note 6—Transactions with Affiliates).
(b) | Principles of Consolidation |
The accompanying consolidated financial statements include (i) for the period prior to March 13, 2019, the accounts of AMGP and its consolidated subsidiaries, which did not include Antero Midstream Partners and its subsidiaries, and (ii) for the period beginning on March 13, 2019, the accounts of Antero Midstream Corporation and its consolidated subsidiaries, including Antero Midstream Partners and its subsidiaries, which were acquired in the Transactions. See Note 3—Business Combination. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements.
Prior to the Transactions on March 12, 2019, AMGP had determined that Antero Midstream Partners was a variable interest entity (“VIE”) for which AMGP was not the primary beneficiary and therefore did not consolidate. AMGP concluded that Antero Resources was the primary beneficiary of Antero Midstream Partners and Antero Resources consolidated its financial results. Antero Resources was the primary beneficiary based on its power to direct the activities that most significantly impacted Antero Midstream Partners’ economic performance and its obligations to absorb losses or receive benefits of Antero Midstream Partners that would be significant to Antero Midstream Partners. Antero Resources owned approximately
AMGP’s ownership of the non-economic general partner interest in Antero Midstream Partners prior to the Transactions provided AMGP with significant influence over Antero Midstream Partners, but not control over the decisions that most significantly impacted the economic performance of Antero Midstream Partners. AMGP’s indirect ownership of the IDRs of Antero Midstream Partners prior to the Transactions entitled AMGP to receive cash distributions from Antero Midstream Partners when distributions exceeded certain target amounts. AMGP’s ownership of these interests prior to the Transactions did not require AMGP to provide financial support to Antero Midstream Partners. AMGP obtained these interests upon its formation for no consideration. Therefore, AMGP had no cost basis and classified its investment in Antero Midstream Partners as a long term investment. Prior to the Transactions, AMGP’s share of Antero Midstream Partner’s earnings were a result of AMGP’s ownership of the IDRs was accounted for using the equity method of accounting. AMGP recognized distributions earned from Antero Midstream Partners as “Equity in earnings of unconsolidated affiliates” on its statement of operations in the period in which they were earned and were allocated to AMGP’s capital account. AMGP’s long-term interest in the IDRs on the balance sheet was recorded in “Investment in unconsolidated affiliates.” The ownership of the general partner interests and IDRs did not provide AMGP with any claim to the assets of Antero Midstream Partners other than the balance in its Antero Midstream Partners capital account. Income related to the IDRs was recognized as earned and increased AMGP’s capital account and equity investment. When these distributions were paid to AMGP, they reduced its capital account and its equity investment in Antero Midstream Partners.
Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero Midstream’s ownership interest, representation on the board of directors, and participation in the policy-making decisions of equity method investees. Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings
F-10
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows. When the Company records its proportionate share of net income, it increases equity income in the statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the balance sheet.
The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities).
(c) Revenue Recognition
The Company, through Antero Midstream Partners and its affiliates, provides gathering and compression and water handling services under fee-based contracts primarily based on throughput or at cost plus a margin. Certain of these contracts contain operating leases of the Company’s assets under GAAP. Under these arrangements, the Company receives fees for gathering gas products, compression services, and water handling services. The revenue the Company earns from these arrangements is directly related to (1) in the case of natural gas gathering and compression, the volumes of metered natural gas that it gathers, compresses, and delivers to natural gas compression sites or other transmission delivery points, (2) in the case of fresh water services, the quantities of fresh water delivered to its customers for use in their well completion operations, (3) in the case of wastewater treatment services performed by the Company prior to idling of the Clearwater Facility (as defined below) in September 2019, the quantities of wastewater treated for our customers, (4) in the case of wastewater services provided by third parties, the third-party costs the Company incurs plus
(d) | Use of Estimates |
The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent liabilities. Items subject to estimates and assumptions include the useful lives of property and equipment, the valuation of assets and liabilities acquired from Antero Midstream Partners, as well as the valuation of accrued liabilities, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.
(e) | Cash and Cash Equivalents |
The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
(f) | Property and Equipment |
Property and equipment primarily consists of gathering pipelines, compressor stations and the wastewater treatment facility and related landfill (collectively, the “Clearwater Facility”) used for the disposal of salt therefrom and fresh water delivery pipelines and facilities stated at historical cost less accumulated depreciation, amortization and impairment. The Company capitalizes construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred.
Depreciation of property and equipment is computed using the straight-line method over the estimated useful lives and salvage values of assets. The depreciation of fixed assets recorded under operating lease agreements is included in depreciation expense. Uncertainties that may impact these estimates of useful lives include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand for the Company’s services in the areas in which it operates. When assets are placed into service, management
F-11
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
makes estimates with respect to useful lives and salvage values that management believes are reasonable.
Amortization of landfill airspace consists of the amortization of landfill capital costs, including those that have been incurred and capitalized and estimated future costs for landfill development and construction, as well as the amortization of asset retirement costs arising from landfill final capping, closure, and post-closure obligations. Amortization expense is recorded on a units-of-consumption basis, applying cost as a rate per-cubic yard. The rate per-cubic yard is calculated by dividing each component of the amortizable basis of the landfill by the number of cubic yards needed to fill the corresponding asset’s airspace. Landfill capital costs and closure and post-closure asset retirement costs are generally incurred to support the operation of the landfill over its entire operating life and are, therefore, amortized on a per-cubic yard basis using a landfill’s total airspace capacity. Estimates of disposal capacity and future development costs are created using input from independent engineers and internal technical teams and are reviewed at least annually.
The Company evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs, and discount rates typical of third-party market participants, which is a Level 3 fair value measurement. The Company recognized an impairment with respect to the Clearwater Facility during the year ended December 31, 2019. See Note 4—Clearwater Facility Impairment.
(g) | Asset Retirement Obligations |
The Company’s asset retirement obligations include its obligation to close, maintain, and monitor landfill cells and support facilities. After the entire landfill reaches capacity and is certified closed, the Company must continue to maintain and monitor the landfill for a post-closure period, which generally extends for
Asset retirement obligations are recorded for fresh water impoundments and waste water pits when an abandonment date is identified. The Company records the fair value of its freshwater impoundment and waste water pit retirement obligations as liabilities in the period in which the regulatory obligation to retire a specific asset is triggered. The fair value is based on the total reclamation costs of the assets. Retirement obligations are increased each year to reflect the passage of time by accreting the balance at the weighted average credit-adjusted risk-free rate that is used to calculate the recorded liability, with accretion charged to direct costs. Actual cash expenditures to perform remediation activities reduce the retirement obligation liabilities as incurred. After initial measurement, asset retirement obligations are adjusted at the end of each period to reflect changes, if any, in the estimated future cash flows underlying the obligation. Fresh water impoundments and wastewater pit retirement assets are capitalized as the related retirement obligations are incurred, and are amortized on a straight-line basis until reclamation.
The Company is under no legal obligations, neither contractually nor under the doctrine of promissory estoppel, to restore or dismantle its gathering pipelines, compressor stations, water delivery pipelines and facilities, flowback and produced water facilities and the wastewater treatment facility upon abandonment. See Note 4—Clearwater Facility Impairment.
F-12
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(h) | Litigation and Other Contingencies |
A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of our accruals and related disclosures. The ultimate amount of losses, if any, may differ from these estimates.
The Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time a remediation feasibility study, or an evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.
As of December 31, 2018 and 2019, the Company had not recorded any liabilities for litigation, environmental, or other contingencies.
(i) | Equity-Based Compensation |
The Company’s consolidated financial statements include equity-based compensation costs related to awards granted by its own plans, as in place before and after the Transactions, as well as costs allocated by Antero Resources for grants made prior to the Transactions. Costs allocated from Antero Resources are offset to additional paid in capital on the consolidated balance sheet. See Note 6—Transactions with Affiliates for additional information regarding Antero Resources’ allocation of expenses to the Company. For awards granted under its own plan, the Company recognizes compensation cost related to all equity-based awards in the financial statements based on the estimated grant date fair value. The Company is authorized to grant various types of equity-based compensation awards, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards and other types of awards. The grant date fair values are determined based on the type of award and may utilize market prices on the date of grant, Black-Scholes option-pricing model, Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of equity-based award. Compensation cost is recognized ratably over the applicable vesting or service period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. See Note 12—Equity-Based Compensation.
(j) | Income Taxes |
The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. The Company regularly reviews its tax positions in each significant taxing jurisdiction during the process of evaluating its tax provision. The Company makes adjustments to its tax provision when: (i) facts and circumstances regarding a tax position change, causing a change in management’s judgment regarding that tax position; and/or (ii) a tax position is effectively settled with a tax authority at a differing amount.
(k) | Fair Value Measures |
The Financial Accounting Standards Board (the “FASB”) ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is
F-13
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.
The carrying values on the consolidated balance sheet of the Company’s cash and cash equivalents, accounts receivable—Antero Resources, accounts receivable—third party, other current assets, accounts payable—Antero Resources, accounts payable—third party, accrued liabilities, other current liabilities, other liabilities and the Credit Facility (as defined in Note 10—Long-Term Debt) approximate fair values due to their short-term maturities. The assets and liabilities of Antero Midstream Partners were recorded at fair value as of the acquisition date, March 12, 2019 (see Note 3—Business Combination). Additionally, the Company uses certain fair valuation techniques in performing its annual goodwill impairment test described below.
(l) | Investments in Unconsolidated Affiliates |
The Company uses the equity method to account for its investments in companies if the investment provides the Company with the ability to exercise significant influence over, but not control of, the operating and financial policies of the investee. The Company’s consolidated net income includes the Company’s proportionate share of the net income or loss of such companies. The Company’s judgment regarding the level of influence over each equity method investee includes considering key factors such as the Company’s ownership interest, representation on the board of directors and participation in policy-making decisions of the investee and material intercompany transactions. See Note 16—Investments in Unconsolidated Affiliates.
(m) | Business Combinations |
The Company recognizes and measures the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill. For acquisitions, management engages an independent valuation specialist, as applicable, to assist with the determination of fair value of the assets acquired, liabilities assumed, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, the Company will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the acquisition date. An adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment. Acquisition-related costs are expensed as incurred in connection with each business combination. See Note 3—Business Combination.
(n) | Goodwill and Intangible Assets |
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment annually in the fourth quarter and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. The fair value is calculated using the expected present value of future cash flows method. Significant assumptions used in the cash flow forecasts include future net operating margins, future volumes, discount rates and future capital requirements. If the fair value of the reporting unit is less than the carrying value, including goodwill, the excess of the book value over the fair value of goodwill is charged to net income as an impairment expense.
Amortization of intangible assets with definite lives is calculated using the straight-line method, which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. Intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible asset may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. See Note 4—Clearwater Facility Impairment and Note 5—Goodwill and Intangibles.
F-14
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(o) | Treasury Share Retirement |
The Company periodically retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares outstanding, to the balance of additional paid-in capital as of retirement.
(p) | Recently Issued Accounting Standards |
In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement: Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement,” which provides changes to certain fair value disclosure requirements. This ASU is effective for annual reporting periods beginning after December 15, 2019 and interim periods within those annual periods, with early adoption permitted. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.
F-15
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(3) Business Combination
On March 12, 2019, AMGP and Antero Midstream Partners completed the Transactions. The Transactions have been accounted for using the acquisition method of accounting with Antero Midstream Corporation identified as the acquirer of Antero Midstream Partners.
The components of the fair value of consideration transferred are as follows (in thousands):
Fair value of shares of AMC common stock issued(1) | $ | | ||
Cash | | |||
Total fair value of consideration transferred | $ | |
The final purchase price allocation of the Transactions, and final adjustments thereto, are summarized in the table below. The fair value of assets acquired and liabilities assumed at March 12, 2019 were as follows (in thousands):
As Originally | As | |||||||||
Reported | Adjustments | Adjusted | ||||||||
Cash and cash equivalents | $ | | — | | ||||||
Accounts receivable–Antero Resources | | — | | |||||||
Accounts receivable–third party | | — | | |||||||
Other current assets | | — | | |||||||
Property and equipment, net | | ( | | |||||||
Investments in unconsolidated affiliates | | ( | | |||||||
Customer relationships | | | | |||||||
Other assets, net | | — | | |||||||
Total assets acquired | | | | |||||||
Accounts payable–Antero Resources | | — | | |||||||
Accounts payable–third party | | — | | |||||||
Accrued liabilities | | — | | |||||||
Other current liabilities | | — | | |||||||
Long-term debt | | — | | |||||||
Contingent acquisition consideration | | — | | |||||||
Other liabilities | | — | | |||||||
Total liabilities assumed | | — | | |||||||
Net assets acquired, excluding goodwill | | | | |||||||
Goodwill | | ( | | |||||||
Net assets acquired | $ | | $ | — | $ | |
Adjustments to the preliminary purchase price allocation stem mainly from additional information obtained by the Company in between the closing of the Transactions on March 12, 2019 and December 31, 2019 about facts and circumstances that existed as of the date of the Transactions, including updates to the completion of certain valuations to determine the underlying fair value of certain assets. The decrease in the fair value of the property and equipment resulted in a $
The purchase price allocation resulted in the recognition of $
F-16
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
Substantially all of goodwill is expected to be deductible for tax purposes. Goodwill represents the efficiencies realized with simplifying our corporate structure to own, operate and develop midstream energy infrastructure primarily to service Antero Resources.
The Company’s financial statements include $
(4) Clearwater Facility Impairment
On September 18, 2019, the Company commenced a strategic evaluation of the Clearwater Facility at which time, such facility was idled. Based on the preliminary results of the evaluation and ongoing discussions with the facility’s contractor, the Company determined that the facility is expected to be idled for the foreseeable future. Accordingly, the Company performed an interim impairment analysis of the facility and determined: (i) to reduce the carrying value of the facility to its estimated salvage value, which included the land associated with the Clearwater Facility; (ii) the fair value of the goodwill assigned to the wastewater treatment reporting unit was less than its carrying value resulting in an impairment charge to goodwill; and (iii) the customer relationships intangible asset was impaired. The following table shows the impairment charges for the year ended December 31, 2019 related to the Clearwater Facility as updated to reflect the final purchase price allocation of the Transactions (in thousands):
Impairment of property and equipment | $ | | ||
Impairment of goodwill | | |||
Impairment of customer relationships | | |||
Total impairment expense | $ | |
The Company incurred $
(5) Goodwill and Intangibles
The Company evaluates goodwill for impairment annually during the fourth quarter and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its carrying amount. Significant assumptions used to estimate the reporting units’ fair value include the discount rate as well as estimates of future cash flows, which are impacted primarily by commodity prices and producer customers’ development plans (which impact volumes and capital requirements).
During the third quarter of 2019, the Company performed an interim impairment analysis of the goodwill related to the wastewater treatment reporting unit recorded in connection with the Transactions due to the Company’s strategic evaluation of the Clearwater Facility. As a result of this evaluation, the Company incurred impairment charges to the goodwill and customer relationships intangible asset associated with the Clearwater Facility, which is in the water handling segment. See Note 4—Clearwater Facility Impairment.
The Company performed its annual goodwill impairment test in the fourth quarter of 2019. As a result of this test, the Company incurred impairment charges of $
F-17
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
The changes in the carrying amount in goodwill for the year ended December 31, 2019 were as follows (in thousands):
| Gathering and |
| Water |
| Consolidated | |||||
|
| Processing |
| Handling |
| Total |
| |||
Goodwill as of December 31, 2018 | $ | — | — | — | ||||||
Goodwill acquired(1) | | | | |||||||
Impairment of goodwill | — | ( | ( | |||||||
Goodwill as of December 31, 2019 | $ | | — | | ||||||
| (1) | See Note 3—Business Combination. |
All customer relationships are subject to amortization and will be amortized over a weighted-average period of
Customer relationships as of December 31, 2018 | $ | — | ||
Customer relationships acquired(1) | | |||
Accumulated amortization | ( | |||
Impairment |
| ( |
| |
Customer relationships as of December 31, 2019 | $ | |
| (1) | See Note 3—Business Combination. |
Future amortization expense is as follows (in thousands):
Year ending December 31, 2020 | $ | | ||
Year ending December 31, 2021 | | |||
Year ending December 31, 2022 | | |||
Year ending December 31, 2023 | | |||
Year ending December 31, 2024 | | |||
Thereafter | | |||
Total | $ | |
(6) Transactions with Affiliates
(a) | Revenues |
Substantially all revenues earned in the year ended December 31, 2019 were earned from Antero Resources, under various agreements for gathering and compression and water handling services. Revenues earned from gathering and processing services consists of lease income. There were no such revenues earned by AMGP for the years ended December 31, 2017 and 2018.
(b) | Accounts receivable–Antero Resources, and Accounts payable–Antero Resources |
Accounts receivable—Antero Resources represents amounts due from Antero Resources, primarily related to gathering and compression services and water handling services. Accounts payable—Antero Resources represents amounts due to Antero Resources for general and administrative and other costs.
(c) | Allocation of Costs Charged by Antero Resources |
The employees supporting the Company’s operations are concurrently employed by Antero Resources and Antero Midstream Corporation. Direct operating expense includes costs charged to the Company of $
F-18
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
$
(7) Revenue
(a) | Revenue from Contracts with Customers |
All of the Company’s revenues are derived from service contracts with customers and are recognized when the Company satisfies a performance obligation by delivering a service to a customer. The Company derives substantially all of its revenues from Antero Resources. The following sets forth the nature, timing of satisfaction of performance obligations, and significant payment terms of the Company’s contracts with Antero Resources.
Gathering and Compression Agreement
Pursuant to the gathering and compression agreement with Antero Resources, Antero Resources has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to the Company for gathering and compression services except for acreage subject to third-party commitments or pre-existing dedications. The Company also has an option to gather and compress natural gas produced by Antero Resources on any additional acreage it acquires during the term of the agreement outside of West Virginia, Ohio and Pennsylvania on the same terms and conditions. In December 2019, the Company and Antero Resources agreed to extend the initial term of the gathering and compression agreement to 2038 and established a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent Antero Resources achieves certain volumetric targets. Upon completion of this term, the gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either the Company or Antero Resources on or before the
Under the gathering and compression agreement, the Company receives a low pressure gathering fee, a high pressure gathering fee and a compression fee, in each case subject to CPI-based adjustments. In addition, the agreement stipulates that the Company receives a reimbursement for the actual cost of electricity used at its compressor stations.
The Company determined that the gathering and compression agreement is an operating lease as Antero Resources obtains substantially all of the economic benefit of the asset and has the right to direct the use of the asset. The gathering system is an identifiable asset within the gathering and compression agreement, and it consists of underground low pressure pipelines that generally connect and deliver gas from specific well pads to compressor stations to compress the gas before delivery to underground high pressure pipelines that transport the gas to a third-party pipeline or plant. The gathering system is considered a single lease due to the interrelated network of the assets. The Company accounts for its lease and non-lease components as a single lease component as the lease component is the predominant component. The non-lease components consist of operating, oversight and maintenance of the gathering system, which are performed on time-elapsed measures. All lease payments under the future Minimum Volume Commitments discussed below are considered to be in-substance fixed lease payments under the gathering and compression agreement.
The Company recognizes revenue when low pressure volumes are delivered to a compressor station, compression volumes are delivered to a high pressure line and high pressure volumes are delivered to a processing plant or transmission pipeline. The Company invoices the customer the month after each service is performed, and payment is due in the same month.
Water Services Agreement
The Company is party to a water services agreement with Antero Resources, which commenced on September 23, 2015,
F-19
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
whereby the Company agreed to provide certain water handling services to Antero Resources within an area of dedication in defined service areas in West Virginia, Ohio and other locations. Upon completion of the initial term
Under the water services agreement, the Company may also contract with third parties to provide water services to Antero Resources. Antero Resources reimburses the Company for third-party out-of-pocket costs plus a
Minimum Volume Commitments
The gathering and compression agreement includes certain minimum volume commitment provisions. If and to the extent Antero Resources requests that the Company construct new high pressure lines and compressor stations, the gathering and compression agreement contains minimum volume commitments that require Antero Resources to utilize or pay for
Minimum revenue amounts under the gathering and compression minimum volume commitments are as follows (in thousands):
2020 | $ | | ||
2021 | | |||
2022 | | |||
2023 | | |||
2024 | | |||
Thereafter | | |||
Total | $ | |
F-20
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(b) | Disaggregation of Revenue |
In the following table, revenue is disaggregated by type of service and type of fee. The table also identifies the reportable segment to which the disaggregated revenues relate. AMGP did not earn revenue for the years ended December 31, 2017 and 2018. For more information on reportable segments, see Note 17—Reporting Segments.
Year Ended | ||||||
December 31, | Segment to which | |||||
(in thousands) |
| 2019 |
| revenues relate |
| |
Revenue from contracts with customers | ||||||
Type of service | ||||||
Gathering—low pressure | $ | | Gathering and Processing(1) | |||
Gathering—high pressure | | Gathering and Processing(1) | ||||
Compression | | Gathering and Processing(1) | ||||
Fresh water delivery | | Water Handling | ||||
Wastewater treatment | | Water Handling | ||||
Other fluid handling | | Water Handling | ||||
Amortization of customer relationships(2) | ( | Gathering and Processing | ||||
Amortization of customer relationships(2) | ( | Water Handling | ||||
Total | $ | | ||||
Type of contract | ||||||
Per Unit Fixed Fee | $ | | Gathering and Processing(1) | |||
Per Unit Fixed Fee | | Water Handling | ||||
Cost plus 3% | | Water Handling | ||||
Cost of service fee | | Water Handling | ||||
Amortization of customer relationships(2) | ( | Gathering and Processing | ||||
Amortization of customer relationships(2) | ( | Water Handling | ||||
Total | $ | | ||||
| (1) | Revenue related to the gathering and processing segment is classified as lease income related to the gathering system. |
| (2) | Fair value of customer contracts acquired as part of the Transactions discussed in Note 3—Business Combination. |
(c) | Transaction Price Allocated to Remaining Performance Obligations |
The majority of the Company’s service contracts have a term greater than one year. As such, the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s service contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The remainder of our service contracts, which relate to contracts with third parties, are short-term in nature with a contract term of one year or less. Accordingly, the Company is exempt from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of
(d) | Contract Balances |
Under the Company’s service contracts, the Company invoices customers after its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s service contracts do not give rise to contract assets or liabilities. At December 31, 2019, the Company’s receivables with customers were $
F-21
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(8) Property and Equipment
The Company’s investment in property and equipment for the period presented is summarized in the following table. AMGP had property and equipment at December 31, 2018.
Estimated | December 31, | |||||
(in thousands) |
| useful lives |
| 2019 |
| |
Land | n/a | $ | | |||
Gathering systems and facilities | - | | ||||
Fresh water permanent buried pipelines and equipment | - | | ||||
Fresh water surface pipelines and equipment | - | | ||||
Landfill | n/a(2) | | ||||
Heavy trucks and equipment | - | | ||||
Above ground storage tanks | - | | ||||
Construction-in-progress | n/a | | ||||
Total property and equipment | | |||||
Less accumulated depreciation | ( | |||||
Property and equipment, net | $ | | ||||
| (1) | Gathering systems and facilities are recognized as a single-leased asset with |
| (2) | Amortization of landfill costs is recorded over the life of the landfill on a units-of-consumption basis. |
(9) Income Taxes
For the years ended December 31, 2017, 2018, and 2019, income tax expense consisted of the following:
Year Ended December 31, | ||||||||||
(in thousands) |
| 2017 |
| 2018 |
| 2019 |
| |||
Current income tax expense (benefit) | $ | | | ( | ||||||
Deferred income tax expense (benefit) | — | ( | ( | |||||||
Total income tax expense (benefit) | $ | | | ( | ||||||
Income tax expense differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of
Year Ended December 31, | ||||||||||
(in thousands) |
| 2017 |
| 2018 |
| 2019 |
| |||
Federal income tax expense (benefit) | $ | | | ( | ||||||
State income tax expense (benefit), net of federal benefit | | | ( | |||||||
Non-deductible equity-based compensation | | | | |||||||
Non-deductible IPO expenses | | | — | |||||||
Charitable contributions | — | — | ( | |||||||
Other | | ( | ( | |||||||
Total income tax expense (benefit) | $ | | | ( | ||||||
F-22
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
Deferred income taxes reflect the impact of temporary differences between assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets as follows:
Year Ended December 31, | |||||||
(in thousands) |
| 2018 | 2019 |
| |||
Deferred tax assets: | |||||||
Net operating loss carryforwards | $ | — | | ||||
Investment in Antero Midstream Partners | — | | |||||
Transaction costs | | | |||||
Equity-based compensation | — | | |||||
Charitable contributions | — | | |||||
Total deferred tax assets | | | |||||
Valuation allowance | — | — | |||||
Net deferred tax assets | | | |||||
Deferred tax liabilities: | |||||||
Net deferred tax liabilities | — | — | |||||
Net deferred tax assets (liabilities) | $ | | | ||||
As of December 31, 2019, the Company has a deferred tax asset in its Investment in Antero Midstream Partners of $
In assessing the realizability of all of the deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the Company’s temporary differences become deductible. Management considers projected future taxable income and tax planning strategies in making this assessment. Based upon the projections of future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will realize the benefits of these deductible differences and thus has not recorded a valuation allowance.
(10) Long-term Debt
On May 9, 2018, AMGP entered into a credit facility (the “AMGP Credit Facility”) with a bank, which provided for a line of credit of up to $
AMGP had
(in thousands) | December 31, 2019 | |||
Credit Facility (a) | $ | | ||
| ||||
| ||||
| ||||
Net unamortized debt issuance costs | ( | |||
Total long-term debt | $ | | ||
F-23
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(a) | Antero Midstream Partners Revolving Credit Facility |
Antero Midstream Partners, an indirect, wholly owned subsidiary of Antero Midstream Corporation, as borrower (the “Borrower”), has a senior secured revolving credit facility (the “Credit Facility”) with a consortium of banks. Lender commitments under the Credit Facility currently are $
Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred and the Borrower is in pro forma compliance with the financial covenants under the Credit Facility, commences when the Borrower elects to give notice to the Administrative Agent that the Borrower has received at least one of either (i) a BBB- or better rating from Standard and Poor’s or (ii) a Baa3 or better from Moody’s (provided that the non-investment grade rating from the other rating agency is at least either Ba1 if Moody’s or BB+ if Standard & Poor’s (an “Investment Grade Rating”)). An Investment Grade Period can end at the Borrower’s election.
During a period that is not an Investment Grade Period, the Credit Facility is ratably secured by mortgages on substantially all of the Borrower’s properties, including the properties of its subsidiaries, and guarantees from its subsidiaries. During an Investment Grade Period, the liens securing the obligations thereunder shall be automatically released (subject to the provisions of the Credit Facility).
The Credit Facility contains certain covenants including restrictions on indebtedness, and requirements with respect to leverage and interest coverage ratios; provided, however, that during an Investment Grade Period, such covenants become less restrictive on the Borrower. The Credit Facility permits distributions to the holders of the Borrower’s equity interests in accordance with the cash distribution policy previously adopted by the board of directors of the general partner of the Borrower, provided that no event of default exists or would be caused thereby, and only to the extent permitted by our organizational documents. The Borrower was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2019.
Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable quarterly or, in the case of Eurodollar Rate Loans, at the end of the applicable interest period if shorter than six months. Interest is payable at a variable rate based on LIBOR or the base rate, determined by election at the time of borrowing, plus an applicable margin rate. Interest at the time of borrowing is determined with reference to (i) during any period that is not an Investment Grade Period, the Borrower’s then-current leverage ratio and (ii) during an Investment Grade Period, with reference to the rating given to the Borrower by Moody’s or Standard and Poor’s. During an Investment Grade Period, the applicable margin rates are reduced by
(b)
On September 13, 2016, Antero Midstream Partners and its wholly owned subsidiary, Finance Corp (together with Antero Midstream Partners, the “Issuers”), issued $
F-24
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(c) |
On February 25, 2019, the Issuers issued $
(d) |
On June 28, 2019, the Issuers issued $
(11) Accrued Liabilities
Accrued liabilities as of December 31, 2018 and 2019 consisted of the following items:
December 31, | |||||||
(in thousands) |
| 2018 |
| 2019 |
| ||
Capital expenditures | $ | — | | ||||
Operating expenses | — | | |||||
Interest expense | — | | |||||
Other | | | |||||
Total accrued liabilities | $ | | | ||||
F-25
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(12) Equity-Based Compensation
The Company’s general and administrative expenses 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 “AMC LTIP”) and (iii) the Exchanged B Units (as defined below). Antero Midstream Partners’ portion of the equity-based compensation expense is included in general and administrative expenses, and recorded as a credit to the applicable classes of equity. Equity-based compensation expense allocated to Antero Midstream Partners was $
Exchanged B Units
As of December 31, 2018, IDR Holdings had
Upon Closing of the Transactions, each Series B Unit, vested and unvested, was exchanged for
The Company accounted for the Series B Exchange as a share-based payment modification under ASC 718, Stock Compensation. On March 12, 2019, which is the modification date, the Company determined the estimated fair value of the unvested Series B Unit awards using a Monte Carlo simulation using various assumptions including a floor equity value of $
The Company recognized $
F-26
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
AMGP LTIP
On April 17, 2017, Antero Midstream GP LP adopted the AMGP LTIP pursuant to which certain non-employee directors of Antero Midstream GP LP’s general partner and certain officers, employees and consultants of Antero Resources were eligible to receive awards representing equity interests in Antero Midstream GP LP. For the years ended December 31, 2017, 2018 and 2019, the Company recognized expense of $
AMC LTIP
Effective March, 12, 2019, the Board of Directors of Antero Midstream Corporation (the “Board”) adopted the AMC LTIP under which awards may be granted to employees, directors and other service providers of the Company and its affiliates. The AMC LTIP provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalents, other stock-based awards, cash awards and substitute awards. The terms and conditions of the awards granted are established by the compensation committee of the Board. The Company is authorized to grant up to
Restricted Stock Unit Awards
As part of the Transactions, each of the unvested outstanding phantom units in the Antero Midstream Partners Long Term Incentive Plan (“AMP LTIP”) was assumed by Antero Midstream Corporation and converted into
Restricted stock unit (“RSU”) awards vest subject to the satisfaction of service requirements. Expense related to each RSU award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of Antero’s common stock on the date of the grant.
Summary Information for Restricted Stock Unit Awards
A summary of RSU awards activity during the year ended December 31, 2019 is as follows:
Weighted | |||||||||
Average | Aggregate | ||||||||
Number of | grant date | intrinsic value | |||||||
| units |
| fair value |
| (in thousands) |
| |||
Total AMC LTIP RSUs awarded and unvested—December 31, 2018 | — | $ | — | $ | — | ||||
AMP LTIP Awards converted into AMC LTIP Awards(1) | | $ | | ||||||
Granted | | $ | | ||||||
Vested | ( | $ | | ||||||
Forfeited | ( | $ | | ||||||
Total AMC LTIP RSUs awarded and unvested—December 31, 2019 | | $ | | $ | | ||||
(1) | Effective as of March 12, 2019, all unvested outstanding phantom units in the AMP LTIP were assumed by the Company and converted into restricted stock units under the AMC LTIP at a conversion rate of |
Intrinsic values are based on the closing price of the Company’s common shares on the referenced dates. At December 31,
F-27
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
2019, unamortized expense of $
Performance Share Unit Awards Based on Return on Invested Capital (“ROIC”)
In 2019, the Company granted performance share units (“PSUs”) to certain of its employees and executive officers, a portion of which vest based on the Company’s actual ROIC (as defined in the award agreement) over a
On December 17, 2019, the compensation committee of the Board modified the terms for the ROIC PSU agreement. Accordingly, the Company accounted for the amended agreement as a share-based payment modification under ASC 718, Stock Compensation and revalued the awards as of the modification date. Expense for the awards are recognized on a straight-line basis over the requisite service period of the entire award. For the year ended December 31, 2019, the Company recognized $
Summary Information for Performance Share Unit Awards
A summary of PSU activity for the year ended December 31, 2019 is as follows:
Weighted | ||||||
Average | ||||||
Number of | grant date | |||||
| units |
| fair value | |||
Total awarded and unvested—December 31, 2018 | — | $ | — | |||
Granted | | $ | | |||
Vested | — | $ | — | |||
Forfeited | ( | $ | | |||
Total awarded and unvested—December 31, 2019 | | $ | | |||
The grant-date fair value for the ROIC PSUs is based on the closing price of the Company’s common stock on the date of the modified terms for the ROIC PSU agreement, assuming the achievement of the performance condition.
As of December 31, 2019, there was $
F-28
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(13) Cash Distributions and Dividends
The following table details the amount of distributions and dividends paid with respect to the quarter indicated (in thousands, except per share data):
Antero | Distributions/ | ||||||||||||||
Quarter | Distributions/ | Resources | Dividends |
| |||||||||||
and Year |
| Record Date |
| Distribution Date |
| Dividends |
| Investment |
|
| per share | ||||
* | May 9, 2017 | September 13, 2017 | $ | — | | * | |||||||||
Q2 2017 | August 3, 2017 | August 23, 2017 | | — | $ | ||||||||||
Q3 2017 | November 1, 2017 | November 23, 2017 | | — | $ | ||||||||||
Total 2017 | $ | | | ||||||||||||
Q4 2017 | February 1, 2018 | February 20, 2018 | $ | | — | $ | |||||||||
Q1 2018 | May 3, 2018 | May 23, 2018 | | — | $ | ||||||||||
Q2 2018 | August 2, 2018 | August 22, 2018 | | — | $ | ||||||||||
Q3 2018 | November 2, 2018 | November 21, 2018 | | — | $ | ||||||||||
Total 2018 | $ | | — | ||||||||||||
Q4 2018 | February 1, 2019 | February 21, 2019 | $ | | — | $ | |||||||||
Q1 2019 | April 26, 2019 | May 8, 2019 | | — | $ | ||||||||||
Q1 2019 | May 15, 2019 | May 15, 2019 | | — | ** | ||||||||||
Q2 2019 | July 26, 2019 | August 7, 2019 | | — | $ | ||||||||||
Q2 2019 | August 14, 2019 | September 18, 2019 | | — | ** | ||||||||||
Q3 2019 | November 1, 2019 | November 13, 2019 | | — | $ | ||||||||||
Q3 2019 | November 14, 2019 | November 14, 2019 | | — | ** | ||||||||||
*** | December 31, 2019 | December 31, 2019 | | — | *** | ||||||||||
Total 2019 | $ | | — | ||||||||||||
* | Income relating to periods prior to May 9, 2017, the closing of our IPO, was distributed to Antero Investment prior to its liquidation. |
** | Dividends are paid in accordance with the terms of the Series A Preferred Stock as discussed in Note 14—Equity and Earnings Per Common Share. |
*** | Distributions declared on unvested Series B Units prior to the closing date of the Transactions that were paid upon the vesting date to the holders of the Exchanged B Units. |
On January 15, 2020, the Board declared a cash dividend on the shares of AMC common stock of $
The Board also declared a cash dividend of $
(14) Equity and Earnings Per Common Share
(a) Preferred Stock
The Board authorized
F-29
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
Preferred Stock are cumulative from the date of original issue and payable in cash on the 45th day following the end of each fiscal quarter, or such other dates as the Board will approve, at a rate of
(b) Weighted Average Shares Outstanding
The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented:
Year Ended December 31, | ||||||||||
(in thousands) |
| 2017 |
| 2018 |
| 2019 |
| |||
Basic weighted average number of shares outstanding | | | | |||||||
Add: Dilutive effect of restricted stock units | — | — | — | |||||||
Add: Dilutive effect of Series A preferred stock | — | — | — | |||||||
Diluted weighted average number of shares outstanding | | | | |||||||
Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share(1): | ||||||||||
Restricted stock units | — | — | | |||||||
Preferred shares | — | — | | |||||||
(1) | The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common shares, assuming dilution because the inclusion of these awards would have been anti-dilutive. |
(c) Earnings Per Common Share
Earnings per common share—basic for (i) the years ended December 31, 2017 and 2018 is computed by dividing net income attributable to AMGP by the basic weighted average number of common shares representing limited partner interest in AMGP outstanding during the period and (ii) the year ended December 31, 2019 is computed by dividing net income (loss) attributable to Antero Midstream Corporation by the basic weighted average number of shares of AMC common stock outstanding during the period. Earnings per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is anti-dilutive.
F-30
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
| Year Ended December 31, | |||||||||
(in thousands, except per share amounts) |
| 2017 | 2018 |
| 2019 |
| ||||
Net income (loss) | $ | | | ( | ||||||
Pre-IPO net income attributed to parent | | — | — | |||||||
Less net income attributable to Series B Units | ( | ( | — | |||||||
Less preferred stock dividends | — | — | ( | |||||||
Net income (loss) available to common shareholders | $ | | | ( | ||||||
Net income (loss) per share–basic and diluted | $ | | | ( | ||||||
Weighted average common shares outstanding–basic | | | | |||||||
Weighted average common shares outstanding–diluted | | | | |||||||
(15) Fair Value Measurement
Business Combination
As the Transactions were accounted for under the acquisition method of accounting, the Company estimated the fair value of assets acquired and liabilities assumed at March 12, 2019. See Note 3—Business Combination. In connection with the Transactions, the Company, among other things, issued shares of common stock valued at the closing market price of the common shares at the effective time of the Transactions, which was a Level 1 measurement.
The Company used the discounted cash flow approach, which is an income statement technique, to estimate the fair value of the customer relationships and investments in unconsolidated affiliates using a weighted-average cost of capital of
Goodwill
The Company estimated the fair value of its assets in performing its annual goodwill analysis. The Company utilized a combination of approaches to 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). The Company performed its fourth quarter quantitative analysis using a weighted-average cost of capital of
Contingent Acquisition Consideration
In connection with Antero Resources’ contribution of Antero Water and certain water handling assets to Antero Midstream Partners in September 2015 (the “Water Acquisition”), Antero Midstream Partners agreed to pay Antero Resources (a) $
F-31
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
The following table provides a reconciliation of changes in Level 3 financial liabilities measured at fair value on a recurring basis for the period shown below (in thousands):
Contingent acquisition consideration—December 31, 2018 |
| $ | — |
|
Contingent acquisition consideration assumed from Antero Midstream Partners | | |||
Accretion and change in fair value of contingent acquisition consideration | | |||
Contingent acquisition consideration—December 31, 2019 | $ | |
The Company accounts for contingent consideration in accordance with applicable accounting guidance pertaining to business combinations. Antero Midstream Partners is contractually obligated to pay Antero Resources contingent consideration in connection with the Water Acquisition. The Company updates its assumptions each reporting period based on new developments and adjusts such amounts to fair value based on revised assumptions, if applicable, until such consideration is satisfied through payment upon achievement of the specified objectives or it is eliminated upon failure to achieve the specified objectives.
As of December 31, 2019, Antero Midstream Partners had delivered more than
Senior Unsecured Notes
As of December 31, 2019 the fair value of the Company’s 2024 Notes, 2027 Notes and 2028 Notes was approximately $
Other Assets and Liabilities
The carrying values of accounts receivable and accounts payable at December 31, 2018 and 2019 approximated fair value because of their short-term nature. The carrying value of the amounts under the Credit Facility at December 31, 2018 and 2019 approximated fair value because the variable interest rates are reflective of current market conditions.
(16) Investments in Unconsolidated Affiliates
Investment in Antero Midstream Partners
Prior to the closing of the Transactions, AMGP did not consolidate Antero Midstream Partners, and AMGP’s share of Antero Midstream Partners’ earnings as a result of AMGP’s ownership of the IDRs was accounted for using the equity method of accounting. AMGP recognized distributions earned from Antero Midstream Partners as “Equity in earnings of unconsolidated affiliates” on its statement of operations in the period in which they were earned and were allocated to AMGP’s capital account. AMGP’s long-term interest in the IDRs on the balance sheet is recorded in “Investment in unconsolidated affiliates.” The ownership of the general partner interests and IDRs did not provide AMGP with any claim to the assets of AMGP other than the balance in its Antero Midstream Partners capital account. Income related to the IDRs was recognized as earned and increased AMGP’s capital account and equity investment. When these distributions were paid to AMGP, they reduced its capital account and its equity investment in Antero Midstream Partners. As a result of the Transactions, Antero Midstream Corporation assumed financial control of Antero Midstream Partners and Antero Midstream Partners is now consolidated (see Note 3—Business Combination).
Investment in Stonewall and MarkWest Joint Venture
The Company has a
F-32
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
Antero Midstream Partners has a
The Company’s net income (loss) includes its proportionate share of the net income of the Joint Venture and Stonewall. When the Company records its proportionate share of net income, it increases equity income in the consolidated statements of operations and comprehensive income and the carrying value of that investment on its balance sheet. When distributions on the Company’s proportionate share of net income are received, they are recorded as reductions to the carrying value of the investment on the balance sheet and are classified as cash inflows from operating activities in accordance with the nature of the distribution approach under ASU No. 2016-15. The Company uses the equity method of accounting to account for its investments in Stonewall and the Joint Venture because it exercises significant influence, but not control, over the entities. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as its ownership interest, representation on the applicable board of directors and participation in policy-making decisions of Stonewall and the Joint Venture.
The following table is a reconciliation of our investments in these unconsolidated affiliates:
Antero | Total Investment | ||||||||||||
Midstream | MarkWest | in Unconsolidated | |||||||||||
(in thousands) | Partners LP | Stonewall | Joint Venture | Affiliates | |||||||||
Balance at December 31, 2017 | | — | — | | |||||||||
Equity in net income of unconsolidated affiliates | | — | — | | |||||||||
Distributions from unconsolidated affiliates | ( | — | — | ( | |||||||||
Balance at December 31, 2018 | | — | — | | |||||||||
Distributions from unconsolidated affiliates | ( | — | — | ( | |||||||||
Balance at March 12, 2019 | — | — | — | — | |||||||||
Investments in unconsolidated affiliates acquired from Antero Midstream Partners | — | | | | |||||||||
Additional investments | — | — | | | |||||||||
Equity in net income of unconsolidated affiliates(1) | — | | | | |||||||||
Distributions from unconsolidated affiliates | — | ( | ( | ( | |||||||||
Balance at December 31, 2019 | $ | — | | | |
(1) | As adjusted for the amortization of the difference between the cost of the equity investments in Stonewall and the Joint Venture and the amount of the underlying equity in the net assets of Stonewall and the Joint Venture as of the date of the acquisition of Antero Midstream Partners. |
(b)Summarized Financial Information of Unconsolidated Affiliates
The following tables present summarized financial information for the Company’s investments in unconsolidated affiliates.
F-33
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
Combined Balance Sheets
December 31, | |||||||
(in thousands) |
| 2018 |
| 2019 | |||
Current assets |
| $ | |
| $ | |
|
Noncurrent assets | | | |||||
Total assets | $ | | $ | | |||
Current liabilities | $ | | $ | | |||
Noncurrent liabilities | | | |||||
Noncontrolling interest | | | |||||
Partners' capital | | | |||||
Total liabilities and partners' capital | $ | | $ | | |||
Statements of Combined Operations
Year Ended December 31, | ||||||||
(in thousands) |
| 2017 | 2018 | 2019 | ||||
Revenues |
| $ | | |
| |
| |
Operating expenses | | | | |||||
Income from operations | | | | |||||
Net income attributable to the equity method investments | | | | |||||
(17) Reporting Segments
Prior to the closing of the Transactions, AMGP had no reporting segment results. Following the completion of the Transactions, the Company’s operations, which are located in the United States, are organized into
Gathering and Processing
The gathering and processing segment includes a network of gathering pipelines and compressor stations that collect and process production from Antero Resources’ wells in West Virginia and Ohio. The gathering and processing segment also includes equity in earnings from the Company’s investments in the Joint Venture and Stonewall.
Water Handling
The Company’s water handling segment includes
These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Management evaluates the performance of the Company’s business segments based on operating income. Interest expense is primarily managed and evaluated on a consolidated basis.
F-34
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
The operating results and assets of the Company’s reportable segments were as follows for the year ended December 31, 2019 (in thousands):
| Gathering and |
| Water |
| Consolidated | ||||||||
|
| Processing |
| Handling |
| Unallocated (1) |
| Total |
| ||||
Year ended December 31, 2019 | |||||||||||||
Revenues: | |||||||||||||
Revenue–Antero Resources | $ | | | — | | ||||||||
Revenue–third-party | — | | — | | |||||||||
Amortization of customer relationships | ( | ( | — | ( | |||||||||
Total revenues | | | — | | |||||||||
Operating expenses: | |||||||||||||
Direct operating | | | — | | |||||||||
General and administrative (excluding equity-based compensation) | | | | | |||||||||
Facility idling | — | | — | | |||||||||
Equity-based compensation | | | | | |||||||||
Impairment of property and equipment | | | — | | |||||||||
Impairment of goodwill | — | | — | | |||||||||
Impairment of customer relationships | — | | — | | |||||||||
Depreciation | | | — | | |||||||||
Accretion and change in fair value of contingent acquisition consideration | — | | — | | |||||||||
Accretion of asset retirement obligations | — | | — | | |||||||||
Total expenses | | | | | |||||||||
Operating income (loss) | $ | | ( | ( | ( | ||||||||
Equity in earnings of unconsolidated affiliates | $ | | — | — | | ||||||||
Total assets | $ | | | | | ||||||||
Additions to property and equipment, net | $ | | | — | | ||||||||
(1) | Certain expenses that are not directly attributable to gathering and processing and water handling are managed and evaluated on a consolidated basis. |
F-35
ANTERO MIDSTREAM CORPORATION
Notes to Consolidated Financial Statements (Continued)
Years Ended December 31, 2017, 2018, and 2019
(18) Quarterly Financial Information (Unaudited)
The Company’s quarterly consolidated unaudited financial information for the years ended December 31, 2018 and 2019 is summarized in the table below (in thousands, except per share data):
First | Second | Third | Fourth | ||||||||||
| Quarter |
| Quarter |
| Quarter |
| Quarter |
| |||||
Year ended December 31, 2018 | |||||||||||||
Total income | $ | | | | | ||||||||
Total operating expenses | | | | | |||||||||
Net income and comprehensive income | | | | | |||||||||
Net income attributable to Series B units | ( | ( | ( | ( | |||||||||
Net income attributable to common shareholders | | | | | |||||||||
Net income per common share–basic and diluted | $ | | | | | ||||||||
Year ended December 31, 2019 | |||||||||||||
Total operating revenues | $ | | | | | ||||||||
Total operating expenses | | | | | |||||||||
Operating income (loss) | | | ( | ( | |||||||||
Net income (loss) and comprehensive income (loss) | | | ( | ( | |||||||||
Net income (loss) per common share–basic and diluted | $ | | | ( | ( | ||||||||
F-36